25162 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Parts 51, 72, 73, 74, 77, 78 and 

96 

[OAR–2003–0053; FRL–7885–9] 

RIN 2060–AL76 

Rule To Reduce Interstate Transport of 

Fine Particulate Matter and Ozone 

(Clean Air Interstate Rule); Revisions 

to Acid Rain Program; Revisions to the 

NOX SIP Call

AGENCY: Environmental Protection 

Agency (EPA).

ACTION: Final rule.

SUMMARY: In today’s action, EPA finds 

that 28 States and the District of 

Columbia contribute significantly to 

nonattainment of the national ambient 

air quality standards (NAAQS) for fine 

particles (PM2.5) and/or 8-hour ozone in 

downwind States. The EPA is requiring 

these upwind States to revise their State 

implementation plans (SIPs) to include 

control measures to reduce emissions of 

sulfur dioxide (SO2) and/or nitrogen 

oxides (NOX). Sulfur dioxide is a 

precursor to PM2.5 formation, and NOX

is a precursor to both ozone and PM2.5

formation. Reducing upwind precursor 

emissions will assist the downwind 

PM2.5 and 8-hour ozone nonattainment 

areas in achieving the NAAQS. 

Moreover, attainment will be achieved 

in a more equitable, cost-effective 

manner than if each nonattainment area 

attempted to achieve attainment by 

implementing local emissions 

reductions alone. 

Based on State obligations to address 

interstate transport of pollutants under 

section 110(a)(2)(D) of the Clean Air Act 

(CAA), EPA is specifying statewide 

emissions reduction requirements for 

SO2 and NOX. The EPA is specifying 

that the emissions reductions be 

implemented in two phases. The first 

phase of NOX reductions starts in 2009 

(covering 2009–2014) and the first phase 

of SO2 reductions starts in 2010 

(covering 2010–2014); the second phase 

of reductions for both NOX and SO2

starts in 2015 (covering 2015 and 

thereafter). The required emissions 

reductions requirements are based on 

controls that are known to be highly 

cost effective for electric generating 

units (EGUs). 

Today’s action also includes model 

rules for multi-State cap and trade 

programs for annual SO2 and NOX

emissions for PM2.5 and seasonal NOX

emissions for ozone that States can 

choose to adopt to meet the required 

emissions reductions in a flexible and 

cost-effective manner. 

Today’s action also includes revisions 

to the Acid Rain Program regulations 

under title IV of the CAA, particularly 

the regulatory provisions governing the 

SO2 cap and trade program. The 

revisions are made because they 

streamline the operation of the Acid 

Rain SO2 cap and trade program and/or 

facilitate the interaction of that cap and 

trade program with the model SO2 cap 

and trade program included in today’s 

action. In addition, today’s action 

provides for the NOX SIP Call cap and 

trade program to be replaced by the 

CAIR ozone-season NOX trading 

program.

DATES: The effective date of today’s 

action, except for the revisions to 40 

CFR parts 72, 73, 74, and 77 of the Acid 

Rain Program regulations, is July 11, 

2005. States must submit to EPA for 

approval enforceable plans for 

complying with the requirements of this 

rule by September 11, 2006. The 

effective date for today’s revisions to 40 

CFR parts 72, 73, 74, and 77 of the Acid 

Rain Program regulations is July 1, 2006.

ADDRESSES: The EPA has established a 

docket for this action under Docket ID 

No. OAR–2003–0053. All documents in 

the docket are listed in the EDOCKET 

index at http://www.epa.gov/edocket. 

Although listed in the index, some 

information is not publicly available, 

i.e., Confidential Business Information 

(CBI) or other information whose 

disclosure is restricted by statute. 

Certain other material, such as 

copyrighted material, is not placed on 

the Internet and will be publicly 

available only in hard copy form. 

Publicly available docket materials are 

available either electronically in 

EDOCKET or in hard copy at the EPA 

Docket Center, EPA West, Room B102, 

1301 Constitution Avenue, NW., 

Washington, DC. The Public Reading 

Room is open from 8:30 a.m. to 4:30 

p.m., Monday through Friday, excluding 

legal holidays. The telephone number 

for the Public Reading Room is (202) 

566–1744, and the telephone number for 

the Air Docket is (202) 566–1742.

FOR FURTHER INFORMATION CONTACT: For 

general questions concerning today’s 

action, please contact Carla Oldham, 

U.S. EPA, Office of Air Quality Planning 

and Standards, Air Quality Strategies 

and Standards Division, Mail Code 

C539–02, Research Triangle Park, NC, 

27711, telephone (919) 541–3347, e-mail 

at oldham.carla@epa.gov. For legal 

questions, please contact Sonja 

Petersen, U.S. EPA, Office of General 

Counsel, Mail Code 2344A, 1200 

Pennsylvania Avenue, NW., 

Washington, DC, 20460, telephone (202) 

564–4079, e-mail at 

petersen.sonja@epa.gov. For questions 

regarding air quality analyses, please 

contact Norm Possiel, U.S. EPA, Office 

of Air Quality Planning and Standards, 

Emissions Monitoring and Analysis 

Division, Mail Code D243–01, Research 

Triangle Park, NC, 27711, telephone 

(919) 541–5692, e-mail at 

possiel.norm@epa.gov. For questions 

regarding the EGU cost analyses, 

emissions inventories, and budgets, 

please contact Roman Kramarchuk, U.S. 

EPA, Office of Atmospheric Programs, 

Clean Air Markets Division, Mail Code 

6204J, 1200 Pennsylvania Avenue, NW., 

Washington, DC, 20460, telephone (202) 

343–9089, e-mail at 

kramarchuk.roman@epa.gov. For 

questions regarding statewide emissions 

inventories, please contact Ron Ryan, 

U.S. EPA, Office of Air Quality Planning 

and Standards, Emissions Monitoring 

and Analysis Division, Mail Code D205–

01, Research Triangle Park, NC, 27711, 

telephone (919) 541–4330, e-mail at 

ryan.ron@epa.gov. For questions 

regarding emissions reporting 

requirements, please contact Bill 

Kuykendal, U.S. EPA, Office of Air 

Quality Planning and Standards, 

Emissions Monitoring and Analysis 

Division, Mail Code D205–01, Research 

Triangle Park, NC, 27711, telephone 

(919) 541–5372, e-mail at 

kuykendal.bill@epa.gov. For questions 

regarding the model cap and trade 

programs, please contact Sam Waltzer, 

U.S. EPA, Office of Atmospheric 

Programs, Clean Air Markets Division, 

Mail Code 6204J, 1200 Pennsylvania 

Avenue, NW., Washington, DC, 20460, 

telephone (202) 343–9175, e-mail at 

waltzer.sam@epa.gov. For questions 

regarding analyses required by statutes 

and executive orders, please contact 

Linda Chappell, U.S. EPA, Office of Air 

Quality Planning and Standards, Air 

Quality Strategies and Standards 

Division, Mail Code C339–01, Research 

Triangle Park, NC, 27711, telephone 

(919) 541–2864, e-mail at 

chappell.linda@epa.gov. For questions 

regarding the Acid Rain Program 

regulation revisions, please contact 

Dwight C. Alpern, U.S. EPA, Office of 

Atmospheric Programs, Clean Air 

Markets Division, Mail Code 6204J, 

1200 Pennsylvania Avenue, NW., 

Washington, DC, 20460, telephone (202) 

343–9151, e-mail at 

alpern.dwight@epa.gov.

SUPPLEMENTARY INFORMATION: 

Regulated Entities 

Except for the revisions to the Acid 

Rain Program regulations, this action 

does not directly regulate emissions 

sources. Instead, it requires States to 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25163

revise their SIPs to include control 

measures to reduce emissions of NOX

and SO2. The emissions reductions 

requirement assigned to the States are 

based on controls that are known to be 

highly cost effective for EGUs. 

Entities potentially regulated by the 

revisions to the Acid Rain Program 

regulations in this action are fossil-fuelfired boilers, turbines, and internal 

combustion engines, including those 

that serve generators producing 

electricity, generate steam, or cogenerate 

electricity and steam. Regulated 

categories and entities include:

Category 1 NAICS code Examples of potentially regulated entities 

Industry ...................... 221112 and others Electric service providers, boilers, turbines, and internal combustion engines from a wide range of 

industries. 

Federal government .. 221122 Fossil fuel-fired electric utility steam generating units owned by the Federal government. 

State/local/Tribal government.221122

921150

Fossil fuel-fired electric utility steam generating units owned by municipalities. Fossil fuel-fired electric utility steam generating units in Indian Country. 

1 North American Industry Classification System. 

2Federal, State, or local government-owned and operated establishments are classified according to the activity in which they are engaged. 

This table is not intended to be 

exhaustive, but rather provides a guide 

for readers regarding entities likely to be 

regulated by the revisions to the Acid 

Rain Program regulations in this action. 

This table lists the types of entities that 

EPA is aware could potentially be 

regulated. Other types of entities not 

listed in the table could also be 

regulated. To determine whether your 

facility is regulated, you should 

carefully examine the applicability 

criteria in 40 CFR 72.6 and 74.2 and the 

exemptions in 40 CFR 72.7 and 72.8. If 

you have questions regarding the 

applicability of the revisions to the Acid 

Rain Program regulations in this action 

to a particular entity, consult persons 

listed in the preceding FOR FURTHER

INFORMATION CONTACT section. 

Web Site for Rulemaking Information 

The EPA has also established a Web 

site for this rulemaking at http://

www.epa.gov/cleanairinterstaterule/ or 

http://www.epa.gov/cair/ (formerly

at http://www.epa.gov/

interstateairquality/) which includes the 

rulemaking actions and certain other 

related information that the public may 

find useful.

Outline 

I. Overview 

A. What Are the Central Requirements of 

this Rule? 

B. Why Is EPA Taking this Action? 

1. Policy Rationale for Addressing 

Transported Pollution Contributing to 

PM2.5 and Ozone Problems 

a. The PM2.5 Problem 

b. The 8-hour Ozone Problem 

c. Other Environmental Effects Associated 

with SO2 and NOX Emissions 

2. The CAA Requires States to Act as Good 

Neighbors by Limiting Downwind 

Impacts 

3. Today’s Rule Will Improve Air Quality 

C. What was the Process for Developing 

this Rule? 

D. What Are the Major Changes Between 

the Proposals and the Final Rule? 

II. The EPA’s Analytical Approach 

A. How Did EPA Interpret the Clean Air 

Act’s Pollution Transport Provisions in 

the NOX SIP Call? 

1. Clean Air Act Requirements 

2. The NOX SIP Call Rulemaking 

a. Analytical Approach of NOX SIP Call 

b. Regulatory Requirements 

c. SIP Submittal and Implementation 

Requirements 

3. Michigan v. EPA Court Case 

4. Implementation of the NOX SIP Call

B. How Does EPA Interpret the Clean Air 

Act’s Pollution Transport Provisions in 

Today’s Rule 

1. CAIR Analytical Approach 

a. Nature of Nonattainment Problem and 

Overview of Today’s Approach 

b. Air Quality Factor 

c. Cost Factor 

d. Other Factors 

e. Regulatory Requirements 

f. SIP Submittal and Implementation 

Requirements 

2. What Did Commenters Say and What Is 

EPA’s Response? 

a. Aspects of Contribute-Significantly Test 

III. Why Does This Rule Focus on SO2 and 

NOX, and How Were Significant 

Downwind Impacts Determined? 

A. What Is the Basis for EPA’s Decision to 

Require Reductions in Upwind 

Emissions of SO2 and NOX to Address 

PM2.5 related transport? 

1. How Did EPA determine which 

pollutants were necessary to control to 

address interstate transport for PM2.5? 

a. What Did EPA propose regarding this 

issue in the NPR? 

b. How Does EPA address public 

comments on its proposal to address SO2

and NOX emissions and not other 

pollutants? 

c. What Is EPA’s Final Determination? 

2. What Is the role for local emissions 

reduction strategies? 

a. Summary of analyses and conclusions in 

the proposal 

b. Summary and Response to Public 

Comments 

B. What Is the Basis for EPA’s Decision to 

Require Reductions in Upwind 

Emissions of NOX to Address OzoneRelated Transport? 

1. How Did EPA Determine Which 

Pollutants Were Necessary to Control to 

Address Interstate Transport for Ozone? 

2. How Did EPA Determine That 

Reductions in Interstate Transport, as 

Well as Reductions in Local Emissions, 

Are Warranted to Help Ozone 

Nonattainment Areas to Meet the 8-hour 

Ozone Standard? 

a. What Did EPA Say in its Proposal 

Notice? 

b. What Did Commenters Say? 

C. Comments on Excluding Future Case 

Measures from the Emissions Baselines 

Used to Estimate Downwind Ambient 

Contribution 

D. What Criteria Should Be Used to 

Determine Which States 

1. What Is the Appropriate Metric for 

Assessing Downwind PM2.5

Contribution? 

a. Notice of Proposed Rulemaking 

b. Comments and EPA’s Responses 

c. Today’s Action 

2. What Is the Level of the PM2.5

Contribution Threshold? 

a. Notice of Proposed Rulemaking 

b. Comments and EPA’s Responses 

c. Today’s Action 

E. What Criteria Should Be Used to 

Determine Which States are Subject to 

this Rule Because They Contribute to 

Ozone Nonattainment? 

1. Notice of Proposed Rulemaking 

2. Comments and EPA Responses 

3. Today’s Action 

F. Issues Related to Timing of the CAIR 

Controls 

1. Overview 

2. By Design, the CAIR Cap and Trade 

Program Will Achieve Significant 

Emissions Reductions Prior to the Cap 

Deadlines 

3. Additional Justification for the SO2 and 

NOX Annual Controls 

4. Additional Justification for Ozone NOX

Requirements 

IV. What Amounts of SO2 and NOX

Emissions Did EPA Determine Should Be 

Reduced? 

A. What Methodology Did EPA Use to 

Determine the Amounts of SO2 and NOX

Emissions That Must Be Eliminated? 

1. The EPA’s Cost Modeling Methodology 

2. The EPA’s Proposed Methodology to 

Determine Amounts of Emissions that 

Must be Eliminated 

a. Overview of EPA Proposal for the Levels 

of Reductions and Resulting Caps, and 

their Timing 

25164 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

b. Regulatory History: NOX SIP Call 

c. Proposed Criteria for Emissions 

Reduction Requirements 

3. What Are the Most Significant 

Comments that EPA Received about its 

Proposed Methodology for Determining 

the Amounts of SO2 and NOX Emissions 

that Must Be Eliminated, and What Are 

EPA’s Responses? 

4. The EPA’s Evaluation of Highly CostEffective SO2 and NOX Emissions 

Reductions Based on Controlling EGUs 

a. SO2 Emissions Reductions Requirements 

b. NOX Emissions Reductions 

Requirements 

B. What Other Sources Did EPA Consider 

when Determining Emission Reduction 

Requirements? 

1. Potential Sources of Highly CostEffective Emissions Reductions 

a. Mobile and Area Sources 

b. Non-EGU Boilers and Turbines

c. Other Non-EGU Stationary Sources 

C. Schedule for Implementing SO2 and 

NOX Emissions Reduction Requirements 

for PM2.5 and Ozone 

1. Overview 

2. Engineering Factors Affecting Timing for 

Control Retrofits 

a. NPR 

b. Comments 

c. Responses 

3. Assure Financial Stability 

D. Control Requirements in Today’s Final 

Rule 

1. Criteria Used to Determine Final Control 

Requirements 

2. Final Control Requirements 

V. Determination of State Emissions Budgets 

A. What Is the Approach for Setting Stateby-State Annual Emissions Reductions 

Requirements and EGU Budgets? 

1. SO2 Emissions Budgets 

a. State Annual SO2 Emission Budget 

Methodology 

b. Final SO2 State Emission Budget 

Methodology 

c. Use of SO2 budgets 

2. NOX Annual Emissions Budgets 

a. Overview 

b. State Annual NOX Emissions Budget 

Methodology 

c. Final Annual State NOX Emission 

Budgets 

d. Use of Annual NOX Budgets 

e. NOX Compliance Supplement Pool 

B. What Is the Approach for Setting Stateby-State Emissions Reductions 

Requirements and EGU Budgets for 

States with NOX Ozone Season 

Reduction Requirements? 

1. States Subject to Ozone-season 

Requirements 

VI. Air Quality Modeling Approach and 

Results 

A. What Air Quality Modeling Platform 

Did EPA Use? 

1. Air Quality Models 

a. The PM2.5 Air Quality Model and 

Evaluation 

b. Ozone Air Quality Modeling Platform 

and Model Evaluation 

c. Model Grid Cell Configuration 

2. Emissions Inventory Data 

3. Meteorological Data 

B. How Did EPA Project Future 

Nonattainment for PM2.5 and 8-Hour 

Ozone? 

1. Projection of Future PM2.5

Nonattainment 

a. Methodology for Projecting Future PM2.5

Nonattainment 

b. Projected 2010 and 2015 Base Case PM2.5

Nonattainment Counties 

2. Projection of Future 8-Hour Ozone 

Nonattainment 

a. Methodology for Projecting Future 8-

Hour Ozone Nonattainment 

b. Projected 2010 and 2015 Base Case 8-

Hour Ozone Nonattainment Counties 

C. How did EPA Assess Interstate 

Contributions to Nonattainment? 

1. PM2.5 Contribution Modeling Approach 

2. 8-Hour Ozone Contribution Modeling 

Approach 

D. What Are the Estimated Interstate 

Contributions to PM2.5 and 8-Hour 

Ozone Nonattainment? 

1. Results of PM2.5 Contribution Modeling 

2. Results of 8-Hour Ozone Contribution 

Modeling 

E. What Are the Estimated Air Quality 

Impacts of the Final Rule? 

1. Estimated Impacts on PM2.5

Concentrations and Attainment 

2. Estimated Impacts on 8-Hour Ozone 

Concentrations and Attainment 

F. What Are the Estimated Visibility 

Impacts of the Final Rule? 

1. Methods for Calculating Projected 

Visibility in Class I Areas 

2. Visibility Improvements in Class I Areas 

VII. SIP Criteria and Emissions Reporting 

Requirements 

A. What Criteria Will EPA Use to Evaluate 

the Approvability of a Transport SIP? 

1. Introduction 

2. Requirements for States Choosing to 

Control EGUs 

a. Emissions Caps and Monitoring 

b. Using the Model Trading Rules 

c. Using a Mechanism Other than the 

Model Trading Rules 

d. Retirement of Excess Title IV 

Allowances 

3. Requirements for States Choosing to 

Control Sources Other than EGUs 

a. Overview of Requirements 

b. Eligibility of Non-EGU Reductions 

c. Emissions Controls and Monitoring 

d. Emissions Inventories and 

Demonstrating Reductions 

4. Controls on Non-EGUs Only 

5. Use of Banked Allowances and the 

Compliance Supplement Pool 

B. State Implementation Plan Schedules 

1. State Implementation Plan Submission 

Schedule 

a. The EPA’s Authority to Require Section 

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

with the Schedule of Section 110(a)(1) 

b. The EPA’s Authority to Require Section 

110(a)(2)(D) Submissions Prior to Formal 

Designation of Nonattainment Areas 

under Section 107

c. The EPA’s Authority to Require Section 

110(a)(2)(D) Submissions Prior to State 

Submission of Nonattainment Area Plans 

Under Section 172

d. The EPA’s Authority to Require Section 

110(a)(2)(D) Submissions Prior to 

Completion of the Next Review of the 

PM2.5 and 8-hour Ozone NAAQS 

e. The EPA’s Authority to Require States to 

Make Section 110(a)(2)(D) Submissions 

within 18 Months of this Final Rule 

C. What Happens If a State Fails to Submit 

a Transport SIP or EPA Disapproves the 

Submitted SIP? 

1. Under What Circumstances Is EPA 

Required to Promulgate a FIP? 

2. What Are the Completeness Criteria? 

3. When Would EPA Promulgate the CAIR 

Transport FIP? 

D. What Are the Emissions Reporting 

Requirements for States? 

1. Purpose and Authority 

2. Pre-existing Emission Reporting 

Requirements 

3. Summary of the Proposed Emissions 

Reporting Requirements 

4. Summary of Comments Received and 

EPA’s Responses 

5. Summary of the Emissions Reporting 

Requirements 

VIII. Model NOX and SO2 Cap and Trade 

Programs 

A. What Is the Overall Structure of the 

Model NOX and SO2 Cap and Trade 

Programs? 

B. What Is the Process for States to Adopt 

the Model Cap and Trade Programs and 

How Will It Interact with Existing 

Programs? 

1. Adopting the Model Cap and Trade 

Programs 

2. Flexibility in Adopting Model Cap and 

Trade Rules 

C. What Sources Are Affected under the 

Model Cap and Trade Rules? 

1. 25 MW Cut-off 

2. Definition of Fossil Fuel-fired 

3. Exemption for Cogeneration Units 

a. Efficiency Standard for Cogeneration 

Units 

b. One-third Potential Electric Output 

Capacity 

c. Clarifying ‘‘For Sale’’

d. Multiple Cogeneration Units 

D. How Are Emission Allowances 

Allocated to Sources? 

1. Allocation of NOX and SO2 Allowances 

a. Required Aspects of a State NOX

Allocation Approach 

b. Flexibility and Options for a State NOX

Allowance Allocations Approach

E. What Mechanisms Affect the Trading of 

Emission Allowances? 

1. Banking 

a. The CAIR NPR and SNPR Proposal for 

the Model Rules and Input from 

Commenters 

b. The Final CAIR Model Rules and 

Banking 

2. Interpollutant Trading Mechanisms 

a. The CAIR NPR Proposal for the Model 

Rules and Input from Commenters 

b. Interpollutant Trading and the Final 

CAIR Model Rules 

F. Are There Incentives for Early 

Reductions? 

1. Incentives for Early SO2 Reductions 

a. The CAIR NPR and SNPR Proposal for 

the Model Rules and Input from 

Commenters 

b. SO2 Early Reduction Incentives in the 

Final CAIR Model Rules 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25165

1 ‘‘Rule to Reduce Interstate Transport of Fine 

Particulate Matter and Ozone (Interstate Air Quality 

Rule); Proposed Rule,’’ (69 FR 4566, January 30, 

2004) (NPR or January Proposal); ‘‘Supplemental 

Proposal for the Rule to Reduce Interstate Transport 

of Fine Particulate Matter and Ozone (Clean Air 

Interstate Rule); Proposed Rule,’’ (69 FR 32684, June 

10, 2004) (SNPR or Supplemental Proposal).

2These data are from EPA’s most recent IPM 

modeling reflecting the final CAIR of today’s notice. 

These results may differ slightly from those 

appearing in elsewhere in this preamble and the 

RIA, which were largely based upon a model run 

that included Arkansas, Delaware, and New Jersey 

in the annual CAIR requirements and also did not 

apply an ozone season cap on any States (the 

modeling was completed before EPA had 

determined the final scope of CAIR because of the 

length of time necessary to perform air quality 

modeling).

3These values represent reductions from future 

projected emissions without CAIR. In 2010 CAIR 

will reduce SO2 by 4.3 million tons from 2003 

levels and in 2015 it will reduce SO2 emissions by 

5.4 million tons from 2003 levels. In 2009, CAIR 

will reduce NOX levels by 1.7 million tons from 

2003 levels and in 2015 it will reduce NOX levels 

by 2.0 million tons from 2003 levels.

4 It should be noted that the banking provisions 

of the cap and trade program which encourage 

sources to make significant reductions before 2010 

also allow sources to operate above these cap levels 

until all of the banked allowances are used, 

therefore EPA does not project that these caps will 

be met in 2010 or 2015.

2. Incentives for Early NOX Reductions 

a. The CAIR NPR and SNPR Proposal for 

the Model Rules and Input from 

Commenters 

b. NOX Early Reduction Incentives in the 

Final CAIR Model Rules 

G. Are There Individual Unit ‘‘Opt-In’’

Provisions? 

1. Applicability 

2. Allowing Single Pollutant 

3. Allocation Method for Opt-Ins 

4. Alternative Opt-In Approach 

5. Opting Out 

6. Regulatory Relief for Opt in Units 

H. What Are the Source-Level Emissions 

Monitoring and Reporting Requirements? 

I. What is Different Between CAIR’s 

Annual and Seasonal NOX Model Cap 

and Trade Rules? 

J. Are There Additional Changes to 

Proposed Model Cap and Trade Rules 

Reflected in the Regulatory Language? 

IX. Interactions with Other Clean Air Act 

Requirements 

A. How Does this Rule Interact with the 

NOX SIP Call? 

B. How Does this Rule Interact with the 

Acid Rain Program? 

1. Legal Authority for Using Title IV 

Allowances in CAIR Model SO2 Cap and 

trade Program 

2. Legal Authority for Requiring Retirement 

of Excess Title IV Allowances if State 

Does Not Use CAIR Model SO2 Cap and 

trade Program 

3. Revisions to Acid Rain Regulations 

C. How Does the Rule Interact With the 

Regional Haze Program? 

1. How Does this Rule Relate to 

Requirements for Best Available Retrofit 

Technology (Bart) under the Visibility 

Provisions of the CAA? 

a. Supplemental Notice of Proposed 

Rulemaking 

b. Comments and EPA’s Responses 

c. Today’s Action 

2. What Improvements did EPA Make to 

the BART Versus CAIR Modeling, and 

What are the New Results? 

a. Supplemental Notice of Proposed 

Rulemaking 

b. Comments and EPA Responses 

c. Today’s Action 

D. How Will EPA Handle State Petitions 

Under Section 126 of the CAA? 

E. Will Sources Subject to CAIR Also Be 

Subject To New Source Review? 

X. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

1. What Economic Analyses Were 

Conducted for the Rulemaking? 

2. What Are the Benefits and Costs of this 

Rule? 

a. Control Scenario 

b. Cost Analysis and Economic Impacts 

c. Human Health Benefit Analysis 

d. Quantified and Monetized Welfare 

Benefits 

3. How Do the Benefits Compare to the 

Costs of This Final Rule? 

4. What are the Unquantified and 

Unmonetized Benefits of CAIR 

Emissions Reductions? 

a. What are the Benefits of Reduced 

Deposition of Sulfur and Nitrogen to 

Aquatic, Forest, and Coastal Ecosystems? 

b. Are There Health or Welfare Disbenefits 

of CAIR That Have Not Been Quantified? 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act 

D. Unfunded Mandates Reform Act 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation 

and Coordination with Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children from Environmental Health and 

Safety Risks 

H. Executive Order 13211: Actions that 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer 

Advancement Act 

J. Executive Order 12898: Federal Actions 

to Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

K. Congressional Review Act 

L. Judicial Review 

CFR Revisions and Additions (Rule Text) 

Part 51

Part 72

Part 73

Part 74

Part 77

Part 78

Part 96

I. Overview 

By notice of proposed rulemaking 

dated January 30, 2004 and by notice of 

supplemental rulemaking dated June 10, 

2004, EPA proposed to find that certain 

States must reduce emissions of SO2

and/or NOX because those emissions 

contribute significantly to downwind 

areas in other States that are not meeting 

the annual PM2.5 NAAQS or the 8-hour 

ozone NAAQS.1 Today, EPA takes final 

action requiring 28 States and the 

District of Columbia to adopt and 

submit revisions to their State 

implementation plans (SIPs), under the 

requirements of CAA section 

110(a)(2)(D), that would eliminate 

specified amounts of SO2 and/or NOX

emissions.

Each State may independently 

determine which emissions sources to 

subject to controls, and which control 

measures to adopt. The EPA’s analysis 

indicates that emissions reductions from 

electric generating units (EGUs) are 

highly cost effective, and EPA 

encourages States to adopt controls for 

EGUs. States that do so must place an 

enforceable limit, or cap, on EGU 

emissions (see section VII for 

discussion). The EPA has calculated the 

amount of each State’s EGU emissions 

cap, or budget, based on reductions that 

EPA has determined are highly cost 

effective. States may allow their EGUs to 

participate in an EPA-administered cap 

and trade program as a way to reduce 

the cost of compliance, and to provide 

compliance flexibility. The cap and 

trade programs are described in more 

detail in section VIII. 

The EPA estimates that today’s action 

will reduce SO2 emissions by 3.5 

million tons 2 in 2010 and by 3.8 million 

tons in 2015; and would reduce annual 

NOX emissions by 1.2 million tons in 

2009 and by 1.5 million tons in 2015.2

(These numbers are for the 23 States and 

the District of Columbia that are affected 

by the annual SO2 and NOX

requirements of CAIR.) If all the affected 

States choose to achieve these 

reductions through EGU controls, then 

EGU SO2 emissions in the affected 

States would be capped at 3.6 million 

tons in 2010 and 2.5 million tons in 

20154; and EGU annual NOX emissions 

would be capped at 1.5 million tons in 

2009 and 1.3 million tons in 2015. The 

EPA estimates that the required SO2 and 

NOX emissions reductions would, by 

themselves, bring into attainment 52 of 

the 79 counties that are otherwise 

projected to be in nonattainment for 

PM2.5 in 2010, and 57 of the 74 counties 

that are otherwise projected to be in 

nonattainment for PM2.5 in 2015. The 

EPA further estimates that the required 

NOX emissions reductions would, by 

themselves, bring into attainment 3 of 

the 40 counties that are otherwise 

projected to be in nonattainment for 8-

hour ozone in 2010, and 6 of the 22 

counties that are projected to be in 

nonattainment for 8-hour ozone in 2015. 

In addition, today’s rule will improve 

PM2.5 and 8-hour ozone air quality in 

the areas that would remain 

25166 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

5Benefit and cost estimates reflect annual SO2

and NOX controls for Arkansas that are not a part 

of the final CAIR program. For this reason, these 

estimates are slightly overstated.

6Technical support document: ‘‘Regional and 

State SO2 and NOX Emissions Budgets’’ is included 

in the docket. 

Technical support document: ‘‘Air Quality 

Modeling’’ is included in the docket.

7 ‘‘Response to Significant Comments on the 

Proposed Clean Air Interstate Rule’’ is included in 

the docket.

nonattainment for those two NAAQS 

after implementation of today’s rule. 

Because of today’s rule, the States with 

those remaining nonattainment areas 

will find it less burdensome and less 

expensive to reach attainment by 

adopting additional local controls. The 

Clean Air Interstate Rule (CAIR) will 

also reduce PM2.5 and 8-hour ozone 

levels in attainment areas, providing 

significant health and environmental 

benefits in all areas of the eastern US.

The EPA’s CAIR and the previously 

promulgated NOX SIP Call reflect EPA’s 

determination that the required SO2 and 

NOX reductions are sufficient to 

eliminate upwind States’ significant 

contribution to downwind 

nonattainment. These programs are not 

designed to eliminate all contributions 

to transport, but rather to balance the 

burden for achieving attainment 

between regional-scale and local-scale 

control programs. 

The EPA conducted a regulatory 

impact analysis (RIA), entitled 

‘‘Regulatory Impact Analysis for the 

Final Clean Air Interstate Rule (March 

2005)’’ that estimates the annual private 

compliance costs (1999$) of $2.4 billion 

for 2010 and $3.6 billion for 2015, if all 

States make the required emissions 

reductions through the power industry. 

Additionally, the RIA includes a 

benefit-cost analysis demonstrating that 

substantial net economic benefits to 

society will be achieved from the 

emissions reductions required in this 

rulemaking. For determination of net 

benefits, the above private costs were 

converted to social costs that are lower 

since transfer payments, such as taxes, 

are removed from the estimates. The 

EPA analysis shows that today’s action 

inclusive of the concurrent New Jersey 

and Delaware proposal will generate 

annual net benefits of approximately 

$71.4 or $60.4 billion in 2010 and $98.5 

or $83.2 billion in 2015.5 These 

alternate net benefit estimates reflect 

differing assumptions about the social 

discount rate used to estimate the 

benefits and costs of the rule. The lower 

estimates reflect a discount rate of 7 

percent and the higher estimates a 

discount rate of 3 percent. In 2015, the 

total annual quantified benefits are $101 

or $86.3 billion and the annual social 

costs are $2.6 or $3.1 billion—benefits 

outweigh costs in 2015 by a ratio of 39 

to 1 or 28 to 1 (3 percent and 7 percent 

discount rates, respectively). These 

estimates do not include the value of 

benefits or costs that we cannot 

monetize.

In 2015, we estimate that PM-related 

annual benefits include approximately 

17,000 fewer premature fatalities, 8,700 

fewer cases of chronic bronchitis, 

22,000 fewer non-fatal heart attacks, 

10,500 fewer hospitalization admissions 

(for respiratory and cardiovascular 

disease combined) and result in 

significant reductions in days of 

restricted activity due to respiratory 

illness (with an estimate of 9.9 million 

fewer minor restricted activity days) and 

approximately 1,700,000 fewer work 

loss days. We also estimate substantial 

health improvements for children from 

reduced upper and lower respiratory 

illness, acute bronchitis, and asthma 

attacks. 

Ozone health-related benefits are 

expected to occur during the summer 

ozone season (usually ranging from May 

to September in the Eastern U.S.). Based 

upon modeling for 2015, annual ozonerelated health benefits are expected to 

include 2,800 fewer hospital admissions 

for respiratory illnesses, 280 fewer 

emergency room admissions for asthma, 

690,000 fewer days with restricted 

activity levels, and 510,000 fewer days 

where children are absent from school 

due to illnesses. 

In addition to these significant health 

benefits, the rule will result in 

ecological and welfare benefits. These 

benefits include visibility 

improvements; reductions in 

acidification in lakes, streams, and 

forests; reduced eutrophication in water 

bodies; and benefits from reduced ozone 

levels for forests and agricultural 

production. 

Several other documents containing 

detailed explanations of other key 

elements of today’s rule are also 

included in the docket. These include a 

detailed explanation of how EPA 

calculated the State-by-State EGU 

emissions budgets, and a detailed 

explanation of the air quality modeling 

analyses which support this rule.6

Responses to comments that are not 

addressed in the preamble to today’s 

rule are included in a separate 

document.7

The remaining sections of the 

preamble describe the final CAIR 

requirements and our responses to 

comments on many of the most 

important features of the CAIR. Section 

II, ‘‘EPA’s Analytical Approach,’’

summarizes EPA’s overall analytical 

approach and responds to general 

comments on that approach. Section III, 

‘‘Why Does This Rule Focus on SO2 and 

NOX, and How Were Significant 

Downwind Impacts Determined?,’’

outlines the rationale for the CAIR focus 

on SO2 and NOX, which are precursors 

that contribute to PM2.5 (SO2, NOX) or 

ozone (NOX) transport, and the analytic 

approach EPA used to determine which 

States had large enough downwind 

ambient air quality impacts to become 

subject to today’s requirements. Section 

IV, ‘‘What Amounts of SO2 and NOX

Emissions Did EPA Determine Should 

Be Reduced?,’’ describes EPA’s 

methodology for determining the 

amounts of SO2 and NOX emissions 

reductions required under today’s rule. 

Section V, ‘‘Determination of State 

Emissions Budgets,’’ describes how EPA 

determined the State-by-State emissions 

reductions requirements and, in the 

event States elect to control EGUs, the 

State-by-State EGU emissions budgets. 

Section VI, ‘‘Air Quality Modeling 

Approach and Results,’’ describes the 

technical aspects of the air quality 

modeling and summarizes the 

numerical results of that modeling. 

Section VII, ‘‘SIP Criteria and Emissions 

Reporting Requirements,’’ describes the 

SIP submission date and other SIP 

requirements associated with the 

emissions controls that States might 

adopt. Section VIII, ‘‘NOX and SO2

Model Cap and Trade Programs,’’

describes the EPA administered cap and 

trade programs that States electing to 

control emissions from EGUs are 

encouraged to adopt. Section IX, 

‘‘Interactions with Other Clean Air Act 

Requirements,’’ discusses how this rule 

interacts with the acid rain provisions 

in CAA title IV, the NOX SIP Call, the 

best available retrofit technology 

(BART) requirements, and other CAA or 

regulatory requirements. Finally, section 

X, ‘‘Statutory and Executive Order 

Reviews,’’ describes the applicability of 

various administrative requirements for 

today’s rule and how EPA addressed 

these requirements.

A. What Are the Central Requirements 

of This Rule? 

In today’s action, we establish SIP 

requirements for the affected upwind 

States under CAA section 110(a)(2). 

Clean Air Act section 110(a)(2)(D) 

requires SIPs to contain adequate 

provisions prohibiting air pollutant 

emissions from sources or activities in 

those States that contribute significantly 

to nonattainment in, or interfere with 

maintenance by, any other State with 

respect to a NAAQS. Based on air 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25167

8 In today’s final rule, when we use the term 

‘‘transport’’ we mean to include the transport of 

both fine particles (PM2.5) and their precursor 

emissions and/or transport of both ozone and its 

precursor emissions.

9 In this regard, the construction of a new EGU 

on a reservation would be analogous to the 

construction of a new EGU within a county or 

region of a CAIR-affected State that does not 

presently contain any EGUs. This is not meant to 

imply that Tribes are in any way legally similar to 

counties, only that, within the CAIR region, the 

geographic scale of reservations is more similar to 

counties than to States.

quality modeling analyses and cost 

analyses, EPA has concluded that SO2

and NOX emissions in certain States in 

the eastern part of the country, through 

the phenomenon of air pollution 

transport,8 contribute significantly to 

downwind nonattainment, or interfere 

with maintenance, of the PM2.5 and 8-

hour ozone NAAQS. The EPA is 

requiring SIP revisions in 28 States and 

the District of Columbia to reduce SO2

and/or NOX emissions, which are 

important precursors of PM2.5 (NOX and 

SO2) and ozone (NOX).

The 23 States along with the District 

of Columbia that must reduce annual 

SO2 and NOX emissions for the 

purposes of the PM2.5 NAAQS are: 

Alabama, Florida, Georgia, Illinois, 

Indiana, Iowa, Kentucky, Louisiana, 

Maryland, Michigan, Minnesota, 

Mississippi, Missouri, New York, North 

Carolina, Ohio, Pennsylvania, South 

Carolina, Tennessee, Texas, Virginia, 

West Virginia, and Wisconsin. 

The 25 States along with the District 

of Columbia that must reduce NOX

emissions for the purposes of the 8-hour 

ozone NAAQS are: Alabama, Arkansas, 

Connecticut, Delaware, Florida, Illinois, 

Indiana, Iowa, Kentucky, Louisiana, 

Maryland, Massachusetts, Michigan, 

Mississippi, Missouri, New Jersey, New 

York, North Carolina, Ohio, 

Pennsylvania, South Carolina, 

Tennessee, Virginia, West Virginia, and 

Wisconsin. In addition to making the 

findings of significant contribution to 

nonattainment or interference with 

maintenance, EPA is requiring each 

State to make specified amounts of SO2

and/or NOX emissions reductions to 

eliminate their significant contribution 

to downwind States. The affected States 

and the District of Columbia are 

required to adopt and submit the 

required SIP revision with the necessary 

control measures by 18 months from the 

signature date of today’s rule. 

The emissions reductions 

requirements are based on controls that 

EPA has determined to be highly cost 

effective for EGUs. However, States have 

the flexibility to choose the measures to 

adopt to achieve the specified emissions 

reductions. If the State chooses to 

control EGUs, then it must establish a 

budget—that is, an emissions cap—for 

those sources. Today’s rule defines the 

EGU budgets for each affected State if a 

State chooses to control only EGUs. The 

rule also explains the emission 

reduction requirements if a State 

chooses to achieve some or all of its 

required emission reductions by 

controlling sources other than EGUs. 

Due to feasibility constraints, EPA is 

requiring emissions reductions be 

implemented in two phases. The first 

phase of NOX reductions starts in 2009 

(covering 2009–2014) and the first phase 

of SO2 reductions starts in 2010 

(covering 2010–2014); the second phase 

of reductions for both NOX and SO2

starts in 2015 (covering 2015 and 

thereafter). For States subject to findings 

of significant contribution for PM2.5, 

EPA is establishing annual emissions 

budgets. For States subject to findings of 

significant contribution for 8-hour 

ozone, the CAIR specifies ozone-season 

NOX emissions budgets. States subject 

to findings for both PM2.5 and ozone 

will have both an annual and an ozone 

season NOX budget. 

The EPA is providing, as an option to 

States, model cap and trade programs 

for EGUs. The EPA will administer 

these programs, which will be governed 

by rules provided by EPA that States 

may adopt or incorporate by reference. 

With respect to federally recognized 

Indian Tribes, the applicability of this 

rule is governed by three factors: The 

flexible regulatory framework for Tribes 

provided by the CAA and the Tribal 

Authority Rule (TAR); the absence of 

any existing EGUs on Tribal lands in the 

CAIR region; and the existence of 

reservations within the geographic areas 

which we determined to contribute 

significantly to nonattainment areas. 

Under CAA section 301(d) as 

implemented by the TAR, eligible 

Indian Tribes may implement all, but 

are not required to implement any, 

programs under the CAA for which EPA 

has determined that it is appropriate to 

treat Tribes similarly to States. Tribes 

may also implement ‘‘reasonably 

severable’’ elements of programs (40 

CFR 49.7(c)). In the absence of Tribal 

implementation of a CAA program or 

programs, EPA will utilize Federal 

implementation for the relevant area of 

Indian country as necessary or 

appropriate to protect air quality, in 

consultation with the Tribal 

government.

The TAR contains a list of provisions 

for which it is not appropriate to treat 

Tribes in the same manner as States (40 

CFR 49.4). The CAIR is based on the 

States’ obligations under CAA section 

110(a)(2)(D) to prohibit emissions which 

would contribute significantly to 

nonattainment in, or interfere with 

maintenance by, other States due to 

pollution transport. Because CAA 

section 110(a)(2)(D) is not among the 

provisions we determined to be 

inappropriate to apply to Tribes in the 

same manner as States, that section is 

applicable, where necessary and 

appropriate, to Tribes. 

However, among the CAA provisions 

not appropriate for Tribes are ‘‘[s]pecific 

plan submittal and implementation 

deadlines for NAAQS-related 

requirements * * *’’ (40 CFR 49.4(a)). 

Therefore, Tribes are not required to 

submit implementation plans under 

section 110(a)(2)(D). Moreover, because 

no Tribal lands in the CAIR region 

currently contain any of the sources 

(EGUs) on which we based the 

emissions reductions requirements 

applicable to States, there are no 

emission reduction requirements 

applicable to Tribes. 

At the same time, the existence of the 

CAIR cap and trade program in some or 

all of the affected States will have 

implications for any future construction 

of EGUs on Tribal lands. The geographic 

scope of the CAIR cap and trade 

program is being determined by a two 

step-process: the EPA’s determination of 

which States significantly contribute to 

downwind areas, and the decision by 

those affected States whether to satisfy 

their emission reduction requirement by 

participating in the CAIR cap and trade 

program. 

With respect to the first step of this 

process (significant contribution test), 

notwithstanding the political autonomy 

of Tribes, we view the zero-out 

modeling as representing the entire 

geographic area within the State being 

considered, regardless of the 

jurisdictional status of areas within the 

State. Therefore, any EGU constructed 

in the future on a reservation within a 

CAIR-affected State would be located in 

an area which we have already 

determined to significantly contribute to 

downwind nonattainment.9

With respect to decisions by States to 

participate in the CAIR cap and trade 

program, because Tribal governments 

are autonomous, such a decision would 

not be directly binding for any Tribe 

located within the State. 

Nonetheless, as a matter of a policy, 

cap and trade programs by their nature 

must apply consistently throughout the 

geographic region of the program in 

order to be effective. Otherwise, the 

existence of areas not covered by the 

cap could create incentives to locate 

sources there, and thereby undermine 

25168 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

10Although it is possible that the CAIR cap and 

trade program may cover a discontinuous area 

depending on which States participate, the failure 

of a State to participate does not raise the same 

environmental integrity concern. A state that does 

not participate in the cap and trade program must 

still submit a SIP that limits emissions to the levels 

mandated by the CAIR emission reduction 

requirements, taking into account any emissions 

from new sources.

11 ‘‘Finding of Significant Contribution and 

Rulemaking for Certain States in the Ozone 

Transport Assessment Group Region for Purposes of 

Reducing Regional Transport of Ozone; Rule,’’ (63 

FR 57356; October 27, 1998).

the environmental goals of the 

program.10

In light of these considerations, in the 

event of any future planned 

construction of EGUs on Tribal lands 

within the CAIR region, EPA intends to 

work with the relevant Tribal 

government to regulate the EGU through 

either a Tribal implementation plan 

(TIP) or a Federal implementation plan 

(FIP). We anticipate that at a minimum, 

a proposed EGU on a reservation within 

a State participating in the CAIR cap 

and trade program would need to be 

made subject to the cap and trade 

program. In the case of a new EGU on 

a reservation in a CAIR-affected State 

which chose not to participate in the 

cap and trade program, the new EGU 

might also be required, through a TIP or 

FIP, to participate in the program. This 

would depend on the potential for 

emissions shifting and other specific 

circumstances (e.g., whether the EGU 

would service the electric grid of States 

involved in the cap and trade program.) 

Again, EPA will work with the relevant 

Tribal government to determine the 

appropriate application of the CAIR. 

Finally, as discussed in the SNPR, 

Tribes have objected to emissions 

trading programs that allocate 

allowances based on historic emissions, 

on the grounds that this rewards first-intime emitters at the expense of those 

who have not yet enjoyed a fair 

opportunity to pursue economic 

development. Comments on the CAIR 

proposal from Tribes requested a 

Federal set-aside of allowances for 

Tribes, or other special Tribal allowance 

provisions. The few comments received 

from States on the issue generally 

opposed allocations based on Indian 

country status. One State expressed a 

willingness to share its emissions 

budget with Tribes in the event an EGU 

locates in Indian country. 

The EPA does not believe there is 

sufficient information to design Tribal 

allocation provisions at this time. A 

program designed to address concerns 

which remain largely speculative is 

likely to create more problems through 

unintended consequences than it solves. 

Therefore, rather than create a Federal 

allowance set-aside for Tribes, EPA will 

work with Tribes and potentially 

affected States to address concerns 

regarding the equity of allowance 

allocations on a case-by-case basis as the 

need arises. The EPA may choose to 

revisit this issue through a separate 

rulemaking in the future.

B. Why Is EPA Taking This Action? 

Emissions reductions to eliminate 

transported pollution are required by 

the CAA, as noted above. There are 

strong policy reasons for addressing 

interstate pollution transport. 

1. Policy Rationale for Addressing 

Transported Pollution Contributing to 

PM2.5 and Ozone Problems 

Emissions from upwind States can 

alone, or in combination with local 

emissions, result in air quality levels 

that exceed the NAAQS and jeopardize 

the health of residents in downwind 

communities. Control of PM2.5 and 

ozone requires a reasonable balance 

between local and regional controls. If 

significant contributions of pollution 

from upwind States that can be abated 

by highly cost-effective controls are 

unabated, the downwind area must 

achieve greater local emissions 

reductions, thereby incurring extra 

clean-up costs. Requiring reasonable 

controls for both upwind and local 

emissions sources should result in 

achieving air quality standards at a 

lesser cost than a strategy that relies 

solely on local controls. For all these 

reasons, addressing interstate transport 

in advance of the time that States must 

adopt local nonattainment plans, will 

make it easier for States to develop their 

nonattainment plans because the States 

will know the degree to which the 

pollution flowing into their 

nonattainment areas will be reduced. 

The EPA addressed interstate 

pollution transport for ozone in the NOX

SIP Call rule published in 1998.11

Today’s rulemaking is EPA’s first 

attempt to address interstate pollution 

transport for PM2.5. The NOX SIP Call is 

substantially reducing ozone transport, 

helping downwind areas meet the 1-

hour and 8-hour ozone standards. The 

EPA has reassessed ozone transport in 

this rulemaking for two reasons. First, 

several years have passed since 

promulgation of the NOX SIP Call and 

updated air quality and emissions data 

are available. Second, some areas are 

expected to face substantial difficulty in 

meeting the 8-hour ozone standards. As 

a result, EPA has determined it is 

important to assess the degree to which 

ozone transport will remain a problem 

after full implementation of the NOX SIP 

Call, and to assess whether further 

controls are warranted to ensure 

continued progress toward attainment. 

The modeling for the CAIR includes the 

NOX SIP Call in the baseline and 

examines later years than the NOX SIP 

Call analyses.

a. The PM2.5 Problem 

By action dated July 18, 1997, we 

revised the NAAQS for particulate 

matter (PM) to add new standards for 

fine particles, using as the indicator 

particles with aerodynamic diameters 

smaller than a nominal 2.5 micrometers, 

termed PM2.5 (62 FR 38652). We 

established health- and welfare-based 

(primary and secondary) annual and 24-

hour standards for PM2.5. The annual 

standards are 15 micrograms per cubic 

meter, based on the 3-year average of 

annual mean PM2.5 concentrations. The 

24-hour standard is a level of 65 

micrograms per cubic meter, based on 

the 3-year average of the annual 98th 

percentile of 24-hour concentrations. 

The annual standard is generally 

considered the most limiting. 

Fine particles are associated with a 

number of serious health effects 

including premature mortality, 

aggravation of respiratory and 

cardiovascular disease (as indicated by 

increased hospital admissions, 

emergency room visits, absences from 

school or work, and restricted activity 

days), lung disease, decreased lung 

function, asthma attacks, and certain 

cardiovascular problems such as heart 

attacks and cardiac arrhythmia. The 

EPA has estimated that attainment of 

the PM2.5 standards would prolong tens 

of thousands of lives and would 

prevent, each year, tens of thousands of 

hospital admissions as well as hundreds 

of thousands of doctor visits, absences 

from work and school, and respiratory 

illnesses in children. 

Individuals particularly sensitive to 

fine particle exposure include older 

adults, people with heart and lung 

disease, and children. More detailed 

information on health effects of fine 

particles can be found on EPA’s Web 

site at: http://www.epa.gov/ttn/naaqs/

standards/pm/s_pm_index.html.

At the time EPA established the PM2.5

primary NAAQS in 1997, we also 

established welfare-based (secondary) 

NAAQS identical to the primary 

standards. The secondary standards are 

designed to protect against major 

environmental effects caused by PM 

such as visibility impairment—

including in Class I areas which include 

national parks and wilderness areas 

across the country—soiling, and 

materials damage. 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25169

12EPA 454/K–04–001, April 2004.

As discussed in other sections of this 

preamble, SO2 and NOX emissions both 

contribute to fine particle 

concentrations. In addition, NOX

emissions contribute to ozone problems, 

described in the next section. We 

believe the CAIR will significantly 

reduce SO2 and NOX emissions that 

contribute to the PM2.5 and 8-hour 

ozone problems described here.

The PM2.5 ambient air quality 

monitoring for the 2001–2003 period 

shows that areas violating the standards 

are located across much of the eastern 

half of the United States and in parts of 

California, and Montana. Based on these 

nationwide data, 82 counties have at 

least one monitor that violates either the 

annual or the 24-hour PM2.5 standard. 

Most areas violate only the annual 

standard; a small number of areas 

violate both the annual and 24-hour 

standards; and no areas violate just the 

24-hour standard. The population of 

these 82 counties totals over 56 million 

people. 

Only two States in the western part of 

the U.S., California and Montana, have 

counties that exceeded the PM2.5

standards. On the other hand, in the 

eastern part of the U.S., 124 sites in 69 

counties (with total population of 34 

million) violated the annual PM2.5

standard of 15.0 micrograms per cubic 

meter (μg/m3) over the 3-year period 

from 2001 to 2003, while 469 sites met 

the annual standard. No sites in the 

eastern part of the United States 

exceeded the daily PM2.5 standard of 65 

μg/m3. The 69 violating counties are 

located in a region made up of 16 States 

(plus the District of Columbia), 

extending eastward from St. Louis 

County, Missouri, the western-most 

violating county and including the 

following States: Alabama, Delaware, 

Georgia, Illinois, Indiana, Kentucky, 

Maryland, Missouri, Michigan, New 

Jersey, New York, North Carolina, Ohio, 

Pennsylvania, Tennessee, West Virginia, 

and the District of Columbia. The EPA 

published the PM2.5 attainment and 

nonattainment designations on January 

5, 2005 (70 FR 944). The designations 

will be effective on April 5, 2005. 

Because interstate transport is not 

believed to be a significant contributor 

to exceedances of the PM2.5 standards in 

California or Montana, today’s final 

CAIR does not cover these States. 

b. The 8-Hour Ozone Problem 

By action dated July 18, 1997, we 

promulgated identical revised primary 

and secondary ozone standards that 

specified an 8-hour ozone standard of 

0.08 parts per million (ppm). 

Specifically, under the standards, the 3-

year average of the fourth highest daily 

maximum 8-hour average ozone 

concentration may not exceed 0.08 ppm. 

In general, the revised 8-hour standards 

are more protective of public health and 

the environment and more stringent 

than the pre-existing 1-hour ozone 

standards. All areas that were violating 

the 1-hour ozone standard at the time of 

the 8-hour ozone designations were also 

designated as nonattainment for the 8-

hour ozone standard. More areas do not 

meet the 8-hour standard than do not 

meet the 1-hour standard. The EPA 

published the 8-hour ozone attainment 

and nonattainment designations in the 

Federal Register on April 30, 2004 (69 

FR 23858). The designations were 

effective on June 15, 2004. Pursuant to 

EPA’s final rule to implement the 8-

hour ozone standard (69 FR 23951; 

April 30, 2004), EPA will revoke the 1-

hour ozone standard on June 15, 2005, 

1 year after the effective date of the 8-

hour designations. 

Short-term (1- to 3-hour) and 

prolonged (6- to 8-hour) exposures to 

ambient ozone have been linked to a 

number of adverse health effects. Shortterm exposure to ozone can irritate the 

respiratory system, causing coughing, 

throat irritation, and chest pain. Ozone 

can reduce lung function and make it 

more difficult to breathe deeply. 

Breathing may become more rapid and 

shallow than normal, thereby limiting a 

person’s normal activity. Ozone also can 

aggravate asthma, leading to more 

asthma attacks that require a doctor’s 

attention and the use of additional 

medication. Increased hospital 

admissions and emergency room visits 

for respiratory problems have been 

associated with ambient ozone 

exposures. Longer-term ozone exposure 

can inflame and damage the lining of 

the lungs, which may lead to permanent 

changes in lung tissue and irreversible 

reductions in lung function. A lower 

quality of life may result if the 

inflammation occurs repeatedly over a 

long time period (such as months, years, 

a lifetime).

People who are particularly 

susceptible to the effects of ozone 

include children and adults who are 

active outdoors, people with respiratory 

diseases, such as asthma, and people 

with unusual sensitivity to ozone. 

In addition to causing adverse health 

effects, ozone affects vegetation and 

ecosystems, leading to reductions in 

agricultural crop and commercial forest 

yields; reduced growth and survivability 

of tree seedlings; and increased plant 

susceptibility to disease, pests, and 

other environmental stresses (e.g., harsh 

weather). In long-lived species, these 

effects may become evident only after 

several years or even decades and have 

the potential for long-term adverse 

impacts on forest ecosystems. Ozone 

damage to the foliage of trees and other 

plants can also decrease the aesthetic 

value of ornamental species used in 

residential landscaping, as well as the 

natural beauty of our national parks and 

recreation areas. The economic value of 

some welfare losses due to ozone can be 

calculated, such as crop yield loss from 

both reduced seed production (e.g., 

soybean) and visible injury to some leaf 

crops (e.g., lettuce, spinach, tobacco), as 

well as visible injury to ornamental 

plants (i.e., grass, flowers, shrubs). 

Other types of welfare loss may not be 

quantifiable (e.g., reduced aesthetic 

value of trees growing in heavily visited 

national parks). More detailed 

information on health effects of ozone 

can be found at the following EPA Web 

site: http://www.epa.gov/ttn/naaqs/

standards/ozone/s_o3_index.html. 

Almost all areas of the country have 

experienced some progress in lowering 

ozone concentrations over the last 20 

years. As reported in the EPA’s report, 

‘‘The Ozone Report: Measuring Progress 

Through 2003,’’ 12 national average 

levels of 1-hour ozone improved by 29 

percent between 1980 and 2003 while 8-

hour levels improved by 21 percent over 

the same time period. The Northeast 

and West regions have shown the 

greatest improvement since 1980. 

However, most of that improvement 

occurred during the first part of the 

period. In fact, during the most recent 

10 years, ozone levels have been 

relatively constant reflecting little if any 

air quality improvement. For this 

reason, ozone has exhibited the slowest 

progress of the six major pollutants 

tracked nationally.

Although ambient ozone levels 

remained relatively constant over the 

past decade, additional control 

requirements have reduced emissions of 

the two major ozone precursors, VOC 

and NOX, although at different rates. 

Emissions of VOCs were reduced by 32 

percent from 1990 levels, while 

emissions of NOX declined by 22 

percent. 

Ozone remains a significant public 

health concern. Presently, wide 

geographic areas, including most of the 

nation’s major population centers, 

experience unhealthy ozone levels, that 

is, concentrations violating the NAAQS 

for 8-hour ozone. These areas include 

much of the eastern part of the United 

States and large areas of California. 

More specifically, 297 counties with a 

total population of over 124 million 

people currently violate the 8-hour 

ozone standard. Most of these ozone 

25170 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

violations occur in the eastern half of 

the United States: 268 counties with a 

population of over 93 million. 

When ozone and PM2.5 are examined 

jointly, 322 counties with 131 million 

people are violating at least one of the 

standards while 57 counties nationwide 

have concentrations violating both 

standards with a total population of 

over 49 million people. Of these, 46 

counties with a population of over 28 

million are in the Eastern United States. 

c. Other Environmental Effects 

Associated With SO2 and NOX

Emissions 

Today’s action will result in benefits 

in addition to the enumerated human 

health and welfare benefits resulting 

from reductions in ambient levels of 

PM2.5 and ozone. Reductions in NOX

and SO2 will contribute to substantial 

visibility improvements in many parts 

of the Eastern U.S. where people live, 

work, and recreate, including Federal 

Class I areas such as the Great Smoky 

Mountains. Reductions in these 

pollutants will also reduce acidification 

and eutrophication of water bodies in 

the region. In addition, reduced mercury 

emissions are anticipated as a result of 

this rule. Reduced mercury emissions 

will lessen mercury contamination in 

lakes and thereby potentially decrease 

both human and wildlife exposure to 

mercury-contaminated fish. 

2. The CAA Requires States To Act as 

Good Neighbors by Limiting Downwind 

Impacts 

The CAA includes the ‘‘good 

neighbor’’ provision of section 

110(a)(2)(D), which requires that every 

SIP prohibit emissions from any source 

or other type of emissions activity in 

amounts that will contribute 

significantly to nonattainment in any 

downwind State, or that will interfere 

with maintenance in any downwind 

State. In today’s action, EPA is 

determining that 28 States and the 

District of Columbia, all in the eastern 

part of the United States, have 

emissions of SO2 and/or NOX that will 

contribute significantly to 

nonattainment, or interfere with 

maintenance, of the PM2.5 NAAQS and/

or the 8-hour ozone NAAQS in another 

State. Under EPA’s general authority to 

clarify the applicability of CAA 

requirements, as provided in CAA 

section 301(a)(1), EPA is establishing 

the amount of SO2 and NOX emissions 

that each affected State must prohibit by 

submitting appropriate SIP provisions to 

EPA. The improvements in air quality 

will assist downwind States in 

developing their SIPs to provide for 

attainment and maintenance in those 

nonattainment areas. 

3. Today’s Rule Will Improve Air 

Quality 

The EPA has estimated the 

improvements in emissions and air 

quality that would result from 

implementing the CAIR. These 

improvements, which are substantial, 

are summarized earlier in this section. 

C. What Was the Process for Developing 

This Rule? 

By action dated January 30, 2004, EPA 

issued a proposal that included many of 

the components of today’s action. ‘‘Rule 

to Reduce Interstate Transport of Fine 

Particulate Matter and Ozone (Interstate 

Air Quality Rule); Proposed Rule,’’ (69 

FR 4566). The Administrator signed the 

proposed rule—termed, at that time, the 

Interstate Air Quality Rule—on 

December 17, 2003, and EPA posted it 

on its Web site for this rule on that date. 

The Web site address at that time was 

http://www.epa.gov/interstateairquality. 

(The address has since changed to

http://www.epa.gov/

cleanairinterstaterule/ or http://

www.epa.gov/cair/.)

The EPA held public hearings on the 

proposal, in conjunction with a 

proposed rulemaking concerning 

mercury and other hazardous air 

pollutants from EGUs, on February 25–

26, 2004, in Chicago, Illinois; 

Philadelphia, Pennsylvania; and 

Research Triangle Park, North Carolina. 

The comment period for the NPR closed 

on March 30, 2004. The EPA received 

over 6,700 comments on the proposal. 

By action dated June 10, 2004, EPA 

issued a supplemental notice of 

proposed rulemaking (SNPR), 

‘‘Supplemental Proposal for the Rule to 

Reduce Interstate Transport of Fine 

Particulate Matter and Ozone (Clean Air 

Interstate Rule); Proposed Rule,’’ (69 FR 

32684). The Administrator signed the 

SNPR for this rule—now called the 

Clean Air Interstate Rule—on May 18, 

2004, and EPA placed it on the Web site 

on that date. The SNPR included, 

among other things, proposed regulatory 

language for the rule, revised proposals 

concerning State-level emissions 

budgets, proposed State reporting 

requirements and SIP approvability 

criteria, and proposed model cap and 

trade rules. The SNPR also proposed 

that under certain circumstances the 

CAIR requirements could replace the 

BART requirements of CAA sections 

169A and 169B. The EPA held a public 

hearing on the SNPR on June 3, 2004, 

in Alexandria, Virginia. The comment 

period for the SNPR closed on July 26, 

2004. The EPA received over 400 

comments on the SNPR. 

By a notice of data availability 

(NODA) dated August 6, 2004, EPA 

announced the availability of additional 

documents for this action. ‘‘Availability 

of Additional Information Supporting 

the Rule To Reduce Interstate Transport 

of Fine Particulate Matter and Ozone 

(Clean Air Interstate Rule),’’ (69 FR 

47828). The documents had been placed 

on the website on or about July 27, 

2004, and in the EDOCKET on that date, 

or shortly thereafter. The EPA allowed 

public comment on those additional 

documents until August 27, 2004. 

Around 30 comments were received on 

the NODA. 

The EPA has responded to all 

significant public comments either in 

this preamble or in the response to 

comment document which is contained 

in the docket. 

Comments on Rulemaking Process:

Some commenters expressed concerns 

about certain aspects of this process. 

One concern was that EPA did not allow 

sufficient time to comment on the 

SNPR. Commenters noted that 

important program elements—including 

regulatory language—appeared for the 

first time in the SNPR, but EPA held a 

public hearing on the SNPR 7 days 

before the SNPR was published in the 

Federal Register and only 16 days after 

the SNPR had been posted on the 

website. The EPA believes that the 16-

day period preceding the public 

hearing, and the total of 45 days to 

comment on the SNPR following its 

publication in the Federal Register, 

constituted an adequate opportunity for 

members of the public to comment on 

the SNPR. 

Commenters also expressed concern 

that certain technical documents were 

not made available in sufficient time to 

comment. However, EPA had placed all 

technical support documents for the 

NPR in the EDOCKET as of the date of 

publication of the NPR, and all 

technical support documents for the 

SNPR had been placed in the EDOCKET 

as of the date of publication of the 

SNPR. 

Commenters also expressed concern 

that in the SNPR, EPA proposed 

significant changes to other regulatory 

programs. The EPA agrees that the 

SNPR did include proposed changes to 

certain regulatory programs, i.e., the 

requirements for BART under CAA 

sections 169A and 169B (concerning 

visibility), certain provisions (primarily 

concerning the allowance-holding 

requirement) in the title IV (Acid Rain 

Program) rules, and certain emissions 

reporting rules under the NOX SIP Call 

(40 CFR 51.122) and Consolidated 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25171

Emissions Reporting Rule (CERR) (title 

40, part 51, subpart A). The EPA 

believes that to the extent the 

requirements for BART and emissions 

reporting rule revisions are tied to the 

CAIR, affected members of the public 

had adequate notice of those revisions. 

(These revisions are described in section 

VII.) However, the SNPR contained 

some revisions to the emissions 

reporting rules that were not tied to the 

transport provisions. The EPA is not 

taking final action today on the proposal 

for the emissions reporting rules that 

were not tied to the transport provisions 

and instead is issuing a new proposal 

for them, which will provide additional 

notice and opportunity to comment. 

Further, the Acid Rain Program rule 

revisions, although connected to the 

CAIR, apply to all persons subject to the 

Acid Rain Program, including persons 

who are not affected by the CAIR. 

(These revisions are described in section 

IX.) Specifically, as explained in section 

IX, the revisions to the Acid Rain 

Program rules are aimed at facilitating 

coordination of the Acid Rain Program 

and the CAIR model SO2 cap and trade 

rule and/or are being adopted on their 

own merits, independently of the need 

to coordinate with the CAIR. Most of the 

proposed revisions involve changing 

from unit-by-unit to source-by-source 

compliance with the allowance-holding 

requirement of the Acid Rain Program 

and therefore affect every source subject 

to the Acid Rain Program, whether or 

not the source is also in a State covered 

by the CAIR. The change to source-bysource compliance increases a source’s 

flexibility to use—in meeting the 

allowance-holding requirement—

allowances held by any unit at the 

source. This flexibility reduces the 

likelihood that sources will incur large 

excess emissions penalties from 

inadvertent, minor errors (e.g., in how 

allowances are distributed among the 

units at the source), while preserving 

the environmental goals of the Acid 

Rain Program. The remaining revisions 

to the Acid Rain Program rules similarly 

cover all Acid Rain Program sources. 

Indeed, none of the comments on the 

proposed Acid Rain Program rule 

revisions stated that the revisions would 

apply only to certain Acid Rain Program 

sources, but rather seemed to treat the 

revisions as applying program-wide. As 

discussed in section IX, EPA is 

finalizing, with minor modifications, 

the Acid Rain Program rule revisions. 

Commenters also expressed concern 

that between the NPR and the SNPR, 

EPA had proposed program elements in 

a piecemeal fashion, which made it 

more difficult to comprehend and 

comment on the rule, and that the 

SNPR’s comment period was too short 

to allow the public adequate 

opportunity to comment on the 

numerous and complex issues raised in 

that proposal. The EPA recognizes the 

challenges faced by commenters in this 

rulemaking, however, we believe that 

the comment periods for the NPR and 

SNPR were adequate, and note that we 

did receive extensive and highly 

detailed, technical comments on both 

proposals.

D. What Are the Major Changes Between 

the Proposals and the Final Rule? 

The EPA is finalizing a number of 

revisions to the proposed elements of 

the CAIR. These revisions are in 

response to information received in 

public comments and new analyses 

conducted by EPA. The following is a 

summary list of those changes: 

• The first phase of NOX reductions 

starts in 2009 (covering 2009–2014) 

instead of 2010. The first phase of the 

SO2 reductions still starts in 2010 

(covering 2010–2014). 

• The emissions inventories used for 

PM2.5 and 8-hour ozone air quality 

modeling have been updated and 

improved; we modeled PM2.5 using the 

Community Multiscale Air Quality 

Model (CMAQ) and meteorology for 

2001 instead of the Regional Model for 

Simulating Aerosols and Deposition 

(REMSAD) and meteorology for 1996. 

• The final CAIR does not cover 

Kansas based on new analyses of its 

contribution to downwind PM2.5

nonattainment. 

• Arkansas, Delaware, Massachusetts, 

and New Jersey are not subject to the 

CAIR based on their contribution to 

PM2.5 nonattainment and maintenance. 

However, they remain subject to NOX

emissions reductions requirements on 

the basis of their contribution to 

downwind 8-hour ozone nonattainment. 

This requirement is for the ozone season 

rather than the entire year. The EPA is 

issuing a new proposal to include 

Delaware and New Jersey for the PM2.5

NAAQS based on additional 

considerations. 

• The change in States covered by the 

rule necessitates a re-analysis of the 

NOX budgets for all covered States. This 

changes the amount of the budget, but 

not the procedure EPA used to calculate 

it. 

• The SIP approval criteria have been 

changed to no longer exclude measures 

otherwise required by the CAA from 

being included in the State’s 

compliance with CAIR. 

• A 200,000 ton compliance 

supplement pool was added for NOX. 

Allowances from this pool can either be 

awarded to sources that make early 

reductions or to sources that 

demonstrate need. 

• All States for which EPA has made 

a finding with respect to ozone are 

subject to an ozone season cap. In order 

to implement this ozone season cap, 

EPA has finalized an ozone season NOX

trading program in addition to the 

annual NOX and SO2 trading programs 

that were proposed. 

• A number of changes were made to 

the trading rule including: changes to 

the model NOX allocation methodology 

(to fuel weight allocations) and the 

addition of opt in provisions. 

• The EPA is not finalizing some of 

the emissions reporting requirements in 

response to public comments indicating 

we gave inadequate notice of the 

changes that were proposed to be 

applicable to all States, not just those 

affected by the CAIR emission reduction 

requirements. These are being 

reproposed, with modifications, in a 

separate action to allow additional 

opportunity for public comment by all 

affected States and other parties. 

II. The EPA’s Analytical Approach 

Overview: Today’s rulemaking is 

based on the ‘‘good neighbor’’ provision 

of CAA section 110(a)(2)(D), which 

requires States to develop SIP 

provisions assuring that emissions from 

their sources do not contribute 

significantly to downwind 

nonattainment, or interfere with 

maintenance, of the NAAQS. The EPA 

interpreted this provision, and 

developed a detailed methodology for 

applying it, in the NOX SIP Call 

rulemaking, which concerned interstate 

transport of ozone precursors. 

Today’s rule requires upwind States 

to submit SIP revisions requiring their 

sources to reduce emissions of certain 

precursors that significantly contribute 

to nonattainment in, or interfere with 

maintenance of, the PM2.5 and 8-hour 

ozone national ambient air quality 

standards in downwind States. The EPA 

developed today’s rule relying heavily 

on the NOX SIP Call approach. 

This section of the preamble outlines 

the key aspects of today’s approach, 

some of which are described in greater 

detail in other sections of the preamble. 

The EPA received comments on today’s 

approach that we respond to either in 

this section or in the other sections of 

the preamble. This section also 

describes how today’s approach varies 

from the NOX SIP Call, which variations 

result from, among other things, the fact 

that today’s action regulates a different 

pollutant (PM2.5) with a different 

precursor (SO2). 

25172 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

13 In the NOX SIP Call, because the same criteria 

applied, the discussion of the ‘‘contribute 

significantly to nonattainment’’ test generally also 

applied to the ‘‘interfere with maintenance’’ test. 

However, in the NOX SIP Call, EPA stated that the 

‘‘interfere with maintenance’’ test applied with 

respect to only the 8-hour ozone NAAQS (63 FR 

57379–80).

14Although EPA’s air quality modeling 

techniques examined all of the upwind State’s 

emissions of ozone precursors (including VOC and 

NOX), only the NOX emissions had meaningful 

interstate impacts.

A. How Did EPA Interpret the Clean Air 

Act’s Pollution Transport Provisions in 

the NOX SIP Call? 

1. Clean Air Act Requirements 

The central CAA provisions 

concerning pollutant transport, for 

purposes of today’s action, are found in 

section 110(a)(2)(D). Under these 

provisions, each SIP must—

(D) Contain adequate provisions 

(i) Prohibiting * * * any source or 

other type of emissions activity within 

the State from emitting any air pollutant 

in amounts which will—

(I) Contribute significantly to 

nonattainment in, or interfere with 

maintenance by, any other State with 

respect to any * * * national primary or 

secondary ambient air quality standard 

* * *. 

2. The NOX SIP Call Rulemaking 

Promulgated by action dated October 

27, 1998, the NOX SIP Call was EPA’s 

principal effort to reduce interstate 

transport of precursors for both the 1-

hour ozone NAAQS and the 8-hour 

ozone NAAQS. (See ‘‘Finding of 

Significant Contribution and 

Rulemaking for Certain States in the 

Ozone Transport Assessment Group 

Region for Purposes of Reducing 

Regional Transport of Ozone; Rule,’’ (63 

FR 57356).) In that rulemaking, EPA 

imposed seasonal NOX reduction 

requirements on 22 States and the 

District of Columbia in the eastern part 

of the country. 

a. Analytical Approach of NOX SIP Call 

In the NOX SIP Call, EPA interpreted 

section 110(a)(2)(D) to authorize EPA to 

determine the amount of emissions in 

upwind States that ‘‘contribute 

significantly’’ to downwind 

nonattainment or ‘‘interfere with’’

downwind maintenance, and to require 

those States to eliminate that amount of 

emissions. The EPA recognized that 

States must retain full authority to 

choose the sources to control, and the 

control mechanisms, to achieve those 

reductions. 

The EPA set out several criteria or 

factors for the ‘‘contribute significantly’’

test, and further indicated that the same 

criteria should apply to the ‘‘interfere 

with maintenance’’ provision: 13

* * * EPA determined the amount of 

emissions that significantly contribute 

to downwind nonattainment from 

sources in a particular upwind State 

primarily by (i) evaluating, with respect 

to each upwind State, several air quality 

related factors, including determining 

that all emissions from the State have a 

sufficiently great impact downwind (in 

the context of the collective 

contribution nature of the ozone 

problem); and (ii) determining the 

amount of that State’s emissions that 

can be eliminated through the 

application of cost-effective controls. 

Before reaching a conclusion, EPA 

evaluated several secondary, and more 

general, considerations. These include: 

• The consistency of the regional 

reductions with the attainment needs of 

the downwind areas with 

nonattainment problems. 

• The overall fairness of the control 

regimes required of the downwind and 

upwind areas, including the extent of 

the controls required or implemented by 

the downwind and upwind areas. 

• General cost considerations, 

including the relative cost-effectiveness 

of additional downwind controls 

compared to upwind controls.

63 FR 57403

i. Air Quality Factor 

The first factor concerns evaluating 

the impact on downwind air quality of 

the upwind State’s emissions. As EPA 

stated in the NOX SIP Call: * * *

EPA specifically considered three air 

quality factors with respect to each upwind 

State * * *. 

• The overall nature of the ozone problem 

(i.e., ‘‘collective contribution’’). 

• The extent of the downwind 

nonattainment problems to which the 

upwind State’s emissions are linked, 

including the ambient impact of controls 

required under the CAA or otherwise 

implemented in the downwind areas. 

• The ambient impact of the emissions 

from the upwind State’s sources on the 

downwind nonattainment problems.

63 FR 57376

The EPA explained the first factor, 

collective contribution, by noting,

[V]irtually every nonattainment problem is 

caused by numerous sources over a wide 

geographic area* * *[. This] factor suggest[s] 

that the solution to the problem is the 

implementation over a wide area of controls 

on many sources, each of which may have a 

small or unmeasureable ambient impact by 

itself.

63 FR 57377

The second air quality factor—the 

extent of downwind nonattainment 

problems—concerns whether 

downwind areas should be considered 

to be in nonattainment. This 

determination took into account the 

then-current air quality of the area, the 

predicted future air quality (assuming 

the implementation of required controls, 

but not the transport requirements that 

were the subject of the NOX SIP Call), 

and the boundaries of the area in light 

of designation status (63 FR 57377). 

The EPA applied the third air quality 

factor—the ambient impact of emissions 

from the upwind sources—by projecting 

the amount of the upwind State’s entire 

inventory of anthropogenic emissions to 

the year 2007, and then quantifying, 

through the appropriate air quality 

modeling techniques, the impact of 

those emissions on downwind 

nonattainment.14 Specifically, (i) EPA 

determined the minimum threshold 

impact that the upwind State’s 

emissions must have on a downwind 

nonattainment area to be considered 

potentially to contribute significantly to 

nonattainment; and then (ii) for States 

with impacts above that threshold, EPA 

developed a set of metrics for further 

evaluating the contribution of the 

upwind State’s emissions on a 

downwind nonattainment area (63 FR 

57378). The EPA considered a State 

with emissions that had a sufficiently 

great impact to contribute significantly 

to the downwind area (depending on 

application of the cost factor). In 

general, EPA established the thresholds 

at a relatively low level, which reflected 

the collective contribution 

phenomenon. That is, because the ozone 

problem is caused by many relatively 

small contributions, even relatively 

small contributors must participate in 

the solution.

ii. Cost Factor 

The cost factor is the second major 

factor that EPA applied to determine the 

significant contribution to 

nonattainment: ‘‘EPA * * * determined 

whether any amounts of the NOX

emissions may be eliminated through 

controls that, on a cost-per-ton basis, 

may be considered to be highly cost 

effective.’’ (See 63 FR 57377.) 

(I) Choice of Highly Cost-Effective 

Standard 

The EPA selected the standard of 

highly cost effective in order to assure 

State flexibility in selecting control 

strategies to meet the emissions 

reduction requirements of the 

rulemaking. That is, the rulemaking 

required the States to achieve specified 

levels of emissions reductions—the 

levels achievable if States implemented 

the control strategies that EPA identified 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25173

as highly cost effective—but the 

rulemaking did not mandate those 

highly cost-effective control strategies, 

or any other control strategy. Indeed, in 

calculating the amount of the required 

emissions reductions by assuming the 

implementation of highly cost-effective 

control strategies, EPA assured that 

other control strategies—ones that were 

cost effective, if not highly cost 

effective—remained available to the 

States. 

(II) Determination of Highly CostEffective Amount 

The EPA determined the dollar 

amount considered to be highly cost 

effective by reference to the cost 

effectiveness of recently promulgated or 

proposed NOX controls. The EPA 

determined that the average cost 

effectiveness of controls in the reference 

list ranged up to approximately $1,800 

per ton of NOX removed (1990$), on an 

annual basis. The EPA considered the 

controls in the reference list to be cost 

effective.

The EPA established $2,000 (1990$) 

in average cost effectiveness for summer 

ozone season emissions reductions as, at 

least directionally, the highly costeffective amount. Identifying this 

amount on an ozone season basis was 

appropriate because the NOX SIP Call 

concerned the ozone standard, for 

which emissions reductions during only 

the summer ozone season are necessary. 

This level of costs reflected the fact that 

in general, States with downwind ozone 

nonattainment areas had already 

implemented extensive controls. 

Accordingly, it was evident that the 

level of upwind controls EPA selected 

would prove necessary for the 

downwind areas to reach attainment. 

(III) Source Categories 

The EPA then determined that the 

source categories for which highly costeffective controls were available 

included EGUs, large industrial boilers 

and turbines, and cement kilns. At the 

same time, EPA determined, for those 

source categories, the level of controls 

that would cost an amount consistent 

with the highly cost-effective amount 

and that would be feasible. The EPA 

considered other source categories, but 

found that highly cost-effective controls 

were not available from them for various 

reasons, including the size of the 

sources, the relatively small amount of 

emissions from the sources, or the 

control costs. 

iii. Other Factors 

The EPA also relied on several other, 

secondary considerations before 

concluding that the identified amount of 

emissions reductions were required. 

The first concerned the consistency of 

regional reductions with downwind 

attainment needs. The EPA ascertained 

the ozone air quality impacts of the 

required emissions reductions, and 

determined that those impacts improved 

air quality downwind, but not to the 

point that would raise questions about 

whether the amount of reductions was 

more than necessary (63 FR 57379). 

The second general consideration was 

‘‘the overall fairness of the control 

regimes’’ to which the downwind and 

upwind areas were subject. The EPA 

explained:

Most broadly, EPA believes that overall 

notions of fairness suggest that upwind 

sources which contribute significant amounts 

to the nonattainment problem should 

implement cost-effective reductions. When 

upwind emitters exacerbate their downwind 

neighbors’ ozone nonattainment problems, 

and thereby visit upon their downwind 

neighbors additional health risks and 

potential clean-up costs, EPA considers it fair 

to require the upwind neighbors to reduce at 

least the portion of their emissions for which 

highly cost-effective controls are available. 

In addition, EPA recognizes that in many 

instances, areas designated as nonattainment 

under the 1-hour NAAQS have incurred 

ozone control costs since the early 1970s. 

Moreover, virtually all components of their 

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

reduce ozone. Furthermore, these areas have 

complied with almost all of the specific 

control requirements under the CAA, and 

generally are moving towards compliance 

with their remaining obligations. The CAA’s 

sanctions and FIP provisions provide 

assurance that these remaining controls will 

be implemented. By comparison, many 

upwind States in the midwest and south 

have had fewer nonattainment problems and 

have incurred fewer control obligations.

(63 FR 57379.) 

The third general consideration was 

‘‘general cost considerations.’’ The EPA 

noted that ‘‘in general, areas that 

currently have, or that in the past have 

had, nonattainment problems * * * 

have already incurred ozone control 

costs.’’ The next set of controls available 

to these nonattainment areas would be 

more expensive than the controls 

available to the upwind areas. The EPA 

found that this cost scenario further 

confirmed the reasonableness of the 

upwind control obligations (63 FR 

57379). 

In the NOX SIP Call, EPA considered 

all of these factors together in 

determining the level of controls 

considered to be highly cost effective. 

This level of controls reflected the thenpresent state of ozone controls: Within 

the region, the nonattainment areas 

were already required to—and had 

already implemented—VOC and NOX

controls that covered much of their 

inventory. However, the upwind States 

in the region generally had not done so 

(except to the extent of their ozone 

nonattainment areas). In this context, 

EPA considered it reasonable to impose 

an additional control burden on the 

upwind States. Air quality modeling 

showed that even with this additional 

level of upwind controls, residual 

nonattainment remained, so that further 

reductions from downwind and/or 

upwind areas would be necessary.

b. Regulatory Requirements 

After ascertaining the controls that 

qualified as highly cost effective, EPA 

developed a methodology for 

calculating the amount of NOX

emissions that each State was required 

to reduce on grounds that those 

emissions contribute significantly to 

nonattainment downwind. The total 

amount of required NOX emissions 

reductions was the sum of the amounts 

that would be reduced by application of 

highly cost-effective controls to each of 

the source categories for which EPA 

determined that such controls were 

available (63 FR 57378). 

The largest of these source categories 

was EGUs. The EPA determined the 

amount of reductions associated with 

EGU controls by applying the control 

rate that EPA considered to reflect 

highly cost-effective controls to each 

State’s EGU heat input. That heat input, 

in turn, was adjusted to reflect projected 

growth. 

Each affected State retained the 

authority to achieve the required level 

of reductions by implementing whatever 

controls on whatever sources it wished, 

and EPA determined that there were 

other source categories for which costeffective, if not highly cost-effective, 

controls were available (63 FR 57378). If 

the States chose to control EGUs, then 

the NOX SIP Call mandated certain 

requirements—including a statewide 

cap on EGU NOX emissions—but also 

made available an EPA-administered 

regionwide EGU allowance trading 

program that the States could choose to 

adopt. 

c. SIP Submittal and Implementation 

Requirements 

At the time EPA promulgated the NOX

SIP Call, States already had SIPs for the 

1-hour ozone NAAQS in place. In the 

NOX SIP Call, EPA determined that the 

1-hour SIPs for the affected States were 

deficient, and EPA called on these 

States, under CAA section 110(k)(5), to 

submit, within 12 months of 

promulgation of the NOX SIP Call, SIP 

revisions to cure the deficiency by 

complying with the NOX SIP Call 

25174 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

15By action dated January 18, 2000, EPA 

promulgated another rulemaking that was related to 

the NOX SIP Call, known as the section 126 Rule 

(65 FR 2675). The DC Circuit generally upheld this 

rule, although it remanded for better explanation 

the EGU heat input growth methodology. 

Appalachian Power Co. v. EPA. 249 F. 3d 1032 (DC 

Cir., 2001).

regulatory requirements. The EPA 

further required that the NOX SIP Callrequired controls be implemented as 

expeditiously as practicable. The EPA 

determined this date to be within 3 

years of the SIP submittal date (with 

that period extended to the beginning of 

the next ozone season), in light of the 

various constraints that EGUs would 

confront in implementing controls. 

For the SIPs due under the 8-hour 

ozone NAAQS, in the NOX SIP Call, 

EPA did not incorporate a section 

110(k)(5) SIP call, but instead required 

States to submit, under section 

110(a)(1)–(2), SIP revisions to fulfill the 

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

The EPA required these 8-hour ozone 

SIPs to be submitted—and the controls 

mandated therein to be implemented—

on the same schedule as the 1-hour 

SIPs. 

However, EPA stayed the 8-hour 

ozone requirements of the NOX SIP Call, 

due to litigation concerning the 8-hour 

ozone NAAQS. To date, EPA has not 

lifted that stay. 

3. Michigan v. EPA Court Case 

Petitioners brought legal challenges to 

various components of the NOX SIP 

Call’s analytical approach in the United 

States Court of Appeals for the District 

of Columbia Circuit, in Michigan v. 

EPA, 213 F.3d 663 (DC Cir., 2000), cert. 

denied, 532 U.S. 904 (2001). The Court 

upheld the essential features of the air 

quality modeling part of EPA’s 

approach, id. at 673; as well as EPA’s 

definition of ‘‘contribute significantly’’

to include the factor of highly costeffective controls, id. at 679. The Court 

did vacate or remand certain specific 

applications of EPA’s approach, and 

delayed the implementation date to May 

31, 2004. See, e.g., id. at 67, 681–85, 

692–94. In addition, in a subsequent 

case that reviewed separate EPA 

rulemakings making technical 

corrections to the NOX SIP Call, the DC 

Circuit remanded for a better 

explanation EPA’s methodology for 

computing the growth component in the 

EGU heat input calculation. 

Appalachian Power Co. v. EPA, 251 

F.3d 1026 (DC Cir., 2001).15

4. Implementation of the NOX SIP Call 

The court decisions left intact most of 

the NOX SIP Call requirements. All 

States subject to those requirements—

which EPA has termed the NOX SIP Call 

Phase I requirements—submitted SIPs 

incorporating them, and requiring 

control implementation by May 31, 

2004 or earlier. The EPA has approved 

those SIPs. 

The EPA responded to the DC 

Circuit’s EGU growth remand decisions 

through a Federal Register action that 

provided a more detailed explanation 

and other supporting information for the 

EGU growth methodology (67 FR 21868; 

May 1, 2002). The Court subsequently 

upheld that explanation. West Virginia

v. EPA, 362 F.3d 861 (DC Cir. 2004). In 

addition, by action dated April 21, 2004, 

EPA promulgated a rulemaking that 

responded to other remanded and 

vacated issues, and included the 

remaining requirements—termed the 

NOX SIP Call Phase II requirements—for 

the affected States (69 FR 21604).

B. How Does EPA Interpret the Clean 

Air Act’s Pollution Transport Provisions 

in Today’s Rule? 

1. CAIR Analytical Approach 

Today, EPA adopts much the same 

interpretation and application of section 

110(a)(2)(D) for regulating downwind 

transport of precursors of PM2.5 and

8-hour ozone as EPA adopted for the 

NOX SIP Call. We are adjusting some 

aspects of the NOX SIP Call analytic 

approach for various reasons, including 

the need to account for regulation of a 

different pollutant (PM2.5) with an 

additional precursor (SO2). 

a. Nature of Nonattainment Problem and 

Overview of Today’s Approach 

As described in section I, above, the 

interstate transport component of 

current nonattainment of the PM2.5 and 

8-hour ozone NAAQS is primarily 

confined to the eastern part of the 

country, although in an area that is 

larger, by several States, than the area 

that EPA focused on in the NOX SIP Call 

for only ozone. As described in section 

III, it is evident that local controls alone 

cannot be counted on to solve the 

nonattainment problems, although 

uncertainties remain in the state of 

knowledge of these nonattainment 

problems as well as the precise role 

interstate and local controls should 

play. As in the case of the NOX SIP Call, 

it is not reasonable to expect a local area 

to bear the entire burden of solving the 

air quality problems, even if doing so 

were technically possible. 

Turning to the interstate component 

of the nonattainment problems, as 

discussed in section III below, for PM2.5, 

we find sufficient information is 

available to address the adverse 

downwind impacts caused by SO2 and 

NOX, and to develop emissions 

reductions requirements for SO2 and 

NOX. However, we do not have 

sufficient information to address other 

precursors. As discussed in section III 

below, for 8-hour ozone, we reiterate the 

finding of the NOX SIP Call that NOX

emissions, and not VOC emissions, are 

of primary importance for interstate 

transport purposes. 

We interpret CAA section 110(a)(2)(D) 

to require SIPs in upwind States to 

eliminate the amounts of emissions that 

contribute significantly to downwind 

nonattainment or interfere with 

downwind maintenance. As described 

below, in today’s rule, EPA determines 

that upwind States’ emissions 

contribute significantly to 

nonattainment or interfere with 

maintenance of the PM2.5 NAAQS. 

To quantify the amounts of those 

emissions that contribute significantly 

to nonattainment, we primarily focus on 

the air quality factor reflecting the 

upwind State’s ambient impact on 

downwind nonattainment areas, and the 

cost factor of highly cost-effective 

controls. However, as with the NOX SIP 

Call, EPA also considers other factors, 

which serve to establish the broad 

context for applying the air quality and 

cost factors. Today, we adopt the 

formulation of those factors as described 

in the CAIR NPR, which has little 

conceptual difference from EPA’s 

application of those factors in the NOX

SIP Call. 

Discussion of issues relating to 

maintenance are found in section III 

below. 

b. Air Quality Factor 

i. PM2.5

With respect to the PM2.5 NAAQS, as 

described in section VI, we employed 

air quality modeling techniques to 

assess the impact of each upwind State’s 

entire inventory of anthropogenic SO2

and NOX emissions on downwind 

nonattainment and maintenance. For air 

quality and technical reasons described 

below, EPA determined that upwind 

SO2 and NOX emissions contribute 

significantly to nonattainment as of the 

year 2010. Therefore, EPA projected SO2

and NOX emissions to the year 2010, 

assuming certain required controls (but 

not controls required under CAIR), and 

then modeled the impact of those 

projected emissions (termed the base 

case inventory) on downwind PM2.5

nonattainment in that year.

As discussed in section III, we adopt 

today a threshold air quality impact of 

0.2 μg/m3, so that an upwind State with 

contributions to downwind 

nonattainment below this level would 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25175

16The second air quality factor described in the 

NOX SIP Call—the extent of downwind 

nonattainment—is reflected in the identification of 

downwind PM2.5 nonattainment areas, discussed 

elsewhere in today’s final action. The third air 

quality factor—the ambient impact of upwind 

emissions—is reflected in the threshold level.

not be subject to regulatory 

requirements, but a State with 

contributions at or higher than this level 

would be subject to further evaluation. 

Because of the inherent differences 

between the PM2.5 and ozone NAAQS, 

this threshold necessarily differs from 

the threshold chosen for the NOX SIP 

Call in terms of: (i) The metrics selected 

to evaluate the threshold, and (ii) the 

specific level of the threshold. Even so, 

the threshold EPA proposed for PM2.5 is 

generally consistent with the approach 

taken in the NOX SIP Call for the 

threshold level for ozone in that both 

are relatively low. This level reflects the 

fact that PM2.5 nonattainment, like 

ozone, is caused by many sources in a 

broad region, and therefore may be 

solved only by controlling sources 

throughout the region. As with the NOX

SIP Call, the collective contribution 

condition of PM2.5 air quality is 

reflected in the proposed relatively low 

threshold.16

The EPA determined that as of 2010, 

23 upwind States and the District of 

Columbia will have contributions to 

downwind PM2.5 nonattainment areas 

that are sufficiently high to meet the air 

quality factor of the transport test. 

ii. 8-Hour Ozone 

With respect to the 8-hour ozone 

NAAQS, we also employed, as 

described in section VI, air quality 

modeling techniques to assess the 

impact of each upwind State’s entire 

inventory of NOX and VOC emissions 

on downwind nonattainment. The EPA 

determined that upwind NOX emissions 

contribute significantly to 8-hour ozone 

nonattainment as of the year 2010. 

Therefore, EPA projected NOX

emissions to the year 2010, assuming 

certain required controls (but not 

controls required under CAIR), and then 

modeled the impact of those projected 

emissions (termed the base case 

inventory) on downwind 8-hour ozone 

nonattainment in that year. 

For the 8-hour ozone air quality 

factor, EPA employs the same threshold 

amounts and metrics that it used in the 

NOX SIP Call. That is, as described in 

section VI, emissions from an upwind 

State contribute significantly to 

nonattainment if the maximum 

contribution is at least 2 parts per 

billion, the average contribution is 

greater than one percent, and certain 

other numerical criteria are met.

The EPA determined that as of 2010, 

25 upwind States and the District of 

Columbia will have contributions to 

downwind nonattainment areas that are 

sufficiently high to meet the air quality 

factor of the transport test. 

c. Cost Factor 

The second major factor that EPA 

applies is the cost factor. As in the case 

of the NOX SIP Call, EPA interprets this 

factor as mandating emissions 

reductions in amounts that would result 

from application of highly cost-effective 

controls. We ascertain the level of costs 

as highly cost effective by reference to 

the cost effectiveness of recent controls. 

As we stated in the CAIR NPR, in 

determining the appropriate level of 

controls, we considered feasibility 

issues—as we did in the NOX SIP Call—

specifically, ‘‘the applicability, 

performance, and reliability of different 

types of pollution control technologies 

for different types of sources; * * * and 

other implementation costs of a 

regulatory program for any particular 

group of sources.’’ (See CAIR NPR, 69 

FR 4585.) 

As described in section IV, today we 

conclude that at present, EGUs are the 

only source category for which highly 

cost-effective SO2 and NOX controls are 

available. In making this determination, 

we examined what information is 

available concerning which source 

categories emit relatively large amounts 

of emissions, and what difficulties 

sources have in implementing controls. 

These criteria are similar to those 

considered in the NOX SIP Call. 

As discussed in section IV, for PM2.5, 

today’s action finalizes our proposal to 

identify as highly cost effective the 

dollar amount of cost effectiveness that 

falls near the low end of the reference 

range for both annual SO2 controls and 

annual NOX controls. We identify this 

level based on the overall context of the 

PM2.5 implementation program, 

discussed below. 

For upwind States affecting 

downwind 8-hour ozone nonattainment 

areas, we apply the cost factor for 

ozone-season NOX controls in much the 

same manner as for the NOX SIP Call, 

although some aspects of the analysis 

have been updated. The level of NOX

control identified as highly cost 

effective is more stringent than in the 

NOX SIP Call. 

d. Other Factors 

As with the NOX SIP Call, EPA 

considers other factors that influence 

the application of the air quality and 

cost factors, and that confirm the 

conclusions concerning the amounts of 

emissions that upwind States must 

eliminate as contributing significantly to 

downwind nonattainment. Specifically, 

as we stated in the CAIR NPR, ‘‘We are 

striving in this proposal to set up a 

reasonable balance of regional and local 

controls to provide a cost effective and 

equitable governmental approach to 

attainment with the NAAQS for fine 

particles and ozone.’’ (See 69 FR 4612.) 

In this manner, we broadly incorporate 

the fairness concept and relative-cost-ofcontrol (regional costs compared to local 

costs) concept that we generally 

considered in the NOX SIP Call. 

i. PM2.5 Controls 

For PM2.5, we promulgated the 

NAAQS in 1997, we issued designations 

of areas in December 2004 (70 FR 944; 

January 5, 2005), and we intend to 

promulgate implementation 

requirements during 2005. We project 

that by 2010, without CAIR or other 

controls not already adopted, 80 

counties in the CAIR region would be in 

nonattainment of the annual standard. 

Our state of knowledge is incomplete 

as to the best control regime to achieve 

attainment and maintenance of this 

NAAQS in individual areas, but we do 

know that transported SO2 and NOX

emissions are important contributors to 

PM2.5 nonattainment. In addition, we 

have concluded that available controls 

for at least the portion of these 

emissions from EGUs are feasible and 

relatively inexpensive on a cost-per-ton 

basis, and generate significant ambient 

benefits. These ambient benefits include 

bringing many areas into attainment and 

decreasing PM2.5 levels in the rest of the 

nonattainment areas. Moreover, 

available information indicates that 

local controls are likely to be relatively 

more expensive on a per-ton basis, and 

will not reduce emissions sufficiently to 

bring many areas into attainment. 

In light of this information, we plan 

to proceed by requiring the level of 

regulatory control specified today on 

upwind SO2 and NOX emissions. We 

consider today’s action to be both 

prudent and effective within the 

circumstances of the developing PM2.5

implementation program. This action is 

one of the initial steps in implementing 

the PM2.5 NAAQS. States, localities, and 

Tribes, as well as EPA, will continue to 

evaluate the efficacy of local controls. 

Finally, as discussed in section VI, air 

quality modeling confirms that these 

regional controls are not more than is 

necessary for downwind areas to attain. 

This overall plan is well within the 

ambit of EPA’s authority to proceed 

with regulation on a step-by-step basis. 

The time frame for section 110(a)(2)(D) 

SIPs, described in section VII, makes 

clear that EPA has the authority to 

25176 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

establish the upwind reduction 

obligations before having full 

information about how best to achieve 

attainment goals, including having full 

information about downwind control 

costs and the efficacy of downwind 

control measures.

ii. Ozone Controls 

The EPA determined the level of 

required NOX reductions for purposes of 

8-hour ozone transport through much 

the same process as for purposes of 

PM2.5 transport. 

e. Regulatory Requirements 

i. Annual SO2 and NOX Emissions 

Reductions 

Although EPA determined that 

upwind emissions will contribute 

significantly to both PM2.5

nonattainment and 8-hour ozone 

nonattainment in 2010, the amount of 

requisite emissions controls cannot 

feasibly be implemented by 2009 for 

NOX, or 2010 for SO2. Instead, EPA has 

determined to implement the reductions 

in two phases for each pollutant: 2009 

for NOX, and 2010 for SO2 initially, with 

lower caps for both in 2015. 

As described in section IV, EPA 

evaluated the cost of emissions 

reductions under consideration against 

the level of highly cost-effective 

controls. Through a multi-year process 

involving studies and other regulatory 

and legislative efforts, as well as 

involvement with citizen, industry, and 

State stakeholders, EPA arrived at an 

amount of SO2 emissions reductions for 

evaluation purposes for the CAIR 

region. The EPA ascertained the costs of 

these reductions and today determines 

that they should be considered highly 

cost effective. These amounts 

correspond to reducing Title IV SO2

allowances for utilities by 65 percent in 

2015 and 50 percent in 2010 in CAIR 

States. 

As described in section V, EPA 

further determined that these emissions 

reductions requirements should be 

allocated to the States in proportion to 

the title IV SO2 allowances allocated 

under the CAA to their EGUs. This 

approach is consistent with the system 

Congress established for allocating title 

IV allowances and facilitates 

implementation of the SO2 interstate 

trading program. 

For annual NOX emissions, EPA 

determined a target regionwide amount 

of both emissions reductions and the 

EGU budget by multiplying current heat 

input by emission rates of 0.125 lb/

mmBtu and 0.15 lb/mmBtu for 2015 and 

2010, respectively. The EPA then 

evaluated those amounts through the 

Integrated Planning Model (IPM), which 

indicated the associated amounts of heat 

input and emission rates projected for 

those years. The IPM indicated that the 

amounts of heat input for 2015 and 2010 

were higher than current heat input (in 

light of the increased electricity demand 

for 2015 and 2010), and that the 

emissions rates were lower than 0.125 

lb/mmBtu (2015) and 0.15 lb/mmBtu 

(2010). The IPM calculated the costs to 

achieve those emissions reductions and 

EGU budget (assuming EGU controls) by 

2015 and 2009, which costs EPA 

determined were highly cost effective 

and feasible, respectively. The EPA used 

this same approach to determine the 

seasonal budget for NOX reductions for 

purposes of the ozone standard. 

As described in section V, we 

allocated this regionwide amount to the 

individual States in accordance with 

their average heat input from EGUs both 

subject to and not subject to title IV. We 

adjusted heat input for type of fuel used. 

The EPA believes that this method is a 

reasonable indicator of each State’s 

appropriate share of the requirements. 

This method differs from what EPA 

used in the NOX SIP Call, which relied 

on State-specific projections of growth 

in heat input. 

We require implementation of the 

PM2.5 and 8-hour ozone reductions in 

two phases, in 2009 and 2015. As 

discussed in section IV, these dates are 

the most expeditious that are 

practicable—the same standard for the 

implementation period in the NOX SIP 

Call—based on engineering and 

financial factors; the performance and 

applicability of control measures; and 

the impact of implementation on, in the 

case of EGUs, electricity reliability. The 

EPA considered these same factors in 

determining the implementation period 

for the NOX SIP Call requirements, but 

factual differences lead to the two-phase 

approach adopted in today’s action.

As discussed in section VII, each 

upwind State may achieve the required 

reductions by regulating any sources of 

SO2 or NOX that it wishes. However, if 

the State chooses to regulate certain 

source categories (such as EGUs), it 

must comply with certain requirements 

(such as capping EGU emissions), and it 

may take advantage of certain 

opportunities (such as participation in 

the EPA-administered EGU cap and 

trade program). Some aspects of these 

requirements and the cap and trade 

program differ from those in the NOX

SIP Call, as explained in section VIII. 

However, like the NOX SIP Call, the 

State may allow sources to opt in to the 

CAIR trading program, as described in 

section VIII. 

f. SIP Submittal and Implementation 

Requirements 

Today EPA requires that the PM2.5

and 8-hour ozone SIPs be submitted 

within 18 months of promulgation of 

today’s action. This period is 6 months 

longer than the SIPs due under the NOX

SIP Call. This difference is due to the 

fact that PM2.5 implementation is only 

now beginning, and it makes sense to 

keep the NOX SIPs due under the 8-hour 

ozone requirements on the same 

schedule as the NOX and SO2 SIPs due 

under the PM2.5 requirements. 

2. What Did Commenters Say and What 

Is EPA’s Response? 

Many of the comments on today’s 

action concern various aspects of EPA’s 

analytical approach. Most of those 

comments are discussed elsewhere in 

today’s action. Comments on the most 

basic elements of EPA’s approach are 

discussed here. 

a. Aspects of Contribute-Significantly 

Test 

i. Date for Evaluation of Downwind 

Impacts 

Comment: Some commenters took 

issue with EPA’s approach of 

determining the upwind State’s air 

quality impact on downwind areas by 

modeling only the State’s 2010 base case 

emissions (that is, projected 2010 

emissions before the 2010 CAIR 

controls). These commenters stated that 

although evaluating the upwind State’s 

base case emissions in 2010 might 

indicate whether that State’s air quality 

impact on downwind areas is 

sufficiently high to justify imposition of 

the 2010 (Phase I) controls, it does not 

justify imposition of the 2015 (Phase II) 

controls. Rather, according to the 

commenters, EPA should conduct 

further air quality modeling that 

evaluates the upwind State’s 2015 base 

case emissions—taking into account the 

CAIR 2010 controls but not the CAIR 

2015 controls—to determine whether 

the State continues (even after 

imposition of the CAIR 2010 controls) to 

have a sufficient downwind ambient 

impact to justify the 2015 controls. 

Commenters added that, in their view, 

PM2.5 precursors generally were 

decreasing after 2010, the PM2.5

nonattainment problem was generally 

diminishing as well, and the 

contribution of some upwind States to 

downwind areas was relatively small. 

These facts, according to the 

commenters, indicated that some 

upwind States should not be subject to 

the 2015 reductions requirement. 

Some commenters stated, more 

broadly, that the threshold contribution 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25177

level selected by EPA should be 

considered a floor, so that upwind 

States should be obliged to reduce their 

emissions only to the level at which 

their contribution to downwind 

nonattainment does not exceed that 

threshold level. 

Response: The EPA views the CAIR 

emission reduction requirements as a 

single action, but one that cannot be 

fully implemented in 2009 (for NOX) or 

2010 (for SO2), and must instead be 

partially deferred until 2015, solely for 

reasons of feasibility. Under these 

circumstances, EPA does not believe it 

appropriate to re-evaluate the 2015 

component, as commenters have 

suggested. 

Under EPA’s approach, which mirrors 

that of the NOX SIP Call, EPA projects, 

for each upwind State, SO2 and NOX

inventories, as of 2010, taking into 

account controls required under other 

CAA provisions and controls adopted 

by State and local agencies. The EPA 

then uses air quality modeling 

techniques to determine the impact of 

these emissions on downwind air 

quality. The EPA then requires upwind 

States whose emissions have a 

sufficiently high impact to eliminate the 

amount of their emissions that could be 

eliminated through application of 

highly cost-effective controls. These 

emissions reductions must be 

implemented as expeditiously as 

practicable. Were it feasible to 

implement all the reductions by 2009 

(for NOX) or 2010 (for SO2), EPA would 

so require. Because part of the emissions 

reductions cannot feasibly be 

implemented until 2015, EPA is 

requiring today’s two-phase approach. 

This analytic method is the same as for 

the NOX SIP Call, except that in that 

rulemaking all of the required emissions 

reductions could feasibly be 

implemented in one phase. 

As in the case of the NOX SIP Call, 

EPA takes the view that once a State’s 

emissions are determined to contribute 

to downwind nonattainment by at least 

a threshold amount, then the upwind 

State should reduce its emissions by the 

amount that would result from 

implementation of highly cost-effective 

controls. This approach is justified by 

the benefits of reducing the upwind 

contribution to downwind 

nonattainment, coupled with the 

relatively low costs. However, EPA does 

consider the ambient impacts of the 

required emissions reductions. For 

today’s action, air quality modeling 

indicates that the regionwide emissions 

reductions do not reduce PM2.5 levels 

beyond what is needed for attainment 

and maintenance. (See also section III 

below.) Most important for present 

purposes, as long as the controls yield 

downwind benefits needed to reduce 

the extent of nonattainment, the 

controls should not be lessened simply 

because they may have the effect of 

reducing the upwind State’s 

contribution to below the initial 

threshold.

The DC Circuit, in upholding the NOX

SIP Call, rejected similar arguments to 

those raised by commenters (Michigan

v. EPA, 213 F.3d at 679). In the NOX SIP 

Call rulemaking, commenters argued 

that EPA’s analytic approach to the 

‘‘contribute significantly’’ test was 

flawed because it meant that States with 

different impacts downwind would 

nevertheless have to implement the 

same level of controls (i.e., those that 

were highly cost effective). Commenters 

urged EPA to recast its approach by 

limiting an upwind State’s emissions 

reductions to the point at which the 

remaining emissions no longer caused a 

downwind ambient impact above the 

threshold level for significance. 

(‘‘Responses to Significant Comments 

on the Proposed Finding of Significant 

Contribution and Rulemaking for 

Certain States in the Ozone Transport 

Assessment Group (OTAG) Region for 

Purposes of Reducing Regional 

Transport of Ozone (62 FR 60318; 

November 7, 1997 and 63 FR 25902; 

May 11, 1998),’’ U.S. E.P.A. (September 

1998), Docket Number A–96–56–VI–C–

1, at 213–16.) 

Petitioners challenging the NOX SIP 

Call in Michigan v. EPA used the same 

arguments to contend that EPA’s 

analytic approach in the NOX SIP Call 

was arbitrary and capricious. The Court 

dismissed these arguments, stating:

* * * EPA required that all of the covered 

jurisdictions, regardless of amount of 

contribution, reduce their NOX by an amount 

achievable with ‘‘highly cost-effective 

controls.’’ Petitioners claim that EPA’s 

uniform control strategy is irrational. * * * 

[T]hey observe that where two states differ 

considerably in the amount of their 

respective NOX contributions to downwind 

nonattainment, under the EPA rule even the 

small contributors must make reductions 

equivalent to those achievable by highly costeffective measures. This of course flows 

ineluctably from the EPA’s decision to draw 

the ‘‘significant contribution’’ line on a basis 

of cost differentials. Our upholding of that 

decision logically entails upholding this 

consequence.

(Michigan v. EPA, 213 F.3d at 679.)

Thus, the Court approved EPA’s 

approach of requiring the same control 

level on all affected States, without 

concern as to the arguably inconsistent 

ambient impacts that may result. By the 

same token, in today’s action, EPA’s 

approach should be accepted 

notwithstanding that the upwind 

controls could, at least in theory, result 

in an ambient impact that is below the 

initial threshold. For this reason, there 

is no basis to conduct a separate 

evaluation of the 2015 controls. 

ii. Residual Nonattainment 

Comment: A commenter expressed 

concern that too many areas will remain 

out of attainment for the PM2.5 and 8-

hour ozone NAAQS even after 

implementation of the CAIR rule. 

Response: Section 110(a)(2)(D) of the 

CAA requires upwind States to prohibit 

the amount of emissions that contribute 

significantly to downwind 

nonattainment, but does not require the 

upwind States to prohibit sufficient 

emissions to assure that the downwind 

areas attain. Rather, downwind areas 

continue to bear the responsibility of 

addressing remaining nonattainment. 

iii. Relationship of Reductions to 

Attainment Dates 

Comment: Some commenters, who 

viewed the CAIR as imposing unduly 

light obligations on upwind States, 

argued that because States with 

nonattainment areas must develop SIPs 

that provide for attainment regardless of 

the cost of the requisite controls, and 

because the courts have viewed 

attainment deadlines as central to the 

CAA, EPA should require that upwind 

emissions contributing to downwind 

nonattainment must be eliminated by 

the downwind attainment dates, and not 

later. 

Other commenters, who viewed the 

CAIR as imposing unduly heavy 

obligations on upwind States, argued 

that EPA had no authority to require 

upwind emissions reductions after the 

downwind attainment dates because by 

that time, the upwind emissions were 

no longer contributing to 

nonattainment. These commenters 

further argued that EPA has no authority 

to accelerate the emissions reductions 

because the controls could not feasibly 

be implemented by an earlier date. 

Response: We note first that part of 

this issue is moot since EPA is requiring 

NOX controls in 2009, within the 

statutory time periods for attainment. 

With respect to remaining issues, EPA’s 

interpretation and application of the 

‘‘contribute significantly to 

nonattainment’’ standard of section 

110(a)(2)(D) is not necessarily 

constrained by the downwind area’s 

attainment date in either manner 

suggested by the commenters. 

First, although it is true that the 

nonattainment area requirements and 

deadlines in CAA title I, part D, mean 

that the downwind area must achieve 

attainment by its attainment date 

25178 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

without regard to the feasibility of 

emissions reductions from sources in 

that nonattainment area, section 

110(a)(2)(D) by its terms does not apply 

those constraints to sources in the 

upwind States. Rather, EPA’s 

interpretation of the ‘‘contribute 

significantly to nonattainment’’

standard—which incorporates 

feasibility considerations in determining 

the implementation period for the 

upwind emissions controls—continues 

to apply.

Often, upwind emissions reductions 

affect at least several downwind areas 

with different attainment dates. The 

EPA does not read section 110(a)(2)(D) 

to require that the pace of upwind 

reductions be controlled by the earliest 

downwind attainment date. Rather, EPA 

views the pace of reductions as being 

determined by the time within which 

they may feasibly be achieved. In some 

cases, upwind sources are themselves in 

a nonattainment area that has a longer 

attainment date than the downwind 

area, and it may not be feasible for those 

upwind sources to implement 

reductions prior to the downwind 

attainment date. Therefore, the upwind 

emissions may be projected to continue 

to affect adversely nonattainment in the 

downwind area even after the 

downwind attainment date, in the 

manner described above. Further, 

emissions reductions after the 

attainment date may be important to 

prevent interference with maintenance 

of the standards. 

The CAIR will achieve substantial 

reductions in time to help many 

nonattainment areas attain the standards 

by the applicable attainment dates. The 

design of the SO2 program, including 

the declining caps in 2010 and 2015 and 

the banking provisions, will steadily 

reduce SO2 emissions over time, 

achieving reductions in advance of the 

cap dates; and the 2009 and 2015 NOX

reductions will be timely for many 

downwind nonattainment areas. 

Although many of today’s 

nonattainment areas will attain before 

all the reductions required by CAIR will 

be achieved, it is clear that CAIR’s 

reductions will still be needed through 

2015 and beyond. The EPA has 

determined that each upwind State’s 

2010 and 2015 emissions reductions 

will be necessary because, for purposes 

of both PM2.5 and 8-hour ozone, we 

reasonably predict that a downwind 

receptor linked to that upwind State 

will either: (i) Remain in nonattainment 

and continue to experience significant 

contribution to nonattainment from the 

upwind State’s emissions; or (ii) attain 

the relevant NAAQS but later revert to 

nonattainment due, for example, to 

continued growth of the emissions 

inventory. This is discussed in detail in 

section III below. 

iv. Factors To Consider in Future 

Rulemaking 

In the January and June CAIR 

proposals, we discussed regional control 

requirements and budgets based on a 

showing of ‘‘significant contribution’’ by 

upwind States to nonattainment in 

downwind States (69 FR at 4611–13, 

32720). The CAA section 110(a)(2)(D), 

which provides the authority for CAIR, 

states among other things that SIPs must 

contain adequate provisions prohibiting, 

consistent with the CAA, sources or 

other types of emissions activity within 

a State from emitting pollutants in 

amounts that will ‘‘contribute 

significantly to nonattainment in, or 

interfere with maintenance by, any 

other State with respect to’’ the NAAQS. 

In the CAIR, EPA has interpreted 

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

certain States reduce emissions by 

specified amounts, and has determined 

those amounts based on the availability 

of highly cost effective controls for 

identified source categories. Following 

this interpretation, EPA has calculated 

CAIR’s emissions reduction 

requirements based on the availability 

of highly cost-effective reductions of 

SO2 and NOX from EGUs in States that 

meet EPA’s proposed inclusion criteria. 

One approach cited in the January 

2004 CAIR proposal for ensuring that 

both the air quality component and the 

cost effectiveness component of the 

section 110 ‘‘contribute significantly’’

determination is met, is to consider a 

source category’s contribution to 

ambient concentrations above the 

attainment level in all nonattainment 

areas in affected downwind states. Id. In 

the June supplemental proposal, we 

requested comment on a further 

refinement of this concept—i.e., 

whether a source category should be 

included in a broad regional rule 

promulgated pursuant to section 

110(a)(2)(D) only if the proposed level of 

additional control of that category 

would meet a specified threshold. 

Under that approach, EPA said it might 

determine, for example, that in the 

context of a broad multi-state SIP call, 

emissions reductions from particular 

source category are ‘‘highly cost 

effective’’ only if emissions reductions 

from that source category would result 

in at least 0.5 percent of U.S. counties 

and/or parishes coming into attainment 

with a NAAQS. The EPA noted that, 

given the number of counties and 

parishes in the United States, this 

requirement would be met if at least 16 

counties were brought into attainment 

with a NAAQS as a result of the 

proposed level of control on a particular 

source category. 

The Agency received comments both 

supporting and opposing the adoption 

of this test as a part of the ‘‘highly cost 

effective’’ component of the ‘‘contribute 

significantly’’ requirement of CAA 

section 110(a)(2)(d). Commenters 

supporting this test asserted that it was 

consistent with the CAA’s overall focus 

on State, rather than federal, control 

over which sources should be regulated, 

and also was consistent with ensuring 

that broad, regional SIP calls, such as 

the one at issue in this case, focus only 

on source categories the control of 

which will result in substantial overall 

improvements in air quality. 

Commenters opposing this screen with 

respect to the application of section 

110(a)(2)(D) asserted, in general, that the 

test would be inconsistent with the 

analysis used by the Agency in the NOX

SIP call and with the language of section 

110(a)(2)(D).

We have determined that it is not 

appropriate to adopt a statutory 

interpretation embodying a ‘‘bright line’’

rule that 0.5 percent of the U.S. counties 

and/or parishes must be brought from 

nonattainment into attainment from 

controlling emissions from a particular 

source category, in order for reductions 

from that source category to be 

considered highly cost effective. We 

continue to believe, however, that broad 

multi-state rules under section 

110(a)(2)(D), such as the one we are 

finalizing today, should play a limited 

role under the CAA and must be 

justified by a careful evaluation of the 

air quality improvement that will result 

from the controls under consideration. 

Therefore, we intend to undertake any 

future broad, multi-state rulemakings 

under section 110(a)(2)(D) regarding 

transported emissions only when, as 

here, they produce substantial air 

quality benefits across a broad area and 

have beneficial air quality impacts on a 

significant number of downwind 

nonattainment areas, including bringing 

many areas into attainment. We do not 

at this time anticipate the need for any 

such rulemakings in the future. We 

believe that today’s action, coupled with 

current and upcoming national rules 

and local or subregional programs 

adopted by States, will be sufficient to 

address the remaining nonattainment 

problems. 

In evaluating whether to undertake 

national or regional transport 

rulemakings in the future, we believe it 

is not only appropriate but necessary to 

consider the effectiveness of the 

proposed emissions reductions in 

improving downwind air quality. We 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25179

17More complete discussions of the key scientific 

underpinnings that form the basis of these 

conclusions in the proposal and the discussion of 

these issues in this seciton of today’s notice can be 

found in the recently completed EPA Criteria 

Document (USEPA, National Center for 

Environmental Assessment, Air Quality Criteria for 

Particulate Matter, October 2004) and the NARTSO 

assessment of fine participles (NARSTO, Particulate 

Matter Science for Policy Makers—A NARSTO 

ASSESSMENT, February 2003).

believe it will be reasonable to initiate 

a broad multi-state rulemaking under 

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

determination that particular emissions 

reductions are highly cost effective only 

when those reductions will bring a 

significant number of downwind areas 

into attainment. In adopting this 

approach for determining whether a 

future broad, multi-state SIP call is 

appropriate, we note that other CAA 

mechanisms, such as SIP disapproval 

authority and State petitions under 

section 126, are available to address 

more isolated instances of the interstate 

transport of pollutants. 

The EPA projects that control of SO2

and NOX through CAIR will bring 72 

counties into attainment with the PM2.5

and ozone NAAQS. The total number 

represents approximately 3 percent of 

the counties/parishes in the United 

States, and is clearly a significant 

number of areas. What will be 

considered a significant number of areas 

in any future cases will need to be 

determined on a case-by-case basis. 

III. Why Does This Rule Focus on SO2

and NOX, and How Were Significant 

Downwind Impacts Determined? 

This section discusses the basis for 

EPA’s decision to require reductions in 

upwind emissions of SO2 and NOX to 

address PM2.5 transport and to require 

reductions in upwind emissions of NOX

to address ozone-related transport. In 

addition, this section discusses how 

EPA determined which States are 

subject to today’s rule because their 

sources’ emissions will significantly 

contribute to nonattainment of the PM2.5

or 8-hour ozone standards, or interfere 

with maintenance of those standards, in 

downwind States. The EPA assessed 

individual upwind States’ ambient 

impacts on downwind States and 

established a threshold value to identify 

those States whose impact constitutes a 

significant contribution to air quality 

violations in the downwind States. The 

EPA used air quality modeling of 

emissions in each State to estimate the 

ambient impacts. The technical issues 

concerning the modeling platform and 

approach are discussed in section VI, 

Air Quality Modeling Approach and 

Results. Also, EPA considered the 

potential for upwind state emissions to 

interfere with maintenance of the PM2.5

and 8-hour ozone NAAQS in downwind 

areas.

A. What Is the Basis for EPA’s Decision 

To Require Reductions in Upwind 

Emissions of SO2 and NOX To Address 

PM2.5 Related Transport? 

1. How Did EPA Determine Which 

Pollutants Were Necessary To Control 

To Address Interstate Transport for 

PM2.5? 

a. What Did EPA Propose Regarding 

This Issue in the NPR? 

Section II of the January 2004 

proposal summarized key scientific and 

technical aspects of the occurrence, 

formation, and origins of PM2.5, as well 

as findings and observations relevant to 

formulating control approaches for 

reducing the contribution of transport to 

fine particle problems (69 FR 4575–87). 

Key concepts and provisional 

conclusions drawn from this discussion 

can be summarized as follows: 17

(1) Fine particles (measured as PM2.5

for the NAAQS) consist of a diverse 

mixture of substances that vary in size, 

chemical composition, and source. The 

PM2.5 includes both ‘‘primary’’ particles 

that are emitted directly to the 

atmosphere as particles, and 

‘‘secondary’’ particles that form in the 

atmosphere through chemical reactions 

from gaseous precursors. The major 

components of fine particles in the 

Eastern U.S. can be grouped into five 

categories: carbonaceous material 

(including both primary and secondary 

organic carbon and black carbon), 

sulfates, nitrates, ammonium, and 

crustal material, which includes 

suspended dust as well as some other 

directly emitted materials. The major 

gaseous precursors of PM2.5 include 

SO2, NOX, ammonia (NH3), and certain 

volatile organic compounds. 

(2) Examination of urban and rural 

monitors indicate that in the Eastern 

U.S., sulfates, carbonaceous material, 

nitrates, and ammonium associated with 

sulfates and nitrates are typically the 

largest components of transported 

PM2.5, while crustal material tends to be 

only a small fraction. 

(3) Atmospheric interactions among 

particulate ammonium sulfates and 

nitrates and gas phase nitric acid and 

ammonia vary with temperature, 

humidity, and location. Both ambient 

observations and modeling simulations 

suggest that regional SO2 reductions are 

effective at reducing sulfate and 

associated ammonium, and, therefore, 

PM2.5. Under certain conditions 

reductions in particulate ammonium 

sulfates can release ammonia as a gas, 

which then reacts with gaseous nitric 

acid to form nitrate particles, a 

phenomenon called ‘‘nitrate 

replacement.’’ In such conditions SO2

reductions would be less effective in 

reducing PM2.5, unless accompanied by 

reductions in NOX emissions to address 

the potential increase in nitrates. 

(4) Reductions in ammonia can 

reduce the ammonium, but not the 

sulfate portion of sulfate particles. The 

relative efficacy of reducing nitrates 

through NOX or ammonia control varies 

with atmospheric conditions; the 

highest particulate nitrate 

concentrations in the East tend to occur 

in cooler months and regions. At 

present, our knowledge about sources, 

emissions, control approaches, and 

costs is greater for NOX than for 

ammonia. Existing programs to reduce 

NOX from stationary and mobile sources 

are well underway. From a chemical 

perspective, as NOX reductions 

accumulate relative to ammonia, the 

atmospheric chemical system would 

move towards an equilibrium in which 

ammonium nitrate reductions become 

more responsive to further NOX

reductions relative to ammonia 

reductions. 

(5) Much less is known about the 

sources of regional transport of 

carbonaceous material. Key 

uncertainties include how much of this 

material is due to biogenic as compared 

to anthropogenic sources, and how 

much is directly emitted as compared to 

formed in the atmosphere. 

(6) Observational evidence suggests 

that the substantial reductions in SO2

emissions in the eastern U.S. since 1990 

have indeed caused observed reductions 

in PM2.5 sulfate. The relatively small 

historical reductions in NOX emissions 

do not allow observations to be used 

similarly to test the effectiveness of NOX

reductions. 

Based on the understanding of current 

scientific and technical information, as 

well as EPA’s air quality modeling, as 

summarized in the January 30 proposal, 

EPA concluded that it was both 

appropriate and necessary to focus on 

control of SO2 and NOX emissions as the 

most effective approach to reducing the 

contribution of interstate transport to 

PM2.5. 

The EPA proposed not to control 

emissions that affect other components 

of PM2.5, noting that ‘‘current 

information relating to sources and 

controls for other components identified 

25180 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

18R. J. Klemm, et al., ‘‘Daily Mortality and Air 

Pollution in Atlanta: Two Year of Data from ARIES’’

(accepted, Inhalation Toxicology).

19USEPA, National Center for Environmental 

Assessment, Air Quality Criteria for Particulate 

Matter, October 2004.

in transported PM2.5 (carbonaceous 

particles, ammonium, and crustal 

materials) does not, at this time, provide 

an adequate basis for regulating the 

regional transport of emissions 

responsible for these PM2.5

components.’’ (69 FR 4582). For all of 

these components, the lack of 

knowledge of and ability to quantify 

accurately the interstate transport of 

these components limited EPA’s ability 

to include these components in this 

rule. 

b. How Does EPA Address Public 

Comments on Its Proposal To Address 

SO2 and NOX Emissions and Not Other 

Pollutants?

i. Overview of Comments on This Issue 

A large number of commenters 

including states, affected industries, 

environmental groups, academics, and 

other members of the public agreed with 

EPA’s proposal to require cost-effective 

multipollutant reductions of SO2 and 

NOX to address interstate transport 

contributions to PM2.5 problems. Fewer 

commenters who supported controlling 

SO2 and NOX commented on inclusion 

of additional pollutants, but several also 

agreed that it would be premature at this 

time to require control of emissions of 

other chemical components and 

precursors to address such transport. 

These commenters suggested that SO2

and NOX emissions from EGUs and 

other sources indeed contribute 

significantly to downwind PM2.5. They 

argued that control of other components 

is premature because of a lack of 

knowledge, either about the interstate 

contributions of other components or of 

control measures for these components. 

Generally, EPA accepts and agrees with 

these conclusions. 

A number of commenters disagreed to 

varying degrees with part or all of EPA’s 

proposed focus on SO2 and NOX. The 

main points raised by these commenters 

can be grouped as follows: 

(1) The focus on SO2 and NOX is not 

appropriate because sulfates and 

nitrates may not be (or are not) the most 

important determinants of the health 

effects of PM2.5. 

(2) The EPA should mandate, or at 

least permit, states to control other 

precursors and particle emissions in 

addition to, or instead of, SO2 and NOX. 

Commenters sometimes made specific 

recommendations with respect to 

additional pollutants, including 

carbonaceous (including organic) 

particles and precursors, ammonia, and 

other direct emissions, including crustal 

material. 

(3) The focus on SO2 may be 

appropriate, but the basis for requiring 

NOX control is not clear. 

ii. Summary of EPA’s Response to the 

Major Comments on This Issue 

The following subsections summarize 

both key comments and EPA’s 

responses organized by the major 

categories outlined above. As noted in 

Section I, EPA has developed and 

placed in the rulemaking docket a 

detailed response to these and other 

public comments. 

(a) SO2 and NOX May Be Less Important 

to Health Than Other Transport-Related 

Components 

Comment: Several commenters argued 

that the proposed focus on SO2 and NOX

was premature, citing the potential for 

differential toxicity of various PM2.5

components, and in some cases 

advancing evidence (e.g., the Electric 

Power Research Institute Aerosol 

Research and Inhalation Studies 

[ARIES]) 18 that other components such 

as organic particles appear to be more 

responsible for health effects of particles 

than sulfates and nitrates. Several 

argued that the relative contribution of 

components to health impacts is an 

important uncertainty that should be 

researched more carefully before 

proposing to control only SO2 and NOX.

Response: Today’s rulemaking 

establishes requirements for SIP 

submissions under section 110(a)(2)(D). 

Those SIP submissions must prohibit 

emissions that contribute significantly 

to nonattainment of a NAAQS in a 

downwind State. The EPA determined 

in the 1997 rulemaking promulgating 

the PM2.5 NAAQS that specified levels 

of PM2.5 adversely affect human health, 

and that sulfates and nitrates are 

components of PM2.5 (62 FR 38652, July 

18, 1997). SO2 and NOX, in turn, are 

precursors to fine particulate sulfates 

and nitrates. Comments that sulfates 

and nitrates do not cause adverse health 

effects are more appropriately raised in 

the context of past or ongoing reviews 

of the PM NAAQS. Because today’s 

action forms part of implementing and 

not establishing the PM NAAQS, 

comments relating to the evidence 

supporting or not supporting health 

effects of all or portions of pollutants 

regulated by the PM2.5 NAAQS are not 

germane to this rulemaking.

Nevertheless, we discuss briefly 

EPA’s current response regarding the 

contributions of different components of 

PM2.5 to health effects. In establishing 

the current PM2.5 NAAQS, EPA found 

that there was ample evidence to 

associate various health effects with the 

measured mass concentration of 

particles smaller than a nominal 2.5 

micrometers (um), termed PM2.5. The 

EPA recognizes that the toxicity of 

different chemical components of PM2.5

may vary, and that the observed effects 

may be the result of the mixture of 

particles and gases. While research is 

underway to better identify whether 

some chemical components are more 

responsible for health effects than 

others, results now available from such 

research are limited and inconclusive. A 

number of studies included in the 

recent EPA PM criteria document 19

have found effects to be associated with 

one or more of the major components 

and sources of PM2.5, including sulfates, 

nitrates, organic materials, PM2.5 mass, 

coal combustion, and mobile sources. 

The criteria document concludes that 

these studies suggest that many different 

chemical components of fine particles 

and a variety of different types of source 

categories are all linked to premature 

mortality and other serious health 

effects, either independently or in 

combinations, but that it is not possible 

to reach clear conclusions about 

differential effects of PM components. 

Accordingly, individual studies or 

groups of studies such as ARIES cannot 

be used to single out any particular 

component of PM2.5 as wholly 

responsible (or not at all responsible) for 

the array of health effects that have been 

found to be associated with various 

chemical and mass indicators of fine 

particles. Other Federal agencies and 

EPA continue to promote and support 

the epidemiological and toxicological 

studies needed to better understand the 

effects of different chemical components 

and different size particles on health 

effects.

In the meantime, EPA believes that, 

given the substantial evidence of 

significant health effects of fine 

particles, it is important to move 

forward expeditiously to address both 

transported and local sources of all the 

major components of fine particles in an 

effort to implement and attain the PM2.5

standards. Today’s rule is focused on 

the contribution of interstate transport 

of nitrate and sulfates to PM2.5 in 

nonattainment areas. However, EPA has 

already adopted other rules that are 

reducing emissions and exposures to 

these and other major components of 

fine particles on a national, regional, 

and local basis. Recent national mobile 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25181

20 V. Rao, N. Frank, A. Rush, F. Dimmick. 

Chemical Speciation of PM2.5 in Urban and Rural 

Area, in The Proceedings of the Air & Waste 

Management Association Symposium on Air 

Quality Measurement Methods and Technology, 

San Francisco, November 13–1, 2002.

21 Jang, M; Czoschke, N.M.; Lee, S.: Kamens, R.M., 

Heterogeneous Atmospheric Aerosol Production by 

Acid-Catalzyed Particle Phase Reactions, Science, 

2002, 298: 814–817.

22Battye, W., V.P. Aneja, and P.A. Roelle, 

Evaluation and improvement of ammonia emissions 

inventories, Atmospheric Environment, 2003, 37: 

3873–3883.

23As pointed out by one commenter, a 

hypothetical new program resulting in major 

regional reductions of ammonia would reduce the 

effectiveness of NOX controls. However, given the 

uncertainties in emissions, the dispersed nature of 

ammonia sources and the lack of present controls, 

an effort to develop a new regional ammonia 

program would likely take significantly longer than 

the additional NOX reductions EPA is adopting 

today.

rules and programs, in particular, have 

focused on carbonaceous materials 

emitted from gasoline and both highway 

and non-road diesel powered mobile 

sources (65 FR 6698; 66 FR 5002; 69 FR 

38958). States with nonattainment areas 

will also be required to address local 

sources of PM2.5 in order to meet 

progress and attainment requirements. 

Together, the collective effect of these 

programs ensures a balanced approach 

to reducing all of the major components 

of PM2.5 from transported and local 

sources. 

(b) Inclusion of Other PM2.5 Precursors 

and Components 

Comment: A number of commenters 

recommended that EPA either mandate 

or at least permit controls on the 

emissions that cause interstate transport 

of other components of PM2.5, in 

addition to or as a substitute for, SO2

and NOX controls. Several commenters 

recommended that EPA include 

emissions reductions related to the 

components of PM2.5 other than sulfate 

and nitrate. While many commenters 

suggested addressing all of the 

important contributors to PM2.5, 

including those not regulated under this 

Rule, others highlighted only one or two 

additional components as most 

important to include. Of the PM2.5

components, direct emissions and 

precursors to carbonaceous PM2.5 and 

ammonia emissions were the omitted 

contributors most frequently discussed.

Some of these commenters argued 

that, by limiting the rule to SO2 and 

NOX and excluding other sources of 

ambient PM2.5, EPA would be limiting 

the choices that states have to address 

their downwind interstate transport 

contributions. These commenters 

argued that this limitation is contrary to 

the CAA, which generally gives states 

the discretion to choose their own 

emission control strategies. Commenters 

further asserted that the roles of other 

components in PM2.5 are sufficiently 

well understood that they should be 

included in state SIPs for PM2.5

transport, and could partially satisfy the 

PM2.5 reductions anticipated by this 

rule. 

Response: The three main classes of 

PM2.5 precursors that are not included 

in this rulemaking are carbonaceous 

material (including both primary 

emissions and VOC emissions that form 

secondary organic aerosol), ammonia, 

and crustal material. As noted in the 

proposal(69 FR 4576) and as mentioned 

in several comments, these components 

comprise a measurable faction of PM2.5

throughout the Eastern U.S., and the 

contribution of carbonaceous material, 

in particular, is often substantial. In 

addition, emissions contributing to 

these components in one state likely do 

affect PM2.5 concentrations in other 

states to some extent. However, the 

extent of those downwind contributions 

to nonattainment has not been 

quantified adequately and current 

scientific understanding makes such a 

determination more uncertain than is 

the case for SO2 and NOX. Responses to 

recommendations for including each of 

these three classes in the transport rule 

are summarized below. 

(i) Carbonaceous Material 

For carbonaceous material, 

uncertainties in both the quantity and 

origins of emissions contributing to both 

primary and secondary carbonaceous 

material on regional scales (including 

emissions from fires and from biogenic 

sources) limit the quality of regional 

scale modeling of carbonaceous PM2.5. 

This in turn causes substantial 

uncertainties in determining the amount 

of interstate transport from 

carbonaceous material and of the costs 

and effectiveness of emission controls. 

Modeling and monitoring the relative 

amount of organic particles that come 

from the formation of secondary organic 

particles, versus primary organic 

particles, is also highly uncertain. 

In addition, comparison of urban and 

nearby rural PM composition 

monitors 20 in the eastern U.S. find a 

significantly larger amount of 

carbonaceous materials in urban areas 

as compared to rural areas, suggesting 

that a substantial fraction of 

carbonaceous particles in urban areas 

come from local sources. By contrast, 

urban and non-urban monitors in the 

East show greater homogeneity for 

regional sulfate concentrations as 

compared to carbonaceous materials, 

suggesting regional sources are most 

important for sulfates. Results for 

nitrates suggest both a mixture of 

regional and local sources. Furthermore, 

as noted above and in the proposal (69 

FR 4577–78), while the relative 

contributions of different sources to 

regional sulfate and nitrates can be 

quantified with certainty, the 

contributions of different sources to 

carbonaceous materials on a regional 

scale are less clear. Moreover, as noted 

in the NPR preamble, some research 

into mechanisms of formation of organic 

particles suggests that both NOX and 

SO2 reductions might be of some benefit 

in lowering the amount of secondary 

organic particles.21 Current models are 

not, however, capable of quantifying 

such potential benefits.

While EPA does not believe that 

enough is known about the relative 

effectiveness or costs of reducing 

anthropogenic sources of carbonaceous 

particles on transported PM2.5, EPA 

agrees that control of known source 

categories of these materials can have a 

significant benefit in reducing the 

significant local contribution. For this 

reason, EPA has already enacted other 

national rules that will reduce 

emissions of primary carbonaceous 

PM2.5 from mobile sources, the largest 

contributor to such emissions. In 

addition to reducing PM2.5 in 

nonattainment areas, these regulations 

will also have the benefit of reducing a 

large measure of whatever interstate 

transport of carbonaceous PM2.5 occurs. 

(ii) Ammonia 

While current models are able to 

address the major chemical mechanisms 

involving particulate ammonium 

compounds, regional-scale ammonia 

emissions, particularly from agricultural 

sources, are highly uncertain.22 Given 

the relative lack of experience in 

controlling such sources, the costs and 

effectiveness of actions to reduce 

regional ammonia emissions are not 

adequately quantified at present. As 

noted above, ammonium would not 

exist in PM2.5 if not for the presence of 

sulfuric acid or nitric acid; hence, 

decreases in SO2 and NOX can be 

expected ultimately to decrease the 

ammonium in PM2.5 as well. The 

additional regional limits on SO2 and 

NOX emissions outlined in today’s 

notice added to those reductions 

provided under current programs would 

likewise be expected to reduce the PM2.5

effectiveness of any ammonia control 

initiative.23 Unlike ammonium, sulfuric 

acid has a very low vapor pressure and 

would exist in the particle with or 

without ammonia. Therefore, while SO2

reductions would reduce particulate 

ammonium, changes in ammonia would 

25182 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

24EPA OAQPS CMAQ Evaluation for 2001 

Docket # OAR–2003–0053–1716.

25NARSTO, Particulate Matter Science for Policy 

Makers—A NARSTO Assessment, February 2003.

be expected to have very little effect on 

the sulfate concentration.

In addition to the above 

considerations, because ammonium 

nitrates are highest in the winter, when 

ammonia emissions are lowest, reducing 

wintertime NOX emissions may 

represent a more certain path towards 

reducing this winter peak than ammonia 

reductions. Moreover, reductions in 

ammonia emissions alone would also 

tend to increase the acidity of PM2.5 and 

of precipitation. As noted in the 

proposal, this might have untoward 

environmental or health consequences.

Some commenters highlighted 

ammonia as an important pollutant with 

multiple effects on the environment, 

including its contributions to PM2.5. 

These commenters highlighted that 

ammonia emissions are not currently 

regulated extensively, and suggested 

that EPA strengthen its efforts to better 

understand the many effects of 

ammonia emissions and better research 

options for controlling ammonia, so that 

it can be regulated where appropriate in 

the future programs. Generally, EPA 

agrees with these commenters. 

(iii) Crustal Material 

The contributions of crustal materials 

to PM2.5 nonattainment are usually 

small, and the interstate transport of 

crustal materials is even smaller. 

Emissions of crustal materials on 

regional scales are uncertain, highly 

variable in space and time, and may not 

be easily controlled in some cases, 

suggesting significant uncertainties in 

quantifying emissions and the costs and 

effectiveness of control actions. 

Emissions reductions of SO2 and NOX

will likely reduce some of the direct 

emissions of PM2.5 from EGUs and other 

industries, which are responsible for a 

portion of the ‘‘crustal material’’

measured downwind at receptors. 

(c) Summary of Response To Requiring 

or Allowing Reductions in Other 

Pollutants 

After reviewing public comments in 

light of the current understanding of 

alternative pollutants as summarized 

above, EPA disagrees with those 

commenters who suggested that the 

final Clean Air Interstate Rule should 

require states to address the interstate 

transport of carbonaceous material 

(including VOCs), ammonia, and/or 

crustal material in the present 

rulemaking. 

At present, the sources and emissions 

contributing to these components on 

regional scales are not sufficiently 

quantified. In addition, the 

representation of atmospheric physics 

and chemistry for these components in 

air quality models is in some cases poor 

in comparison with current 

understanding of SO2 and NOX (most 

notably for sources and amounts of 

secondary organic aerosol production.24

Consequently, quantification of the 

interstate transport of these components 

is significantly more uncertain than for 

SO2 and NOX emissions. Given these 

uncertainties in regional emissions and 

interstate transport of these 

components, EPA has determined that it 

would be premature to quantify 

interstate impacts of these emissions 

through zero-out modeling, as was done 

for SO2 and NOX emissions.

In addition, the costs of control 

measures, their effectiveness at reducing 

emissions, as well as their ultimate 

effectiveness at reducing PM2.5

concentrations at downwind receptors 

are all uncertain. The EPA does not 

believe it could reasonably evaluate 

whether such State emissions 

contributed significantly to transport, or 

what level of control would address the 

significant contribution. Commenters 

have not provided us specific data and 

information to allow such assessments. 

The EPA also disagrees with 

commenters who argue that EPA 

should, for the purposes of this rule, 

permit the States to substitute controls 

of sources of any of these other three 

components for the required limits on 

SO2 and NOX. Given the greater 

uncertainties in estimating the 

contribution of alternative source 

emissions, States would have difficulty 

developing, and EPA would have 

difficulty in approving, SIPs that, by 

controlling these components, purport 

to reduce an upwind State’s impact on 

downwind PM2.5 nonattainment by an 

equivalent amount to that required in 

today’s final rule. 

As explained in the proposal, a 

decision not to regulate these 

components of PM2.5 in the present 

rulemaking does not preclude state or 

local PM2.5 implementation plans from 

reducing emissions of carbonaceous 

material, ammonia, or crustal material, 

in order to achieve attainment with 

PM2.5 standards, in cases where there is 

evidence that such controls will be 

effective on a local basis. Although 

uncertainties exist in addressing longrange transport of these pollutants, state 

and local air quality management 

agencies will need to evaluate 

reasonable control measures for sources 

of these pollutants in developing SIPs 

due in 2008. We expect continuous 

improvements will be made in our 

understanding of source emissions and 

PM2.5 components not addressed under 

CAIR. To assist future air quality 

management decisions, EPA is actively 

supporting research into better 

understanding the emissions, 

atmospheric processes, long range 

transport, and opportunities for control 

of these PM2.5 components. 

(d) Justification for Including NOX in 

Determining Significant Contributions 

and for Regulating NOX Emissions for 

PM2.5 Transport 

Some commenters questioned the 

EPA’s basis for requiring emissions 

reductions of NOX, in addition to SO2, 

for the purposes of controlling interstate 

transport of PM2.5. These comments, and 

EPA’s response, are discussed below. 

Other comments addressing EPA’s basis 

for requiring NOX for ozone are 

addressed in a subsequent section.

Like SO2, NOX emissions are 

understood to affect PM2.5 on regional 

scales, due in part to the time needed to 

convert NOX emissions to nitrate. Like 

SO2 but unlike precursors of other 

components of PM2.5, emissions of NOX

are well quantified for EGUs and with 

reasonable accuracy for other urban and 

regional sources, and the transport of 

NOX and PM2.5 derived from NOX can 

also be quantified with a fair degree of 

certainty. In addition, SO2 and NOX

interact as part of the same chemical 

system in the atmosphere. Controlling 

SO2 emissions without concurrently 

controlling NOX emissions can lead to 

nitrate replacement whereby SO2

emissions reductions will be less 

effective than expected. Finally, SO2

and NOX share common sources in 

fossil fuel combustion. As such, 

controlling emissions of both precursors 

in a coordinated way presents 

opportunities to reduce the overall cost 

of the control program.25

Commenters questioned EPA’s 

methodology of evaluating whether an 

upwind State contributes significantly 

to PM2.5 nonattainment by considering 

(through the ‘‘zero-out’’ air quality 

modeling technique) SO2 and NOX

emissions simultaneously. These 

commenters argued that zeroing out SO2

and NOX emissions simultaneously 

precludes determining the contribution 

of each component to downwind 

nonattainment. Because sulfates 

generally comprise a greater fraction of 

PM2.5 than nitrates in the Eastern U.S., 

these commenters argued that the basis 

for requiring NOX controls is weaker 

than for SO2, and has not been 

determined directly by EPA. 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25183

26NARSTO, Particulate Matter Science for Policy 

Makers—A NARSTO Assessment, February 2003.

27 ‘‘Regulatory Impact Analysis for the Final 

Clean Air Interstate Rule (March 2005).’’

28Blanchard, C.L., and G.M. Hidy (2004) Effects 

of projected utility SO2 and NOX emission 

reductions on particulate nitrate and PM2.5 mass 

concentrations in the Southeastern United States, 

Report to Southern Company. See CAIR docket.

29Blanchard C.L., and G.M. Hidy (2003). Effects 

of changes in sulfate, ammonia, and nitric acid on 

particulate nitrate concentrations in the 

Southeastern United States, J. Air & Waste Manage. 

Assoc., 53: 283–290.

30NARSTO, Particulate Matter Science for Policy 

Makers—A NARSTO Assessment, February 2003.

The EPA’s multi-pollutant approach 

of modeling SO2 and NOX contributions 

at the same time is consistent both with 

sound science and with the 

requirements of CAA section 

110(a)(2)(D), as EPA interpreted and 

applied them in the NOX SIP Call. This 

provision requires each State to submit 

a SIP to prohibit ‘‘any source or other 

type of emissions activity within the 

State from emitting any air pollutant in 

amounts which will * * * contribute 

significantly to nonattainment’’

downwind. As discussed in section II 

above, in the NOX SIP Call, a 

rulemaking in which EPA regulated 

NOX emissions as precursors for ozone, 

EPA found that ozone resulted from the 

combined contributions of many 

emitters over a multistate region, a 

phenomenon that EPA termed 

‘‘collective contribution’’ (63 FR 57356–

86). As a result, EPA evaluated each 

State’s contribution to nonattainment 

downwind by considering the impact of 

the entirety of that State’s NOX

emissions on downwind nonattainment. 

Once EPA determined the State’s entire 

NOX emissions inventory to have at 

least a minimum downwind impact, 

then EPA required the State to eliminate 

the portion of those emissions that 

could be reduced through highly costeffective controls. The EPA considered 

this approach to be consistent with the 

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

In a companion rulemaking, the 

section 126 Rule, EPA found that 

certain, individual NOX emitters must 

be subject to Federal regulation due to 

their impact on downwind 

nonattainment (65 FR 2674). The EPA 

based this finding on the same notion of 

‘‘collective contribution,’’ that is, NOX

emissions from those individual sources 

were part of the upwind State’s total 

NOX inventory, the total NOX inventory 

had a sufficiently high impact on 

downwind nonattainment, and therefore 

the individual NOX emitters should be 

subject to control without any separate 

determination as to their individual 

impacts on downwind nonattainment. 

The DC Circuit accepted EPA’s 

collective contribution approach 

upholding most of the NOX SIP Call 

regulation, in Michigan v. EPA, 213 F.3d 

663 (DC Cir. 2000), cert. denied 532 U.S. 

904 (2001). Similarly, the DC Circuit 

upheld most aspects of EPA’s Section 

126 Rule, including the collective 

contribution basis for finding that 

emissions from the individual sources 

should be subject to regulation. 

Appalachian Power Co. v. EPA, 249 

F.3d 1032 (DC Cir. 2001) (per curium).

As discussed elsewhere, PM2.5 is 

similar to ozone in that it is the result 

of emissions from many sources over a 

multi-state region. Accordingly, EPA 

considers that the phenomenon of 

‘‘collective contribution’’ is associated 

with PM2.5 as well. 

In the CAIR NPR, EPA selected SO2

and NOX as the appropriate precursors 

to be controlled for PM2.5 transport, for 

several reasons presented above. As in 

the NOX SIP Call, today’s rulemaking, 

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

requires EPA to evaluate whether a 

particular upwind State must submit a 

SIP that prohibits ‘‘any source or other 

type of emissions activity within the 

State from emitting any air pollutant in 

amounts which will * * * contribute 

significantly to nonattainment’’

downwind. In making this 

determination, EPA considers the effects 

of all of the appropriate precursors—

here, both SO2 and NOX—from all of the 

State’s sources on downwind PM2.5

nonattainment. If that collective 

contribution to downwind PM2.5

nonattainment is sufficiently high, then 

EPA requires the upwind State to 

eliminate those precursors to the extent 

of the availability of highly costeffective controls. 

The EPA’s approach to evaluating a 

State’s impact on downwind 

nonattainment by considering the 

entirety of the State’s SO2 and NOX

emissions is also consistent with the 

chemical interactions in the atmosphere 

of SO2 and NOX in forming PM2.5. The 

contributions of SO2 and NOX emissions 

are generally not additive, but rather are 

interrelated due to the nitrate 

replacement phenomenon, as well as 

other complex chemical reactions that 

can include organic compounds as well. 

As commenters point out, the nature of 

these reactions can vary with location 

and time. The non-linear nature of some 

of these reactions can produce differing 

results depending on the relative 

amount of reductions and copollutants. 

Reductions in sulfates can increase 

nitrates and, in some conditions, modest 

reductions in nitrates can increase 

sulfates although through different 

mechanisms. Large regional reductions 

in both pollutants, however, are more 

likely to result in a significant 

reductions in fine particles.26

Based on its current understanding of 

regional air pollution and modeling 

results, EPA believes that adopting a 

broad new program of regional controls 

to continue the downward trajectory in 

both SOX and NOX begun in base 

programs such as the national mobile 

source rules and Title IV, as well as the 

NOX SIP call, will ultimately result in 

significant benefits not only in reducing 

PM2.5 nonattainment, but improving 

public health, reducing regional haze, 

and addressing multimedia 

environmental concerns including acid 

deposition and nutrient loadings in 

sensitive coastal estuaries in the East.27

Some commenters argued that the 

benefits of combining NOX with SO2

reductions, if any, would be small, and 

further argued that the effect of any 

nitrate reductions in the environment 

would be further diminished by 

measurement losses that can occur in 

the filter in the method used to measure 

PM2.5. In so doing, they questioned the 

scientific basis for nitrate replacement, 

suggesting that this response to changes 

in SO2 emissions may not happen in all 

places and at all times. The commenters 

referenced a study in the Southeastern 

U.S. by Blanchard and Hidy,28 which 

they claim calls into question whether 

nitrate replacement actually occurs. In 

fact, the study finds evidence that 

nitrate replacement occurs: ‘‘the sulfate 

decreases were an input to the model 

calculations, but their effect on fine PM 

mass was modified by concomitant 

decreases in ammonium and increases 

in nitrate.’’ A second study by the same 

authors, using essentially the same 

dataset and methods, and referenced 

both by EPA in the NPR and by the 

commenters, gives very strong support 

for the existence of nitrate replacement, 

as well as for coordinating SO2 and NOX

reductions, as indicated by the 

following conclusions: ‘‘reductions in 

sulfate through SO2 reduction at 

constant NOX levels would not result in 

proportional reduction in PM2.5 mass 

because particulate nitrate 

concentrations would increase. 

However, if both NOX and SO2

emissions are reduced, then it may be 

possible to achieve sulfate reductions 

without concomitant nitrate increases 

***’’ 29

Nitrate replacement is well 

documented in the scientific literature 

as a possible response of PM2.5 to 

changes in SO2 emissions.30 While these 

commenters are correct that nitrate 

replacement is not expected to occur at 

all places and at all times, even where 

average conditions are not favorable for 

25184 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

31 Ibid. 32For example, West, J.J., A.S. Ansari, and S.N. 

Pandis (1999) Marginal PM2.5, nonlinear aerosol 

mass response to sulfate reductions in the Eastern 

U.S., J. Air & Waste Manage. Assoc., 49: 1415–1424.

nitrate replacement, hourly variability 

in those conditions can create 

conditions favorable for nitrate 

replacement at particular times. Nitrate 

replacement theory predicts no 

conditions under which SO2 reductions 

would decrease nitrate, and suggests 

that nitrate may increase under fairly 

common conditions.31 Consequently, 

the net effect of SO2 reductions can be 

only to increase nitrate or not to have 

any effect. The variability of conditions 

occurring over a year means that SO2

reductions would be expected to 

increase nitrate on balance.

Even if the studies referenced by these 

commenters showed that nitrate 

replacement does not occur in some 

circumstances, other studies suggest 

that the conditions for nitrate 

replacement are common in the Eastern 

U.S.32 Suggesting that nitrate 

replacement does not occur under some 

conditions does not imply that NOX

should not be controlled, when it is 

known that nitrate replacement occurs 

under other common conditions.

The EPA recognizes that the relative 

reductions in PM2.5 from 

implementation of the CAIR will be 

greater for SO2 than for NOX. 

Nevertheless, overall costs for reducing 

NOX in the CAIR region are much lower 

than SO2 because a large portion of the 

region has already installed NOX

controls for ozone in the summer 

months. Our revised modeling 

approaches took into account the 

differences commenters note between 

actual nitrate concentrations in the 

atmosphere and what is measured as 

PM2.5. Nevertheless emissions of both 

pollutants clearly contribute to 

interstate transport of ambient fine 

particles, and EPA concludes that the 

best approach in this situation is to 

provide highly cost effective reductions 

for both pollutants. Moreover, in 

warmer conditions when apparent 

nitrate changes from NOX reductions as 

measured on PM2.5 monitors are small, 

the actual reductions in particulate and 

gaseous nitrates in the ambient 

environment are larger; accordingly, 

NOX reductions combined with SO2

reductions can be expected to reduce 

health risk, visibility impairment, and 

other environmental damages. 

c. What Is EPA’s Final Determination? 

After considering the public 

comments, EPA concludes that it should 

adopt the approach it proposed for 

addressing interstate transport of 

pollutants that affect PM2.5, for the 

reasons presented here and in the 

proposal. That is, in today’s action, EPA 

is requiring states to take steps to 

control emissions of SO2 and NOX on 

the basis of their contributions to 

nonattainment of PM2.5 standards in 

downwind states. The EPA concludes 

that we do not now have a sufficient 

basis for including emissions of other 

components (carbonaceous material, 

ammonia, and crustal material) that 

contribute to PM2.5 in determining 

significant contributions and in 

requiring emission reductions of these 

components. 

2. What Is the Role for Local Emissions 

Reduction Strategies? 

a. Summary of Analyses and 

Conclusions in the Proposal 

In section IV.F of the proposed rule, 

we discussed two analyses that were 

completed to address the impact of local 

control measures relative to regional 

reductions of SO2 and NOX (69 FR 

4596–99). In the first analysis, we 

applied a list of readily identifiable 

control measures (NPR, Table IV–5) in 

the Philadelphia, Birmingham, and 

Chicago urban primary metropolitan 

statistical areas (PMSA) counties. In the 

second analysis, we applied a similar 

list of control measures to 290 counties 

representing the metropolitan areas we 

projected to contain any nonattainment 

county in 2010 in the baseline scenario. 

The three-city analysis estimated that 

these local measures would result in 

ambient PM2.5 reductions of about 0.5 

μg/m3 to about 0.9 μg/m3, which is less 

than needed to bring any of the cities 

into attainment in 2010. The 290-county 

study, which included enough counties 

to produce regional as well as local 

reductions, found that while some of the 

2010 nonattainment areas would be 

projected to attain, many would not. 

Moreover, much of the PM2.5 reduction 

in the 290-county study resulted from 

assuming reduction in sulfates due to 

SO2 reductions on utility boilers in the 

urban counties. Accordingly, we 

concluded that for a sizable number of 

PM2.5 nonattainment areas it will be 

difficult if not impossible to reach 

attainment unless transport is reduced 

to a much greater degree than by the 

simultaneous adoption of controls 

within only the nonattainment areas. 

b. Summary and Response to Public 

Comments 

A number of commenters supported 

EPA’s conclusion that regional 

reductions are necessary given the 

difficulty in achieving local emission 

reductions, and given that they are 

generally more cost-effective. Generally, 

EPA agrees with these commenters. 

Other commenters were critical of the 

local measures analysis, and 

recommended that EPA should consider 

a more appropriate mix of regional and 

local controls before requiring 

substantial expenditures for controls on 

power plants or other regional sources 

potentially affected by this rule. These 

commenters believed that the proposed 

rule did not represent the optimal 

emissions reduction strategy. Other 

commenters believed that the local 

measures analysis underestimated the 

achievable local emissions reductions. 

Some commenters believed that EPA 

should include local control measures 

in the baseline scenario for the analysis. 

Finally, some commenters questioned 

the feasibility of doing a local measures 

analysis at all, given the uncertainties in 

the analysis, the uncertainties regarding 

nonattainment boundaries, and the 

work to be done by State and local areas 

to identify and evaluate strategies.

The EPA continues to conclude that it 

would be difficult if not impossible for 

many nonattainment areas to reach 

attainment through local measures 

alone, and EPA finds no information in 

the comments to alter this conclusion. 

While recognizing the uncertainties in 

conducting such an analysis (as noted in 

the preamble to the proposed rule), we 

continue to believe that the two local 

measures scenarios represent a highly 

ambitious set of measures and emissions 

reductions that may in fact be difficult 

to achieve in practice. This analysis was 

not intended to precisely identify local 

measures that may be available in a 

particular area. The EPA believes that a 

strategy based on adopting highly cost 

effective controls on transported 

pollutants as a first step would produce 

a more reasonable, equitable, and 

optimal strategy than one beginning 

with local controls. The local measures 

analyses we conducted were not, 

however, intended to develop a specific 

or ‘‘optimal’’ regional and local 

attainment strategy for any given area. 

Rather, the analysis was intended to 

evaluate whether, in light of available 

local measures, it is likely to be 

necessary to reduce significant regional 

transport from upwind states. We 

continue to believe that the two local 

measures analyses that were conducted 

for the proposal rule strongly support 

the need for regional reductions of SO2

and NOX. 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25185

33Ozone Transport Assessment Group, OTAG 

Final Report, 1997. 

34NARSTO, An Assessment of Tropospheric 

Ozone Pollution—A North American Perspective, 

July 2000.

35National Research Council, Rethinking the 

Ozone Problem in Urban and Regional Air 

Pollution, 1991. 

36NARSTO, An Assessment of Tropospheric 

Ozone Pollution—A North American Perspective, 

July 2000.

37U.S. EPA, Latest Findings on National Air 

Quality, August 2003.

38Other commenters confirmed that the control of 

NOX emissions is critical for interstate ozone 

transport, and supported EPA’s decision not to 

include VOC emissions in this rule.

B. What Is the Basis for EPA’s Decision 

To Require Reductions in Upwind 

Emissions of NOX To Address OzoneRelated Transport? 

1. How Did EPA Determine Which 

Pollutants Were Necessary To Control 

To Address Interstate Transport for 

Ozone? 

In the notice of proposed rulemaking, 

EPA provided the following 

characterization of the origin and 

distribution of 8-hour ozone air quality 

problems: 

The ozone present at ground level as 

a principal component of 

photochemical smog is formed in sunlit 

conditions through atmospheric 

reactions of two main classes of 

precursor compound: VOCs and NOX

(mainly NO and NO2). The term ‘‘VOC’’

includes many classes of compounds 

that possess a wide range of chemical 

properties and atmospheric lifetimes, 

which helps determine their relative 

importance in forming ozone. Sources of 

VOCs include man-made sources such 

as motor vehicles, chemical plants, 

refineries, and many consumer 

products, but also natural emissions 

from vegetation. Nitrogen oxides are 

emitted by motor vehicles, power 

plants, and other combustion sources, 

with lesser amounts from natural 

processes including lightning and soils. 

Key aspects of current and projected 

inventories for NOX and VOC are 

summarized in section IV of the 

proposal notice and EPA websites (e.g., 

http://www.w.gov/ttn/chief.) The 

relative importance of NOX and VOC in 

ozone formation and control varies with 

local- and time-specific factors, 

including the relative amounts of VOC 

and NOX present. In rural areas with 

high concentrations of VOC from 

biogenic sources, ozone formation and 

control is governed by NOX. In some 

urban core situations, NOX

concentrations can be high enough 

relative to VOC to suppress ozone 

formation locally, but still contribute to 

increased ozone downwind from the 

city. In such situations, VOC reductions 

are most effective at reducing ozone 

within the urban environment and 

immediately downwind. 

The formation of ozone increases with 

temperature and sunlight, which is one 

reason ozone levels are higher during 

the summer. Increased temperature 

increases emissions of volatile manmade and biogenic organics and can 

indirectly increase NOX as well (e.g., 

increased electricity generation for air 

conditioning). Summertime conditions 

also bring increased episodes of largescale stagnation, which promote the 

build-up of direct emissions and 

pollutants formed through atmospheric 

reactions over large regions. The most 

recent authoritative assessments of 

ozone control approaches 33, 34 have 

concluded that, for reducing regional 

scale ozone transport, a NOX control 

strategy would be most effective, 

whereas VOC reductions are most 

effective in more dense urbanized areas.

Studies conducted in the 1970s 

established that ozone occurs on a 

regional scale (i.e., 1000s of kilometers) 

over much of the Eastern U.S., with 

elevated concentrations occurring in 

rural as well as metropolitan areas.35, 36

While progress has been made in 

reducing ozone in many urban areas, the 

Eastern U.S. continues to experience 

elevated regional scale ozone episodes 

in the extended summer ozone season.

Regional 8-hour ozone levels are 

highest in the Northeast and MidAtlantic areas with peak 2002 (3-year 

average of the 4th highest value for all 

sites in the region) ranging from 0.097 

to 0.099 parts per million (ppm).37 The 

Midwest and Southeast States have 

slightly lower peak values (but still 

above the 8-hour standard in many 

urban areas) with 2002 regional averages 

ranging from 0.083 to 0.090 ppm. 

Regional-scale ozone levels in other 

regions of the country are generally 

lower, with 2002 regional averages 

ranging from 0.059 to 0.082 ppm. 

Nevertheless, some of the highest urban 

8-hour ozone levels in the nation occur 

in southern and central California and 

the Houston area.

In the notice of proposed rulemaking, 

EPA noted that we continue to rely on 

the assessment of ozone transport made 

in great depth by the OTAG in the mid1990s. As indicated in the NOX SIP call 

proposal, the OTAG Regional and Urban 

Scale Modeling and Air Quality 

Analysis Work Groups reached the 

following conclusions: 

A. Regional NOX emissions 

reductions are effective in producing 

ozone benefits; the more NOX reduced, 

the greater the benefit. 

B. Controls for VOC are effective in 

reducing ozone locally and are most 

advantageous to urban nonattainment 

areas. (62 FR 60320, November 7, 1997). 

The EPA proposed to reaffirm this 

conclusion in this rulemaking, and 

proposed to address only NOX

emissions for the purpose of reducing 

interstate ozone transport. 

Some commenters suggested that in 

this rulemaking EPA should require 

regional reductions in VOC emissions as 

well as NOX emissions in this 

rulemaking.38 The EPA continues to 

believe based on the OTAG and 

NARSTO reports cited earlier, and the 

modeling completed as part of the 

analysis for this rule, that NOX

emissions are chiefly responsible for 

regional ozone transport, and that NOX

reductions will be most effective in 

reducing regional ozone transport. This 

understanding was considered an 

adequate basis for controlling NOX

emissions for ozone transport in the 

NOX SIP call, and was upheld by the 

courts. As a result, EPA is requiring 

NOX reductions and not VOC reductions 

in this rulemaking.

However, EPA agrees, that VOCs from 

some upwind States do indeed have an 

impact in nearby downwind States, 

particularly over short transport 

distances. The EPA expects that States 

will need to examine the extent to 

which VOC emissions affect ozone 

pollution levels across State lines, and 

identify areas where multi-state VOC 

strategies might assist in meeting the 8-

hour standard, in planning for 

attainment. This does not alter the basis 

for the CAIR ozone requirements in this 

rule; EPA’s modeling supports the 

conclusion that NOX emissions from 

upwind states will significantly 

contribute to downwind nonattainment 

and interfere with maintenance of the 8-

hour ozone standard. 

2. How Did EPA Determine That 

Reductions in Interstate Transport, as 

Well as Reductions in Local Emissions, 

Are Warranted To Help Ozone 

Nonattainment Areas To Meet the

8-Hour Ozone Standard? 

a. What Did EPA Say in Its Proposal 

Notice? 

In the NPR, EPA noted that the 

Agency promulgated the NOX SIP call in 

1998 to address interstate ozone 

transport problems in the Eastern U.S. 

The EPA noted that it made sense to reevaluate whether the NOX SIP call was 

adequate at the same time that the 

Agency was assessing the need for 

emissions reductions to address 

interstate PM2.5 problems because of 

overlap in the pollutants and relevant 

25186 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

sources, and the timetables for States to 

submit local attainment plans. The EPA 

presented a new analysis of the extent 

of residual 8-hour ozone attainment 

projected to remain in 2010, and the 

extent and severity of interstate 

pollution transport contributing to 

downwind nonattainment in that year. 

The proposal notice said that based 

on a multi-part assessment, EPA had 

concluded that: 

• ‘‘Without adoption of additional 

emissions controls, a substantial 

number of urban areas in the central and 

eastern regions of the U.S. will continue 

to have levels of 8-hour ozone that do 

not meet the national air quality 

standards. 

• * * * EPA has concluded that 

small contributions of pollution 

transport to downwind nonattainment 

areas should be considered significant 

from an air quality standpoint, because 

these contributions could prevent or 

delay downwind areas from achieving 

the standards. 

• * * * EPA has concluded that 

interstate transport is a major 

contributor to the projected (8-hour 

ozone) nonattainment problem in the 

eastern U.S. in 2010. * * * (T)he 

nonattainment areas analyzed receive a 

transport contribution of more than 20 

percent of the ambient ozone 

concentrations, and 21 of 47 had a 

transport contribution of more than 50 

percent. 

• Typically, two or more States 

contribute transported pollution to a 

single downwind area, so that the 

‘‘collective contribution’’ is much larger 

than the contribution of any single 

State. 

Also, EPA concluded that highly costeffective reductions in NOX emissions 

were available within the eastern region 

where it determined interstate transport 

was occurring, and that requiring those 

highly cost effective reductions would 

reduce ozone in downwind 

nonattainment areas. 

In addition, the proposal examined 

the effect of hypothetical across-theboard emissions reductions in 

nonattainment areas. The notice stated 

that EPA had conducted a preliminary 

scoping analysis in which hypothetical 

total NOX and VOC emissions 

reductions of 25 percent were applied in 

all projected nonattainment areas east of 

the continental divide in 2010, yet 

approximately 8 areas were projected to 

have ozone levels exceeding the 8-hour 

standard. Based on experience with 

state plans for meeting the one-hour 

ozone standard, EPA said this scenario 

was an indication that attaining the 8-

hour standard will entail substantial 

cost in a number of nonattainment 

areas, and that further regional 

reductions are warranted.

b. What Did Commenters Say? 

The Need for Reductions in Interstate 

Ozone Transport: Some commenters 

argued that EPA should not conduct 

another rulemaking to control interstate 

contributions to ozone because local 

contributions in nonattainment regions 

appear, according to the commenters, to 

have larger impacts than regional NOX

emissions. The commenters cited EPA’s 

sensitivity modeling of hypothetical 25 

percent reductions as supporting this 

view. 

The EPA disagrees that comparing the 

sensitivity modeling and the CAIR 

control modeling is a valid way to 

compare the effectiveness of local and 

regional controls. The two scenarios do 

not reduce emissions by equal tonnage 

amounts, equal percentages of the 

inventory, or equal cost. These scenarios 

therefore do not support an assessment 

of the relative effectiveness of local and 

regional controls. While EPA in general 

agrees that emissions reductions in a 

nonattainment area will have a greater 

effect on ozone levels in that area than 

similar reductions a long distance away, 

EPA does not agree that the modeling 

supports the conclusion that all 

additional controls to promote 

attainment with the 8-hour standard 

should be local. The level of reduction 

assumed was a hypothetical level, not a 

level determined to be reasonable cost 

nor a mandated level of reduction. The 

commenters provided no evidence that 

reasonable local controls alone would 

result in attainment throughout the East. 

However, EPA did receive comments 

that such a level would result in costly 

controls and might not be feasible in 

some areas that have previously 

imposed substantial controls. 

The EPA believes it is clear that 

further reductions in emissions 

contributing to interstate ozone 

transport, beyond those required by the 

NOX SIP Call, are warranted to promote 

attainment of the 8-hour ozone standard 

in the eastern U.S. As explained 

elsewhere in this final rule, EPA 

analyzed interstate transport remaining 

after the NOX SIP Call, and 

determined—considering both the 

impact of interstate transport on 

downwind nonattainment, and the 

potential for highly cost effective 

reductions in upwind States—that 25 

States significantly contribute to 8-hour 

ozone nonattainment downwind. The 

importance of transport is illustrated, as 

mentioned above, by EPA’s findings for 

the final rule that (1) all the 2010 

nonattainment counties analyzed were 

projected to receive a transport 

contribution of 24 percent or more of 

the ambient ozone concentrations, and 

(2) that 16 of 38 counties are projected 

to have a transport contribution of more 

than 50 percent. 

In addition, EPA received multiple 

comments from State associations and 

individual States strongly agreeing that 

further reductions in interstate ozone 

transport are warranted to promote 

attainment with the 8-hour standard, to 

protect public health, and to address 

equity concerns of downwind states 

affected by transport. For example, 

comments from the Maryland 

Department of the Environment stated, 

‘‘Our 15 year partnership with 

researchers from the University of 

Maryland has produced data that shows 

on many summer days the ozone levels 

floating into Maryland area are already 

at 80 to 90 percent of the 1-hour ozone 

standard and actually exceed the new 8-

hour ozone standard before any 

Maryland emissions are added. * * * 

Serious help is needed from EPA and 

neighboring states to solve Maryland’s 

air pollution problems. * * * Local 

reductions alone will not clean up 

Maryland’s air.’’ The comments of the 

Ozone Transport Commission stated 

that even after levels of control 

envisioned by EPA in 2010 (under the 

Clear Skies Act), interstate transport 

from other states would continue to 

affect the Ozone Transport Region 

created by the CAA (Connecticut, 

Delaware, the District of Columbia, 

Maine, Maryland, Massachusetts, New 

Hampshire, New Jersey, New York, 

Pennsylvania, Rhode Island, Vermont, 

and Virginia). ‘‘Our modeling 

demonstrates that even in the extreme 

example of zero anthropogenic 

emissions within the OTR (Ozone 

Transport Region), 145 of 146 monitors 

show a significant (>25%) increment of 

the 8-hour standard taken up by 

transport from outside the OTR.’’

Comments from the North Carolina 

Department of Environment and Natural 

Resources stated, ‘‘The reductions 

proposed in [EPA’s rule] in the other 

states are needed to ensure that North 

Carolina can attain and maintain the 

health-based air quality standards for 

* * * 8-hour ozone.’’

Magnitude of Ozone Reductions 

Achieved: Commenters stated that NOX

reductions should not be pursued 

because the 8-hour ozone reductions in 

projected nonattainment counties 

resulting from the required NOX

reductions are too small—1–2 ppb in 

only certain areas. According to 

commenters, these benefits are smaller 

than the threshold for determining 

significant contribution. 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25187

The EPA disagrees with the notion 

that if air quality improvements would 

be limited, then nothing further should 

be done to address interstate transport. 

Based on the difference between the 

base case and CAIR control case 

modeling results, EPA has concluded 

that interstate air quality impacts are 

significant from an air quality 

standpoint, and that highly cost 

effective reductions are available to 

reduce ozone transport. State comments 

have corroborated EPA’s conclusion that 

a number of areas will face high local 

control costs, or even be unable to attain 

the 8-hour ozone standard, without 

further reductions in interstate 

transport. Therefore, EPA believes it is 

important for upwind states to modify 

their SIPs so that they contain adequate 

provisions to prohibit significant 

contributions to downwind 

nonattainment or interference with 

maintenance as the statute requires. The 

EPA has established an amount of 

required emissions reductions based on 

controls that are highly cost effective. 

The resulting improvements in 

downwind ozone levels are needed for 

attainment, public health and equity 

reasons.

The 2 ppb significance threshold that 

commenters cite is part of the test that 

EPA used to identify which States 

should be evaluated for inclusion in a 

rule requiring them to reduce emissions 

to reduce interstate transport. (See 

section VI.) This 2 ppb threshold is 

based on the impact on a downwind 

area of eliminating all emissions in an 

upwind State. The ozone reductions 

from CAIR will improve public health 

and will decrease the extent and cost of 

local controls needed for attainment in 

some areas. In addition, base case 

modeling for this rule shows that of the 

40 counties projected in nonattainment 

in 2010, 16 counties are within 2 ppb 

of the standard, 6 counties are within 3 

ppb, and 3 counties are within 4 ppb. 

In 2015, projected base case ozone 

concentrations in over 70 percent of 

nonattaining counties (i.e., 16 of 22 

counties) are within 5 ppb of the 

standard. 

Reducing NOX emissions has multiple 

health and environmental benefits. 

Controlling NOX reduces interstate 

transport of fine particle levels as well 

as ozone levels, as discussed elsewhere 

in this notice. Although EPA is not 

relying on other benefits for purposes 

for setting requirements in this rule, 

reducing NOX emissions also helps to 

reduce unhealthy ozone and PM levels 

within a State, as well as reduce acid 

deposition to soils and surface waters, 

eutrophication of surface and coastal 

waters, visibility degradation, and 

impacts on terrestrial and wetland 

systems such as changes in species 

composition and diversity. 

EPA’s Authority To Require Controls 

Beyond the NOX SIP Call: Commenters 

emphasized that in the NO X SIP Call, 

EPA determined the States whose 

emissions contribute significantly to 

nonattainment, EPA mandated NOX

emissions reductions that would 

eliminate those significant 

contributions, and EPA indicated that it 

would reconsider the matter in 2007. 

This commenter argued that for the 

States included in the NOX SIP Call, 

EPA may not, as a legal matter, conduct 

further rulemaking at this time because 

the affected States are no longer 

contributing significantly to 

nonattainment downwind. In any event, 

the commenters said, EPA should abide 

by its statement that it would revisit the 

matter in 2007, and EPA should not do 

so earlier. 

Sound policy considerations support 

re-examining interstate ozone transport 

at this time. At the time of the NOX SIP 

Call, EPA anticipated reassessing in 

2007 the need for additional reductions 

in emissions that contribute to interstate 

transport, but EPA has accelerated that 

date in light of various circumstances, 

including the fact that we are 

undertaking similar action with the 

PM2.5 NAAQS. In addition, in light of 

overlap in the pollutants, States, and 

sources likely to be affected, it is 

prudent to coordinate action under the 

8-hour ozone standard. The EPA notes 

that evaluating PM2.5 transport and 

ozone transport together at this time 

will enable States to consider the 

resulting rules in devising their PM2.5

and 8-hour ozone attainment plans, and 

will enable States and sources to plan 

emissions reductions knowing their 

transport-related reduction 

requirements for both standards. 

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

State SIPs contain ‘‘adequate 

provisions’’ prohibiting emissions that 

significantly contribute to 

nonattainment areas in, or interfere with 

maintenance by, other States. Over time, 

emissions of ozone precursors, the 

(projected) non-attainment status of 

receptors, the modeling tools that EPA 

and the states use to conduct their 

analyses, the data available to the states 

or EPA and other analytic tools or 

conditions may change. The EPA has 

conducted an updated analysis of 

upwind contribution to downwind 

nonattainment of 8-hour ozone 

nonattainment areas after the NOX SIP 

Call, including updated emissions 

projections, updated air quality 

modeling, and updated analysis of 

control costs. This has revealed a need 

for reductions beyond those required by 

the NOX SIP Call in order for upwind 

states to be in compliance with section 

110(a)(2)(D). The EPA thus disagrees 

with commenters’ assertions that the 

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

prevent EPA from conducting further 

evaluation of upwind contributions to 

downwind nonattainment at this time. 

The EPA also notes that the NOX SIP 

Call, a 1998 rulemaking, promulgated a 

set of requirements intended to 

eliminate significant contribution to 

downwind ozone nonattainment at the 

time of implementation, which EPA 

identified on the basis of modeling for 

the year 2007 (although implementation 

was required to occur several years 

earlier). In today’s action, EPA is 

reviewing the transport component of 8-

hour ozone nonattainment for the 

period beginning in 2010, consistent 

with the criteria in the NOX SIP Call as 

applied to present circumstances, 

concluding that even with 

implementation of the NOX SIP Call 

controls, upwind States will contribute 

significantly to downwind ozone 

nonattainment and interfere with 

maintenance at a point after 2007. No 

provision of the CAA prohibits this 

action.

Commenters added that the purpose 

of the CAIR rulemaking seemed to be to 

account for the fact that control costs 

have changed since the date of the NOX

SIP Call. The commenters said that 

control costs will frequently fluctuate, 

but that such fluctuations should not 

merit revised rulemaking. 

In response, we would note that EPA 

conducted an updated analysis for air 

quality impacts, not only costs, in 

determining that further reductions in 

interstate ozone transport are warranted. 

That air quality analysis showed a 

substantial, continuing interstate 

transport problem for areas after 

implementation of the NOX SIP Call. 

The EPA does have the legal authority 

to reconsider the scope of the area that 

significantly contributes and the level of 

control determined to be ‘‘highly costeffective’’ based on new information. 

Updated information shows that lower 

NOX burners and SCR achieve better 

performance than previously estimated 

and as a result are more cost effective 

than previously anticipated. This rule 

follows the NOX SIP Call by six years; 

EPA does not believe that this 

represents a too-frequent re-evaluation, 

particularly given the stay of the 8-hour 

basis for the NOX SIP Call (See, e.g.,

CAA section 109(d)(1) requiring EPA to 

reevaluate the NAAQS themselves every 

five years.) So both updated air quality 

and cost information supports further 

25188 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

NOX controls to reduce interstate 

transport. 

Some commenters argued that EPA 

should delay imposing control 

obligations on upwind States for the 8-

hour ozone NAAQS until after EPA has 

implemented local control 

requirements, and after all of the NOX

SIP Call control requirements are 

implemented and evaluated. Others said 

EPA should not impose requirements on 

non-SIP-Call States until after all 8-hour 

controls—NOX SIP Call and local—are 

implemented. 

We agree that the NOX SIP Call 

should be taken into account in 

evaluating the need for further interstate 

transport controls. We have taken the 

NOX SIP Call into account by including 

the effect of the NOX SIP Call in the base 

case used for the CAIR analysis, and by 

conducting analyses to confirm that 

CAIR will achieve greater ozone-season 

reductions than the SIP Call. The EPA 

disagrees that the Agency should wait 

for implementation of local controls 

before determining transport controls. 

There is no legal requirement that EPA 

wait to determine transport controls 

until after local controls are 

implemented. The EPA’s basis for this 

legal interpretation is explained in 

section II.A. above. In addition, the 

Agency believes it is important to 

address interstate transport 

expeditiously for public health. 

C. Comments on Excluding Future Case 

Measures From the Emissions Baselines 

Used To Estimate Downwind Ambient 

Contribution 

The EPA received comments that the 

2010 analytical baseline for evaluating 

whether upwind emissions meet the air 

quality portion of the ‘‘contribute 

significantly’’ standard should reflect 

local control measures that will be 

required in the downwind 

nonattainment areas, or broader 

statewide measures in downwind states, 

to attain the PM2.5 or 8-hour ozone 

NAAQS by the relevant attainment 

dates, many of which are (or are 

anticipated to be) 2010 or earlier. This 

single target year was chosen both to 

address analytical tool constraints and 

to reasonably reflect future conditions 

in or near the initial attainment years for 

both ozone and PM nonattainment 

areas. The EPA did include in the 

baseline most of the specifically 

required measures that can be identified 

at this time, but did not include any 

further measures that would be needed 

for satisfying ‘‘rate of progress’’

requirements or for attainment of the 

PM2.5 and 8-hour ozone standards. If 

EPA had included further local controls, 

the commenters contend, fewer upwind 

States would have exceeded our 

significant contribution thresholds.

We reject any notion that in 

determining the need for transport 

controls in upwind states, EPA should 

assume that the affected downwind 

areas must ‘‘go all the way first’’—that 

is, assume that downwind areas put on 

local in-state controls sufficient to reach 

attainment, or assume that downwind 

states with nonattainment areas 

implement statewide control measures. 

The EPA does not believe these are 

appropriate assumptions. The former 

assumption would eviscerate the 

meaning of CAA section 110(a)(2)(D). 

The latter assumption would make the 

downwind state solely responsible for 

reductions in any case where a 

downwind state could attain through instate controls alone, even if the upwind 

state contribution was significantly 

contributing to nonattainment problems 

in the downwind state. We do not 

believe that this approach would be 

consistent with the intent of section 

110(a)(2)(D), which in part is to hold 

upwind states responsible for an 

appropriate share of downwind 

nonattainment and maintenance 

problems, and to prevent scenarios in 

which downwind states must impose 

costly extra controls to compensate for 

significant pollution contributions from 

uncontrolled or poorly controlled 

sources in upwind states. In addition, 

this approach could raise costs of 

meeting air quality standards because 

highly cost effective controls in upwind 

States would be foregone. 

Rather, in the particular 

circumstances presented here, we think 

the adoption of regional controls at this 

time under section 110(a)(2)(D) is 

consistent with sound policy and 

section 110. Based on our analysis, the 

states covered by CAIR make a 

significant contribution to downwind 

nonattainment and the required 

reductions are highly cost effective. The 

reductions will reduce regional 

pollution problems affecting multiple 

downwind areas, will make it possible 

for States to determine the extent of 

local control needed knowing the 

reductions in interstate pollution that 

are required, will address interstate 

equity issues that can hamper control 

efforts in downwind States, and reflect 

considerations discussed in detail in 

section VII. 

Although some commenters 

advocated specifically including 

statutorily mandated future 

nonattainment area controls in the 

analytical baseline, it would be difficult 

as a practical matter to predict the 

extent of local controls that will be 

required (beyond controls previously 

required) in each area in advance of 

final implementation rules interpreting 

the Act’s requirements for PM2.5 and 8-

hour ozone, and before the state 

implementation plan process. Subpart 2 

provisions that apply to certain ozone 

nonattainment areas are quite specific 

regarding some mandatory measures; we 

believe the CAIR baseline for the most 

part captures these measures. (See 

Response to Comments document in the 

docket.) As noted above, the choice of 

a single analytical year of 2010 was 

made to reflect baseline conditions at a 

date at or near the attainment dates for 

different pollutants and classes of areas. 

Because the attainment date for many 

ozone areas is 2009 or earlier, it should 

be noted that the analyses in 2010 may 

slightly overestimate the benefits of a 

number of national rules for mobile 

sources that grow with time. As noted 

elsewhere, these differences are unlikely 

to be significant. 

D. What Criteria Should Be Used To 

Determine Which States Are Subject to 

This Rule Because They Contribute to 

PM2.5 Nonattainment? 

1. What Is the Appropriate Metric for 

Assessing Downwind PM2.5

Contribution? 

a. Notice of Proposed Rulemaking 

In the NPR, we proposed as the metric 

for identifying a State as significantly 

contributing (depending upon further 

consideration of costs) to downwind 

nonattainment, the predicted change, 

due to the upwind State’s emissions, in 

PM2.5 concentration in the downwind 

nonattainment area that receives the 

largest ambient impact. The EPA 

proposed this metric in the form of a 

range of alternatives for a ‘‘bright line,’’

that is, ambient impacts at or greater 

than the chosen threshold level 

indicated that the upwind State’s 

emissions do contribute significantly 

(depending on cost considerations), and 

that ambient impacts below the 

threshold mean that the upwind State’s 

emissions do not contribute 

significantly to nonattainment. As 

detailed in section VI below, EPA 

conducted the analysis through air 

quality modeling that removed the 

upwind State’s anthropogenic SO2 and 

NOX emissions, and determined the 

difference in downwind ambient PM2.5

levels before and after removal. The 

modeling results indicate a wide range 

of maximum downwind nonattainment 

impacts from the 37 States that we 

evaluated. The largest maximum 

contribution is 1.67 micrograms per 

cubic meter (μg/m3), from Ohio to both 

Allegheny and Beaver counties in 

Pennsylvania. 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25189

b. Comments and EPA’s Responses

The EPA proposed to use the 

maximum contribution on any 

downwind nonattainment area for 

assessing downwind PM2.5

contributions. Many commenters 

expressed agreement with our proposed 

metric, however, many others disagreed. 

One group of these commenters 

indicated that EPA should distinguish 

the relative contribution from States 

using two parameters: (1) How many 

downwind nonattainment receptors 

they contribute to, and (2) how much 

they contribute to each such receptor. 

The commenters indicated that this 

approach would avoid inequities 

created by the disproportionate impact 

of some upwind contributors on their 

downwind neighbors. The EPA 

interprets these comments to suggest a 

metric that collectively includes both of 

these parameters, such as the sum of all 

downwind impacts on all affected 

receptors. This metric would result in 

higher values for States contributing to 

multiple receptors and at relatively high 

levels, and lower values for States 

contributing to fewer receptors and at 

relatively low levels. 

The EPA’s proposed metric does 

address how much each State 

contributes to a downwind neighbor; 

however, EPA does not believe that 

multiple downwind receptors need to 

be impacted in order for a particular 

state to be required to make emissions 

reductions under CAA section 

110(a)(2)(D). Under this provision, an 

upwind State must include in the SIP 

adequate provisions that prohibit that 

State’s emissions that ‘‘contribute 

significantly to nonattainment in * * * 

any other State * * *.’’ (Emphasis 

added.) Our interpretation of this 

provision is that the emphasized terms 

make clear that the upwind State’s 

emissions must be controlled as long as 

they contribute significantly to a single 

nonattainment area. 

One commenter agreed with EPA’s 

use of maximum annual average 

downwind contribution, but suggested 

that EPA consider additional metrics 

such as: (a) Contributions to adverse 

health and welfare effects from shortterm PM2.5 concentrations; (b) 

contributions to worst 20 percent haze 

levels in Class 1 areas; and (c) 

contributions to adverse effects of sulfur 

and nitrogen deposition to acid 

sensitive surface waters and forest soils. 

The EPA appreciates that these metrics 

all have merit in their focus on the 

health and environmental consequences 

of emissions, however, in determining a 

metric for significant contributions, we 

must focus on implementation of CAA 

section 110(a)(2)(D) provisions 

regarding significant contribution to 

nonattainment of the PM2.5 NAAQS. 

Another commenter suggested EPA 

use the maximum annual average 

impact, as we proposed, but add the 

maximum daily PM2.5 contribution. The 

commenter notes that this additional 

metric would indicate whether specific 

meteorological events drive the 

concentration change or whether there 

is a consistent pattern of transport from 

one area to another. It is not clear to 

EPA how the single data point of the 

maximum daily contribution indicates a 

consistent pattern of transport from one 

area to another since it is a measure 

from only a single day. Further, EPA 

does not agree that multiple days of 

impact is a relevant criterion for 

evaluating whether a State contributes 

significantly to nonattainment, since in 

theory, a single high-contribution event 

could be the cause or a substantial 

element of nonattainment of the annual 

average PM2.5 standard. Because we 

currently do not observe nonattainment 

of the daily average PM2.5 standard in 

Eastern areas, nonattainment of the 

annual average PM2.5 standard is the 

relevant evaluative measure. 

Some commenters suggested 

separately evaluating the NOX- and SO2-

related impacts (i.e., particulate nitrate 

and particulate sulfate) on 

nonattainment. As discussed in section 

II of this notice, EPA’s approach to 

evaluating a State’s impact on 

downwind nonattainment by 

considering the entirety of the State’s 

SO2 and NOX emissions is consistent 

with the chemical interactions in the 

atmosphere of SO2 and NOX in forming 

PM2.5. The contributions of SO2 and 

NOX emissions are generally not 

additive, but rather are interrelated due 

to complex chemical reactions. 

c. Today’s Action

The EPA continues to believe that for 

each upwind State analyzed, the change 

in the annual PM2.5 concentration level 

in the downwind nonattainment area 

that receives the largest impact is a 

reasonable metric for determining 

whether a State passes the ‘‘air quality’’

portion of the ‘‘contribute significantly’’

test, and therefore that State should be 

considered further for emissions 

reductions (depending upon the cost of 

achieving those reductions). This single 

concentration-based metric is adequate 

to capture the impact of SO2 and NOX

emissions on downwind annual PM2.5

concentrations. 

2. What Is the Level of the PM2.5

Contribution Threshold? 

a. Notice of Proposed Rulemaking 

In the NPR, EPA proposed to establish 

a State-level annual average PM2.5

contribution threshold from 

anthropogenic SO2 and NOX emissions 

that was a small percentage of the 

annual air quality standard of 15.0 μg/

m3. The EPA based this proposal on the 

general concept that an upwind State’s 

contribution of a relatively low level of 

ambient impact should be regarded as 

significant (depending on the further 

assessment of the control costs). We 

based our reasoning on several factors. 

The EPA’s modeling indicates that at 

least some nonattainment areas will find 

it difficult or impossible to attain the 

standards without reductions in upwind 

emissions. In addition, our analysis of 

‘‘base case’’ PM2.5 transport shows that, 

in general, PM2.5 nonattainment 

problems result from the combined 

impact of relatively small contributions 

from many upwind States, along with 

contributions from in-State sources and, 

in some cases, substantially larger 

contributions from a subset of particular 

upwind States. In the NOX SIP Call 

rulemaking, we termed this pattern of 

contribution—which is also present for 

ozone nonattainment—‘‘collective 

contribution.’’

In the case of PM2.5, we have found 

collective contribution to be a 

pronounced feature of the PM2.5

transport problem, in part because the 

annual nature of the PM2.5 NAAQS 

means that throughout the entire year 

and across a range of wind patterns—

rather than during just one season of the 

year or on only the few worst days 

during the year which may share a 

prevailing wind direction—emissions 

from many upwind States affect the 

downwind nonattainment area. 

As a result, to address the transport 

affecting a given nonattainment area, 

many upwind States must reduce their 

emissions, even though their individual 

contributions may be relatively small. 

Moreover, as noted above, EPA’s air 

quality modeling indicates that at least 

some nonattainment areas will find it 

difficult or impossible to attain the 

standards without reductions in upwind 

emissions. In combination, these factors 

suggest a relatively low value for the 

PM2.5 transport contribution threshold is 

appropriate. For reasons specified in the 

NPR (69 FR 4584), EPA initially 

proposed a value of 0.15 μg/m3 (1% of 

the annual standard) for the significance 

criterion, but also presented analyses 

based on an alternative of 0.10 μg/m3

and called for comment on this 

alternative as well as on ‘‘the use of 

25190 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

39 In attainment modeling for the annual PM2.5

NAAQS, results are carried to the second place 

beyond the decimal, in contrast to the three places 

beyond decimal noted above for the proposed 

threshold.

higher or lower thresholds for this 

purpose’’ (69 FR 4584). 

The EPA adopted a conceptually 

similar approach to that outlined above 

for determining that the significance 

level for ozone transport in the NOX SIP 

Call rulemaking should be a small 

number relative to the NAAQS. The DC 

Circuit Court, in generally upholding 

the NOX SIP Call, viewed this approach 

as reasonable. Michigan v. EPA, 213 

F.3d 663, 674–80 (DC Cir. 2000), cert. 

denied, 532 U.S. 904 (2001). After 

describing EPA’s overall approach of 

establishing a significance level and 

requiring States with impacts above the 

threshold to implement highly costeffective reductions, the Court 

explained: ‘‘EPA’s design was to have a 

lot of States make what it considered 

modest NOX reductions * * *. ’’ Id. at 

675. Indeed, the Court intimated that 

EPA could have established an even 

lower threshold for States to pass the air 

quality component:

The EPA has determined that ozone has some 

adverse health effects—however slight—at 

every level [citing National Ambient Air 

Quality Standards for Ozone, 62 FR 38856 

(1997)]. Without consideration of cost it is 

hard to see why any ozone-creating 

emissions should not be regarded as fatally 

‘‘significant’’ under section 

110(a)(2)(D)(i)(I).’’

213 F.3d at 678 (emphasis in original).

We believe the same approach applies 

in the case of PM2.5 transport. 

b. Comments and EPA’s Responses 

Many commenters indicated that EPA 

did not adequately justify the proposed 

annual average PM2.5 contribution 

threshold level of 0.15 μg/m3. Some 

commenters favor the alternative 0.10 

μg/m3 proposed by EPA, citing their 

agreement with EPA’s rationale for 0.10 

μg/m3 while criticizing as arbitrary 

EPA’s rationale for 0.15 μg/m3. 

Some commenters argued that the 

public health impact portion of EPA’s 

rationale for establishing a relatively 

low-level threshold was not relevant. 

The commenters said that EPA 

previously determined, in establishing 

the PM2.5 NAAQS, that ambient levels at 

or above 15.0 μg/m3 were of concern for 

protecting public health, not the much 

lower levels that EPA proposed as the 

thresholds. In the NPR, we stated that 

we considered that there are significant 

public health impacts associated with 

ambient PM2.5, even at relatively low 

levels. In generally upholding the NOX

SIP Call, the DC Circuit noted a similar 

reason for establishing a relatively low 

threshold for ozone impacts. Michigan

v. EPA, 213 F.3d 663, 678 (DC Cir. 

2000), cert. denied, 532 U.S. 904 (2001). 

The EPA notes that by using a metric 

that focuses on the contribution of 

upwind areas to downwind areas that 

are above 15.0 μg/m3, relatively low 

contributions to levels above the annual 

PM2.5 standard are highly relevant to 

public health protection. 

Many commenters offered alternative 

thresholds higher than 0.15 μg/m3, 

citing previous EPA rules or policies as 

justification for the alternative level. 

Some suggested the PM2.5 threshold 

should be equivalent in percentage 

terms to the threshold employed for 

assessing maximum downwind 8-hour 

ozone contributions. The threshold for 

maximum downwind 8-hour ozone 

concentration impact used in the NOX

SIP Call, and proposed for use in the 

CAIR, is 2 parts per billion (ppb), or 

about 2.5 percent of the standard level 

of 80 ppb. Applying the 2.5 percent 

criterion to the 15.0 μg/m3 annual PM2.5

standard would yield a significance 

threshold of 0.35 μg/m3. 

The EPA disagrees with the comment 

that the thresholds for annual PM2.5 and 

8-hour ozone should be an equivalent 

percentage of their respective NAAQS. 

Both the forms and averaging times of 

the two standards are substantially 

different, with 8-hour ozone based on 

the average of the 4th highest daily 8-

hour maximum values from each of 3 

years, and PM2.5 based on the average of 

annual means from 3 successive years. 

These fundamental differences in time 

scales, and thus in the patterns of 

transport that are relevant to 

contributing to nonattainment, do not 

suggest a transparent reason for 

presuming that the contribution 

thresholds should be equivalent. As 

discussed above, when more States 

make smaller individual contributions 

because of the annual nature of the 

PM2.5 standard, it makes sense to have 

a threshold for PM2.5 that is a smaller 

percentage of its NAAQS. 

Other commenters suggested that in 

setting the maximum downwind PM2.5

threshold, EPA should take into 

consideration the measurement 

precision of existing PM2.5 monitors. 

The commenters assert that such 

measurement carries ‘‘noise’’ in the 

range of 0.5—0.6 μg/m3. Because many 

daily average monitor readings are 

averaged to calculate the annual 

average, the precision of the annual 

average concentration is better than the 

figures cited by the commenters. Indeed, 

the annual standard is expressed as 15.0 

μg/m3, rounded to the nearest 1⁄10 μg, 

because such small differences are 

meaningful on an annual basis. While 

disagreeing with the specific amounts 

suggested by commenters, EPA 

recognizes that the PM2.5 threshold 

specified in the proposal contains two 

digits beyond the decimal place, while 

the NAAQS specifies only one. The EPA 

agrees that specification of a threshold 

value of 0.15 μg/m3 does suggest an 

overly precise test that might need to 

take into account modeled difference in 

PM2.5 values as low as 0.001 μg/m3. 

Other commenters indicated that 

modeling ‘‘noise’’—that is, 

imprecision—is a relevant consideration 

for establishing a threshold whose 

evaluation depends on air quality 

modeling analysis. These commenters 

indicated that a threshold of 5 percent 

of the NAAQS (i.e., 0.75 μg/m3) is more 

reasonable considering modeling 

sensitivity. The commenters were not 

clear about what they mean by modeling 

‘‘noise’’ and did not explain how it 

relates to the use of a threshold metric 

in the context of the CAIR. 

In responding to the comment, we 

have considered some possible 

contributors to what the commenter 

describes as ‘‘noise.’’ There is the 

possibility that the air quality model has 

a systematic bias in predicting 

concentrations resulting from a given set 

of emissions sources. The EPA uses the 

model outputs in a relative, rather than 

an absolute, sense so that any modeling 

bias is constrained by real world results. 

As described further in section VI, EPA 

conducts a relative comparison of the 

results of a base case and a control case 

to estimate the percentage change in 

ambient PM2.5 from the current year 

base case, holding meteorology, other 

source emissions, and other factors 

contributing to uncertainty constant. 

With this technique, any absolute 

modeling bias is cancelled out because 

the same model limitations and 

uncertainties are present in each set of 

runs. 

Another possible source of noise is in 

the relative comparison of two model 

runs conducted on different computers. 

Since the computers used by EPA to run 

air quality models do not have any 

significant variability in their numerical 

processes, two model runs with 

identical inputs result in outputs that 

are identical to many significant digits. 

On the other hand, EPA believes it is 

not appropriate or necessary to carry 

such results to a level of precision that 

is beyond that required by the PM2.5

NAAQS itself 39.

Many commenters noted that EPA’s 

proposed threshold of 0.15 μg/m3, or 

one percent of the annual PM2.5 NAAQS 

of 15.0 μg/m3, is lower than the singlesource contribution thresholds 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25191

40See 40 CFR 51.165(b)(2). New or modified 

major sources in attainment or unclassifiable areas 

must undergo preconstruction permit review, adopt 

best available control technology, and obtain 

emissions offsets if they are determined to ‘‘cause 

or contribute’’ to a violation of the NAAQS. ‘‘Cause 

or contribute’’ is defined as an impact that exceeds 

5 μg/m3 (3.3 percent) of the 150 μg/m3 24-hour 

average PM10 NAAQS , or 1 μg/m3 (2 percent) of 

the annual average PM10 NAAQS.

41See 40 CFR 51.166(i)(5)(i). Proposed new 

sources or existing-source modifications that would 

contribute less than 10 μg/m3 (or 5.3%) of the 150 

μg/m3 PM10 24-hour average NAAQS, estimated 

using on a screening model, may avoid the 

requirement of collecting and submitting ambient 

air quality data.

42This truncation convention for PM2.5 is similar 

to that used in evaluating modeling results in 

applying the ozone significance screening criterion 

of 2 ppb in the NOX SIP call and the CAIR proposal 

(Technical Support Document for the Interstate Air 

Quality Rule Air Quality Modeling Analyses’’, 

January 2004. Docket # OAR–2003–0053–0162), as 

well as today’s final action. 43Today’s action, including the updated 

modeling, fulfills EPA’s commitment in the NOX

SIP Call (which EPA finalized in 1998) to reevaluate 

interstate ozone contributions by 2007. See 63 FR 

57399; October 27, 1998.

44See the CAIR Air Quality Modeling TSD for 

description of the methodology used to calculate 

these metrics.

employed for PM10 in certain other 

regulatory contexts. Commenters cited 

several different thresholds, including 

thresholds governing the applicability of 

the preconstruction review permit 

program and the emissions reduction 

requirement for certain major new or 

modified stationary sources located in 

attainment or unclassified areas;40 and 

thresholds in the PSD rules that may 

relieve proposed sources from 

performing comprehensive ambient air 

quality analyses.41

Since the thresholds referred to by the 

commenters serve different purposes 

than the CAIR threshold for significant 

contribution, it does not follow that they 

should be made equivalent. The 

implication of the thresholds cited by 

the commenters is not that single-source 

contributions below these levels 

indicate the absence of a contribution. 

Rather, these thresholds address 

whether further more comprehensive, 

multi-source review or analysis of 

appropriate control technology and 

emissions offsets are required of the 

source. A source with estimated impacts 

below these levels is recognized as still 

affecting the airshed and is subject to 

meeting applicable control 

requirements, including best available 

control technology, designed to 

moderate the source’s impact on air 

quality. The purpose of the CAIR 

threshold for PM2.5 is to determine 

whether the annual average contribution 

from a collection of sources in a State 

is small enough not to warrant any 

additional control for the purpose of 

mitigating interstate transport, even if 

that control were highly cost effective. 

One commenter suggested that EPA 

also establish and evaluate a threshold 

for a potential new tighter 24-hour PM2.5

standard (e.g., 1 percent of 30 μg/m3). 

The EPA must base its criteria on 

evaluation of the current PM2.5

standards and not standards that may be 

considered in the future. 

c. Today’s Action

The EPA continues to believe that the 

threshold for evaluating the air quality 

component of determining whether an 

individual State’s emissions ‘‘contribute 

significantly’’ to downwind 

nonattainment of the annual PM2.5

standard, under CAA section 

110(a)(2)(D) should be very small 

compared to the NAAQS. We are, 

however, persuaded by commenters 

arguments on monitoring and modeling 

that the precision of the threshold 

should not exceed that of the NAAQS. 

Rounding the proposal value of 0.15, the 

nearest single digit corresponding to 

about 1% of the PM2.5 annual NAAQS 

is 0.2 μg/m3. The final rule is based on 

this threshold. The EPA has decided to 

apply this threshold such that any 

model result that is below this value 

(0.19 or less)indicates a lack of 

significant contribution, while values of 

0.20 or higher exceed the threshold.42

Using this metric for determining 

whether a State ‘‘contributes 

significantly’’ (before considering cost) 

to PM2.5 nonattainment, our updated 

modeling shows that Kansas, 

Massachusetts, New Jersey, Delaware, 

and Arkansas (all included in the 

original proposal) no longer exceed the 

0.2 μg/m3 annual average PM2.5

contribution threshold. Of these states, 

only Arkansas would exceed the 

threshold of 0.15 μg/m3 that was 

included in the proposal. 

E. What Criteria Should Be Used To 

Determine Which States Are Subject to 

This Rule Because They Contribute to 

Ozone Nonattainment? 

1. Notice of Proposed Rulemaking 

In assessing the contribution of 

upwind States to downwind 8-hour 

ozone nonattainment, EPA proposed to 

follow the approach used in the NOX

SIP Call and to employ the same 

contribution metrics, but with an 

updated model and updated inputs that 

reflect current requirements (including 

the NOX SIP Call itself).43

The air quality modeling approach we 

proposed to quantify the impact of 

upwind emissions includes two 

different methodologies: Zero-out and 

source apportionment. As described in 

section VI, EPA applied each 

methodology to estimate the impact of 

all of the upwind State’s NOX emissions 

on each downwind nonattainment 

areas. 

The EPA’s first step in evaluating the 

results of these methodologies was to 

remove from consideration those States 

whose upwind contributions were very 

low. Specifically, EPA considered an 

upwind State not to contribute 

significantly to a downwind 

nonattainment area if the State’s 

maximum contribution to the area was 

either (1) less than 2 ppb, as indicated 

by either of the two modeling 

techniques; or (2) less than one percent 

of total nonattainment in the downwind 

area.44

If the upwind State’s impact exceeded 

these thresholds, then EPA conducted a 

further evaluation to determine if the 

impact was high enough to meet the air 

quality portion of the ‘‘contribute 

significantly’’ standard. In doing so, 

EPA organized the outputs of the two 

modeling techniques into a set of 

‘‘metrics.’’ The metrics reflect three key 

contribution factors: 

• The magnitude of the contribution 

(actual amount of ozone contributed by 

emissions in the upwind State to 

nonattainment in the downwind area); 

• The frequency of the contribution 

(how often contributions above certain 

thresholds occur); and 

• The relative amount of the 

contribution (the total ozone 

contributed by the upwind State 

compared to the total amount of 

nonattainment ozone in the downwind 

area). 

The specific metrics on which EPA 

proposed to rely are the same as those 

used in the NOX SIP Call. Table III–1 

lists them for each of the two modeling 

techniques, and identifies their 

relationship to the three key 

contribution factors.

25192 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

TABLE III–1.—OZONE CONTRIBUTION FACTORS AND METRICS

Factor 

Modeling technique 

Zero-out Source apportionment 

Magnitude of Contribution .................... Maximum contribution ............................................. Maximum contribution; and Highest daily average 

contribution (ppb and percent). 

Frequency of Contribution .................... Number and percent of exceedances with contributions in various concentration ranges.Number and percent of exceedances with contributions in various concentration ranges. 

Relative Amount of Contribution .......... Total contribution relative to the total exceedance 

ozone in the downwind area; and.

Population-weighted total contribution relative to 

the total population-weighted exceedance ozone 

in the downwind area.

Total average contribution to exceedance hours in 

the downwind area. 

In the NPR, EPA proposed threshold 

values for the metrics. An upwind State 

whose contribution to a downwind area 

exceeded the threshold values for at 

least one metric in each of at least two 

of the three sets of metrics was 

considered to contribute significantly 

(before considering cost) to that 

downwind area. To reiterate, the three 

sets of metrics reflect the factors of 

magnitude of contribution, frequency of 

contribution, and relative percentage on 

nonattainment. 

In fact, EPA noted in the NPR that for 

each upwind State, the modeling 

disclosed at least one linkage with a 

downwind nonattainment area in which 

all factors (magnitude, frequency, and 

relative amount) were found to indicate 

large and frequent contributions. In 

addition, EPA noted in the NPR that 

each upwind State contributed to 

nonattainment problems in at least two 

downwind States (except for Louisiana 

and Arkansas which contributed to 

nonattainment in only 1 downwind 

State). 

In addition, EPA noted in the NPR 

that for most of the individual linkages, 

the factors yield a consistent result 

across all three sets of metrics (i.e., 

either (i) large and frequent 

contributions and high relative 

contributions or (ii) small and 

infrequent contributions and low 

relative contributions). In some 

linkages, however, not all of the factors 

are consistent. The EPA believes that 

each of the factors provides an 

independent, legitimate measure of 

contribution. 

In the NPR, EPA applied the 

evaluation methodology described 

above to each upwind-downwind 

linkage to determine which States 

contribute significantly (before 

considering cost) to nonattainment in 

the 40 downwind counties in 

nonattainment for ozone in the East. 

The analysis of the metrics for each 

linkage was presented in the AQMTSD 

for the NPR. The modeling analysis 

supporting the final rule is an update to 

the NPR modeling, and is described in 

more detail in section VI below. 

2. Comments and EPA Responses 

Some commenters submitted 

comments specifically on the 8-hour 

ozone metrics. One commenter asserted 

that in calculating the ‘‘Relative Amount 

of Contribution’’ metric, EPA treats the 

modeled reductions from zeroing out a 

State’s emissions as impacting only the 

portion of the downwind receptor’s 

ambient ozone level that exceeds the 8-

hour average 84 ppb level. The 

commenter asserted that this approach 

falsely treats the upwind state’s 

emissions as contributing to the amount 

of ozone that exceeds the NAAQS, and 

thus inflates the ambient impact of 

those emissions. The commenter 

concluded that it would be more 

appropriate to treat the upwind 

emissions as impacting all of the 

downwind ozone level (not just the 

portion greater than 84 ppb). We 

interpret this comment to mean that in 

expressing an upwind State’s 

contribution as a percentage, the 

denominator of the percentage should 

be the downwind area’s total ozone 

contribution, rather than the downwind 

area’s ozone excess above the NAAQS, 

but that the same threshold should be 

used to evaluate contribution. This 

would tend to result in fewer upwind 

States being found to be significant with 

respect to this metric. 

We believe that it is important to 

examine the ozone contribution relative 

to the amount of ozone above the 

NAAQS as well as the amount relative 

to total nonattainment ozone. Both 

approaches have merit. The intent of the 

relative contribution metric, as 

calculated for the zero-out modeling, is 

to view the contribution of the upwind 

State relative to the amount that the 

downwind area is in nonattainment; 

that is, the amount of ozone above the 

NAAQS. However, our relative amount 

metric for the source apportionment 

modeling does treat the amount of 

contribution relative to the total amount 

of ozone when ozone concentrations are 

predicted to be above the NAAQS. To be 

found a significant contributor, an 

upwind State must be above the 

threshold for both the zero-out-based 

metric and the source-apportionmentbased metric. Thus, our approach to 

considering the significance of interstate 

ozone transport captures both 

approaches for examining the relative 

amount of contribution and does not 

favor one approach over the other, as 

discussed above. 

3. Today’s Action 

The EPA is finalizing the 

methodology proposed in the NPR, and 

discussed above, for evaluating the air 

quality portion of the ‘‘contribute 

significantly’’ standard for ozone. 

F. Issues Related to Timing of the CAIR 

Controls 

1. Overview 

A number of commenters questioned 

the need for CAIR requirements 

considering that cap dates of 2010 and 

2015 are later than the attainment dates 

that, in the absence of extensions, 

would apply to certain downwind PM2.5

areas and ozone nonattainment areas. 

Other commenters, noting that states 

will be required to adopt controls in 

local attainment plans, questioned 

whether CAIR controls would still be 

needed to avoid significant contribution 

to downwind nonattainment, or 

whether the controls would still be 

needed to the extent required by the 

rule.

Of course, CAIR will achieve 

substantial reductions in time to help 

many nonattainment areas attain the 

standards by the applicable attainment 

dates. The design of the SO2 program, 

including the declining caps in 2010 

and 2015 and the banking provisions, 

will steadily reduce SO2 emissions over 

time, achieving reductions in advance of 

the cap dates; and the 2009 and 2015 

NOX reductions will be timely for many 

downwind nonattainment areas. 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25193

45As in the NOX SIP Call rulemaking, EPA 

interprets the ‘‘interfere with maintenance’’

statutory requirement ‘‘much the same as the term 

‘contribute significantly’ ’’, that is, ‘‘through the 

same weight-of-evidence approach.’’ 63 FR at 

57379. Furthermore, we believe the ‘‘interfere with 

maintenance’’ prong may come into play only in 

circumstances where EPA or the State can 

reasonably determine or project, based on available 

data, that an area in a downwind state will achieve 

attainment, but due to emissions growth or other 

relevant factors is likely to fall back into 

nonattainment. Id.

46This does not mean that the upwind state 

would be responsible for making all the reductions 

necessary to bring the downwind State’s 

nonattainment area into attainment; how much 

would be required of each State is a separate 

question. Again in the ideal world, we would be 

able to find the right mix of controls in both states 

so that attainment would be achieved at the lowest 

total cost.

47Tables describing cost effectiveness of various 

control measures and programs are provided in 

section IV. These show that the cost per ton of nonpower-sector control options that states might 

consider for attainment purposes typically is higher 

than for CAIR controls.

Although many of today’s 

nonattainment areas will attain before 

all the reductions required by CAIR will 

be achieved, it is clear that CAIR’s 

reductions will still be needed through 

2015 and beyond. The EPA’s air quality 

modeling has demonstrated that upwind 

States have a sufficiently large impact 

on downwind areas to require 

reductions in 2010 and 2015 under CAA 

section 110(a)(2)(D). Under this 

provision, SIPs must prohibit emissions 

from sources in amounts that ‘‘will 

contribute significantly to * * * 

nonattainment’’ or ‘‘will interfere with 

maintenance’’.45 The EPA has evaluated 

the attainment status of the downwind 

receptors in 2010 and 2015, and has 

determined that each upwind State’s 

2010 and 2015 emissions reductions are 

necessary to the extent required by the 

rule because a downwind receptor 

linked to that upwind State will either 

(i) remain in nonattainment and 

continue to experience significant 

contribution to nonattainment from the 

upwind State’s emissions; or (ii) attain 

the relevant NAAQS but later revert to 

nonattainment due, for example, to 

continued growth of the emissions 

inventory.

The argument that the CAIR 

reductions are justified, in part, by the 

need to prevent interference with 

maintenance, is a limited one. The EPA 

does not believe that the ‘‘interfere with 

maintenance’’ language in section 

110(a)(2)(D) requires an upwind state to 

eliminate all emissions that may have 

some impact on an area in a downwind 

state that is (or once was) in 

nonattainment and that, therefore, will 

need (or now needs) to maintain its 

attainment status. Instead, we believe 

that CAIR emission reductions are 

needed beyond 2010 and 2015, in part, 

to prevent upwind states from 

significantly interfering with 

maintenance in other states because our 

analysis shows it is likely that, in the 

absence of the CAIR, a current or 

projected attainment area will revert to 

nonattainment due to continued 

emissions growth or other relevant 

factors. We are not taking the position 

that CAIR controls are automatically 

justified to prevent interference with 

maintenance in every area initially 

modeled to be in nonattainment. 

We also note that considering the 

emission controls needed for 

maintenance, along with the controls 

needed to reach attainment in the first 

place, is consistent with the goal of 

promoting a reasonable balance between 

upwind state controls and local 

(including all in-state) controls to attain 

and maintain the NAAQS. As discussed 

in section IV of this notice, in the ideal 

world, the states and EPA would have 

enough information (and powerful 

enough analytical tools) to allow us to 

identify a mix of control strategies that 

would bring every area of the country 

into attainment at the lowest overall 

cost to society. Under such an approach, 

we would evaluate the impact of every 

emissions source on air quality in all 

nonattainment areas, the cost of 

different options for controlling those 

sources, and the cost-effectiveness of 

those controls in terms of cost per 

increment of air quality improvement. 

Such an approach would obviously 

make it easier for a state to develop an 

appropriate set of control requirements 

for sources located in that state based on 

(1) the need to bring its own 

nonattainment areas into attainment and 

(2) its responsibility under section 

110(a)(2)(D) to prevent significant 

contribution to nonattainment in 

downwind States and interference with 

maintenance in those States.

Such an approach would also make it 

much easier for the Agency to decide on 

efficiency grounds whether to take 

action under section 126 (or under 

section 110(a)(2)(D) if a State failed to 

meet its obligations under that section) 

for purposes of either attainment or 

maintenance of a NAAQS in another 

State. In the simplest example, we might 

need to consider a case in which a 

downwind State with a nonattainment 

area is seeking reductions from an 

upwind State based on the claim that 

emissions from the upwind state are 

contributing significantly to the 

nonattainment problem in the 

downwind State. In such a case, the first 

question is whether the upwind state 

should be required to take any action at 

all, and in the ideal world, it would be 

simple to answer this question. If 

emission reductions from sources in the 

upwind State are more cost-effective 

than emission reductions in the 

downwind State—in terms of cost per 

increment of improvement in air quality 

in the downwind nonattainment area—

then the upwind State would need to 

take some action to control emissions 

from sources in that State.46 On the 

other hand, if controls on sources in the 

upwind State are not more cost-effective 

in terms of cost per increment of 

improvement in air quality, then the 

Agency would not take action under 

sections 126 or 110(a)(2)(D); rather, the 

downwind State would need to meets 

its attainment and maintenance needs 

by controlling sources within its own 

jurisdiction. Of course, factors other 

than efficiency, such as equity or 

practicality, also might affect the 

decision.

Unfortunately, we do not have 

adequate information or analytical tools 

(ideally a detailed linear programming 

model that fully integrates both control 

costs and ambient impacts of sources in 

each State on each of the downwind 

receptors) to allow us to undertake the 

analysis described above at this time. 

However, the Agency believes that CAIR 

is consistent with this basic approach 

and will result in upwind States and 

downwind States sharing appropriate 

responsibility for attainment and 

maintenance of the relevant NAAQS, 

considering efficiency, equity and 

practical considerations. Under CAIR, 

the required reductions in upwind 

States (including those projected to 

occur after 2015) are highly cost 

effective, measured in cost-per-ton of 

emissions reduction, as documented in 

section IV. This suggests that, regardless 

of whether the CAIR reductions assist 

downwind areas in achieving 

attainment or in subsequently 

maintaining the relevant NAAQS, the 

upwind controls will be reasonable in 

cost relative to a further increment of 

local controls that, in most cases, will 

have a substantially higher cost per 

ton—particularly in areas that need 

greater local reductions and require 

reductions from a variety of source 

types.47 Thus, we believe that CAIR is 

consistent with the goal of attaining and 

maintaining air quality standards in an 

efficient, as well as equitable, manner.

Another reason for considering both 

attainment and maintenance needs at 

this time is EPA’s expectation that most 

nonattainment areas will be able to 

25194 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

48A similar glide path will occur prior to the 

effective date of the Phase I SO2 cap because this 

cap will complement and extend the cap that 

currently exists under the Acid Rain program.

attain the PM2.5 and 8-hour ozone 

standards within the time periods 

provided under the statute. Considering 

both types of downwind needs shows 

that there is a strong basis for CAIR’s 

requirements despite the potential for 

most receptor areas to attain before all 

the emission reductions required by 

CAIR are achieved. 

2. By Design, the CAIR Cap and Trade 

Program Will Achieve Significant 

Emissions Reductions Prior to the Cap 

Deadlines 

The EPA notes that Phase I of CAIR 

is the initial step on the slope of 

emissions reduction (i.e., the ‘‘glide 

path’’) leading to the final control levels. 

Because of the incentive to make early 

emission reductions that the cap and 

trade program provides, reductions will 

begin early and will continue to 

increase through Phases I and II. 

Therefore, all the required Phase II 

emission reductions will not take place 

on January 1, 2015, the effective date of 

the second phase cap. Rather, these 

reductions will accrue throughout the 

implementation period, as the sources 

install controls and start to test and 

operate them. The resulting glide path 

of reductions with CAIR Phase II will 

provide important reductions to areas 

coming into attainment over the 2010 to 

2014 period.48

3. Additional Justification for the SO2

and NOX Annual Controls

Our modeling indicates that it is very 

plausible that a significant number of 

downwind PM2.5 receptors are likely to 

remain in nonattainment in 2010 and 

beyond. As noted below (Preamble 

Table VI–10), the Agency has evaluated 

a wide range of emission control options 

and found that the average ambient 

reduction in PM2.5 concentrations 

achievable through aggressive but 

feasible local controls is 1.26 μg/m3. In 

the 2010 base case (which does not 

consider potential local controls or 2010 

CAIR controls, but does consider all 

other emission controls required to be in 

effect as of that date), nearly half the 

receptor counties would be in 

nonattainment by more than this 

amount. This indicates that 

nonattainment is of sufficient severity to 

make it likely that, in the absence of 

CAIR, many of these areas would need 

an attainment date extension of at least 

one year. 

Our base case modeling further shows 

that every upwind state is linked to at 

least one receptor area projected to have 

nonattainment of this severity. Tables 

VI–10 and VI–11. Thus, there is a 

reasonable likelihood that CAIR controls 

will be needed from all of the upwind 

states to prevent significant contribution 

to these downwind receptors’

nonattainment. 

Nor is the amount of reduction in 

excess of what is needed for attainment. 

We project that even with CAIR 

controls, almost all of the upwind states 

in 2010 remain linked with at least one 

downwind receptor that would not 

attain by the same substantial margin 

exceeding the average of aggressive local 

controls. Tables VI–10 and VI–8. This 

not only indicates that the 2010 CAIR 

controls are not excessive, but that local 

controls will still be necessary for 

attainment. 

In addition, there is potential for 

residual nonattainment in 2015 in view 

of the severity of PM2.5 levels in some 

areas, uncertainties about the levels of 

reductions in PM2.5 and precursors that 

will prove reasonable over the next 

decade, the potential for up to two 1-

year extensions for areas that meet 

certain air quality levels in the year 

preceding their attainment date, and 

historical examples in which areas did 

not meet their statutory attainment dates 

for other NAAQS. 

With respect to the argument that 

phase II emission reductions that will be 

achieved after 2015 are not needed 

because all receptors will have attained 

before 2015, we think it likely that some 

PM2.5 nonattainment areas may qualify 

for 2014 attainment dates and 

eventually, one-year attainment date 

extensions, and that there may be 

residual nonattainment in 2015. We 

continue to project that nearly half the 

downwind receptors in the 2015 base 

case will be in nonattainment by 

amounts exceeding the average ambient 

reduction (again, 1.26 μg/m3) 

attributable to local controls we believe 

would be aggressive but feasible for 

2010. Table VI–11. The history of 

progress in development of emission 

reduction strategies and technologies 

indicates that greater local reductions 

could be achieved by 2015 than in 2010; 

nonetheless, this potential 

nonattainment is of sufficient severity to 

make it plausible that at least some of 

these areas will need an extension. In 

such cases, this would eliminate the 

issue of timing raised by commenters, 

since CAIR controls would no longer be 

following attainment dates. 

Our modeling further shows that, in 

the 2015 base case (which does not 

include CAIR controls), all the upwind 

states in the CAIR region are linked to 

areas projected to exceed the standard 

by at least 2 μg/m3. Tables VI–11 and 

VI–8. Given the reasonable potential for 

continued nonattainment, it is 

reasonable to require 2015 CAIR 

controls from each upwind state to 

prevent significant contribution to 

nonattainment. 

Moreover, even with 2015 CAIR 

controls (but not attainment SIP 

controls), almost all of the upwind 

states remain linked with at least one 

downwind receptor that would not 

attain by at least this same substantial 

margin (at least 1.26 μg/m3). Id. This 

shows that the 2015 CAIR controls are 

not more than are necessary to attain the 

NAAQS (and also shows the necessity 

for local controls in order to attain). 

Thus, we conclude that the further 

PM2.5 reductions achieved by the second 

phase cap will likely be needed to 

assure all relevant areas reach 

attainment by applicable deadlines.

Even if some of these areas make more 

progress than we predict, many 

downwind receptor areas would be 

likely in 2010 and 2015 to continue to 

have air quality only marginally better 

than the standard, and be at risk of 

returning to nonattainment. Air quality 

is unlikely to be appreciably cleaner 

than the standard because many areas 

will need steep reductions merely to 

attain, given that we project 

nonattainment by wide margins (as 

explained above). 

Moreover, we project that without 

CAIR, PM2.5 levels would worsen in 19 

downwind receptor counties between 

2010 and 2015, reflecting changes in 

local and upwind emissions. Air 

Quality Modeling Technical Support 

Document, November, 2004. This 

suggests a reasonable likelihood that, 

without CAIR, these areas would return 

to nonattainment. See 63 FR at 57379–

80 (finding in NOX SIP Call that upwind 

emissions interfere with maintenance of 

8-hour ozone standard under section 

110(a)(2)(D)(i) where increases in 

emissions of ozone precursors are 

projected due to growth in emissions 

generating activity, resulting in 

receptors no longer attaining the 

standard). These downwind receptors 

link to all but two of the upwind states, 

and the remaining two upwind states 

are linked to receptors where projected 

PM2.5 levels between 2010 and 2015 

improve only slightly, leaving their air 

quality only marginally in attainment. 

Response to Comments, section III.C. In 

light of documented year-to-year 

variations in PM2.5 levels, these 

receptors would have a reasonable 

probability of returning to 

nonattainment in the absence of CAIR. 

Emissions trends after 2015 give rise 

to further maintenance concerns. 

Between 2015 and 2020, emissions of 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25195

49Attainment deadlines for moderate ozone areas 

are to be no later than June 2010; an approvable 

attainment plan must demonstrate the reductions 

needed for attainment will be achieved by the 

ozone season in the preceding year.

50We recognize that in the absence of substantial 

evidence, variability alone would not be a sufficient 

basis for applying the ‘‘interfere with maintenance’’

prong of section 110(a)(2)(D). Here, however, where 

there is a substantial body of historical data 

documenting the variability in ozone 

concentrations, we believe it is appropriate to 

consider variability in determining whether 

emission reductions from upwind states are 

necessary to prevent interference with maintenance 

of the ozone standard in downwind states.

PM2.5 and certain precursors are 

projected to rise. We do not have air 

quality modeling for 2020. However, for 

PM2.5 and every precursor, the 2015–

2020 emission trend is less favorable 

than the 2010–2015 emission trend. 

Given the PM2.5 increases our air quality 

modeling found for 19 counties between 

2010 and 2015, the emission trends 

suggest greater maintenance concerns in 

the 2015–2020 period than during the 

2010–2015 period. See Response to 

Comments section III.C. 

Accordingly, we believe that given 

these projected trends, and the 

likelihood of only borderline 

attainment, CAIR controls from every 

upwind state in the CAIR region are 

needed to prevent interference with 

maintenance of the PM2.5 standard. The 

projected upwards pressure on PM2.5

concentrations in most receptor areas 

indicates that the amount of upwind 

reductions is not more than necessary to 

prevent interference with maintenance 

of the standards, again given the 

likelihood of initial attainment by 

narrow margins. 

4. Additional Justification for Ozone 

NOX Requirements 

We believe that most 8-hour ozone 

areas will be able to attain by their 

attainment deadlines through existing 

measures, 2009 CAIR NOX reductions, 

and additional local measures. 

However, we also believe that a limited 

number of downwind receptor areas 

will remain in nonattainment with the 

ozone standard after 2010. This is due 

to the severity of projected ozone levels 

in certain areas, uncertainties about the 

levels of emissions reductions in that 

will prove reasonable over the next 

decade, and historical difficulties with 

attaining the 1-hour ozone standard. 

For ozone, the historic difficulties that 

many areas, particularly large urban 

areas, have experienced in attaining the 

ozone NAAQS raises the possibility that 

some areas may not attain by their 

attainment dates, and may request a 

voluntary bump up to a higher 

classification pursuant to section 

181(b)(2) to gain an extension, or may 

fail to attain by the attainment date and 

be bumped up under section 181(b)(2). 

These authorities were used in the 

course of implementing the 1-hour 

ozone NAAQS.

Our base case modeling (without 

CAIR, and without state controls 

implementing the 8-hour standard) 

projects geographically widespread 

nonattainment with the 8-hour ozone 

NAAQS in 2015. Tables VI–12 and VI–

13. Five counties that link to 14 upwind 

states have projected ozone levels that 

exceed the 8-hour standard by 6 ppb or 

more, and 20 upwind states are linked 

to counties projected to exceed the 8-

hour standard by more than 4 ppb. 

These two sets of linkages show that 

under a scenario in which several of the 

receptors with the highest ozone levels 

did not attain, CAIR reductions would 

be justified to prevent significant 

contributions from many of the upwind 

states in the CAIR ozone region. 

The fact that receptors show 

significant nonattainment even after 

implementation of the phase II CAIR 

reductions, as shown in Table VI–13, 

indicates that these reductions would 

not be more than necessary to prevent 

significant contribution to 

nonattainment in residual areas. Even if 

all ozone nonattainment areas in the 

CAIR region could achieve reductions 

sufficient to meet the level of the 8-hour 

ozone standard in 2009 49 based on local 

controls, 2009 CAIR NOX reductions, 

and existing programs, we believe that 

numerous downwind receptor areas 

would remain close enough to the 

standard to be at risk of falling back into 

nonattainment for the reasons discussed 

below. These receptor areas are linked 

to all states in the CAIR ozone region.

First, it is highly unlikely that the 

receptor areas will be able to attain by 

a wide margin. This is primarily 

because many of those areas will need 

substantial emissions reductions merely 

to attain. This is supported by modeling 

showing that in the 2010 base case, 30 

percent of the receptors are projected to 

be in nonattainment by the wide margin 

of 6 ppb or more, indicating the steep 

emissions reductions necessary just to 

come into attainment. Table VI–12. We 

recognize that, unlike the trend in key 

PM receptor areas, our modeling 

projects that the ozone levels in ozone 

receptor areas will improve somewhat 

between 2010 and 2015 due chiefly to 

downward trends in NOX emissions 

projected under existing requirements. 

Nonetheless, as shown in detail in the 

Response to Comments, the projected 

improvements in ozone levels in the 

receptor areas are less (often 

considerably less) than historic 

variability in monitored 8-hour ozone 

design values from one three year 

period to the next.50 We believe this 

variability is mostly attributable to 

changing weather conditions (which 

significantly affect the rate at which 

ozone is formed in the atmosphere and 

movement of ozone after it is formed), 

rather than variability in the emissions 

inventory. Thus, absent the second 

phase CAIR cap, these receptors remain 

vulnerable to falling back into 

nonattainment. The receptors for which 

this is the case link to each of the 

upwind States in the ozone CAIR 

region.

IV. What Amounts of SO2 and NOX

Emissions Did EPA Determine Should 

Be Reduced? 

In today’s rule, EPA requires annual 

SO2 and NOX emissions reductions and 

ozone-season NOX emissions reductions 

to eliminate the amount of emissions 

that contribute significantly to 

nonattainment of the NAAQS for PM2.5

and ozone. The NOX reductions are 

phased in beginning in 2009, the SO2

reductions beginning in 2010, and both 

caps are lowered in 2015. In this section 

of the preamble, EPA explains its 

analysis of the cost portion of the 

contribute-significantly test, which 

determines the amount of required 

emissions reductions. The cost portion 

requires analysis of whether the control 

program under review is highly cost 

effective, and other factors that are 

discussed below in section IV.A. 

In section IV.A of today’s preamble, 

EPA explains its methodology for 

determining the amounts of SO2 and 

NOX emissions that must be eliminated 

for compliance with the CAIR. Section 

IV.A is divided into IV.A.1, IV.A.2, 

IV.A.3, and IV.A.4. In IV.A.1, EPA 

explains the methodology that the 

Agency used to model control costs for 

evaluation of cost effectiveness. In 

IV.A.2, EPA describes the methodology 

that was proposed in the NPR for 

determining the amounts of emissions 

that must be eliminated, including an 

overview of the proposed methodology, 

a description of the NOX SIP Call 

regulatory history in relation to the 

proposed methodology, and a 

description of EPA’s proposed criteria 

for determining emission reduction 

requirements. Section IV.A.3 

summarizes some comments received 

regarding the proposed methodology. 

Section IV.A.4 describes EPA’s 

evaluation of highly cost-effective SO2

and NOX emissions reductions based on 

controlling EGUs.

Section IV.A.4 is further divided into 

IV.A.4.a and IV.A.4.b, which address 

25196 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

51An exception was made to the run year 

mapping for an IPM sensitivity run that examined 

the impact of a NOX Compliance Supplement Pool 

(CSP). In that run the years 2009 through 2012 were 

mapped to 2010 and 2008 was mapped to 2008.

52The EPA began our emissions and economic 

analyses for the CAIR before the air quality analysis, 

which affects the States covered by the final rule, 

was completed

SO2 and NOX emission reduction 

requirements, respectively. Section 

IV.A.4.a describes EPA’s evaluation of 

highly cost-effective SO2 reduction 

requirements, beginning with a 

summary of the proposal and then 

describing today’s final determination. 

In IV.A.4.b., EPA describes its 

evaluation of highly cost-effective NOX

reduction requirements, also beginning 

with a summary of the proposal and 

then describing today’s final 

determination. Section IV.A.4.b first 

addresses annual NOX reductions, and 

then addresses ozone season NOX

reductions. The final regionwide CAIR 

SO2 and NOX control levels are 

provided within section IV.A, while a 

more detailed description of today’s 

final emission reduction requirements is 

presented in section IV.D. 

In section IV.B of today’s preamble, 

EPA discusses other (non-EGU) sources 

that the Agency considered in 

developing today’s rule. 

Section IV.C of today’s preamble 

explains the schedule for implementing 

today’s SO2 and NOX emissions 

reductions requirements. This section 

begins with an overview of the schedule 

(see section IV.C.1), then provides a 

detailed discussion of the engineering 

factors that affect timing for control 

retrofits (section IV.C.2). Within IV.C.2, 

EPA first describes the NPR discussion 

of engineering factors including the 

availability of boilermaker labor as a 

limitation (IV.C.2.a), then presents some 

comments received (IV.C.2.b) and EPA’s 

responses (IV.C.2.c). In section IV.C.3, 

EPA discusses the financial stability of 

the power sector in relation to the 

schedule for the CAIR. 

Section IV.D of today’s preamble 

provides a detailed description of the 

final CAIR emission reduction 

requirements. Regionwide SO2 and NOX

control levels, projected base case 

emissions and emissions after the CAIR, 

and projected emissions reductions are 

presented. Section IV.D begins with a 

description of the criteria used to 

determine final control requirements 

and provides the details of the final 

requirements. 

A. What Methodology Did EPA Use To 

Determine the Amounts of SO2 and NOX

Emissions That Must Be Eliminated? 

1. The EPA’s Cost Modeling 

Methodology 

The EPA conducted analysis using the 

Integrated Planning Model (IPM) that 

indicates that its CAIR SO2 and NOX

reduction requirements are highly cost 

effective. Cost effectiveness is one 

portion of the contribute-significantly 

test. The EPA uses the IPM to examine 

costs and, more broadly, analyze the 

projected impact of environmental 

policies on the electric power sector in 

the 48 contiguous States and the District 

of Columbia. The IPM is a multiregional, dynamic, deterministic linear 

programming model of the U.S. electric 

power sector. The EPA used the IPM to 

evaluate the cost and emissions impacts 

of the policies required by today’s 

action to limit annual emissions of SO2

and NOX and ozone season emissions of 

NOX from the electric power sector (on 

the assumption that all affected States 

choose to implement reductions by 

controlling EGUs using the model cap 

and trade rule). 

The EPA conducted analyses for the 

final CAIR using the 2004 update of the 

IPM, version 2.1.9. Documentation 

describing the 2004 update is in the 

CAIR docket and on EPA’s Web site. 

Some highlights of the 2004 update 

include: Updated inventory of electric 

generating units (EGUs) and installed 

pollution control equipment; updated 

State emission regulations; updated coal 

choices available to generating units; 

updated natural gas supply curves; 

updated SCR and SNCR cost 

assumptions; updated assumptions on 

performance of NOX combustion 

controls; updated title IV SO2 bank 

assumptions; updated heat rates and 

SO2 and NOX emission rates; and, 

updated repowering costs. 

The National Electric Energy Data 

System (NEEDS) contains the generation 

unit records used to construct model 

plants that represent existing and 

planned/committed units in EPA 

modeling applications of the IPM. The 

NEEDS includes basic geographic, 

operating, air emissions, and other data 

on all the generation units that are 

represented by model plants in EPA’s 

v.2.1.9 update of the IPM. 

The IPM uses model run years to 

represent the full planning horizon 

being modeled. That is, several years in 

the planning horizon are mapped into a 

representative model run year, enabling 

the IPM to perform multiple-year 

analyses while keeping the model size 

manageable. Although the IPM reports 

results only for model run years, it takes 

into account the costs in all years in the 

planning horizon. In EPA’s v.2.1.9 

update of the IPM, the years 2008 

through 2012 are mapped to run year 

2010, and the years 2013 through 2017 

are mapped to run year 2015.51 Model 

outputs for 2009 and 2010 are from the 

2010 run year. Model outputs for 2015 

are from the 2015 run year.

The EPA used the IPM to conduct the 

cost-effectiveness analysis for the 

emissions control program required by 

today’s action. The model was used to 

project the incremental electric 

generation production costs that result 

from the CAIR program. These estimates 

are used as the basis for EPA’s estimate 

of average cost and marginal cost of 

emissions reductions on a per ton basis. 

The model was also used to project the 

marginal cost of several State programs 

that EPA considers as part of its base 

case. 

In modeling the CAIR with the IPM, 

EPA assumes interstate emissions 

trading. While EPA is not requiring 

States to participate in an interstate 

trading program for EGUs, we believe it 

is reasonable to evaluate control costs 

assuming States choose to participate in 

such a program since that will result in 

less expensive reductions. The EPA’s 

IPM analyses for the CAIR includes all 

fossil fuel-fired EGUs with generating 

capacity greater than 25 MW. 

The EPA’s IPM modeling accounts for 

the use of the existing title IV bank of 

SO2 allowances. The projected EGU SO2

emissions in 2010 and 2015 are above 

the cap levels, because of the use of the 

title IV bank. The annual SO2 emissions 

reductions that are achieved in 2010 

and 2015 are based on the caps that EPA 

determined to be highly cost effective, 

including the existence of the title IV 

bank. 

The final CAIR requires annual SO2

and NOX reductions in 23 States and the 

District of Columbia, and also requires 

ozone season NOX reductions in 25 

States and the District of Columbia. 

Many of the CAIR States are affected by 

both the annual SO2 and NOX reduction 

requirements and the ozone season NOX

requirements. 

The EPA initially conducted IPM 

modeling for today’s final action using 

a control strategy that is similar but not 

identical to the final CAIR 

requirements.52 Many of the analyses for 

the final CAIR are based on that initial 

modeling, as explained further below. 

The control strategy that EPA initially 

modeled included three additional 

States (Arkansas, Delaware and New 

Jersey) within the region required to 

make annual SO2 and NOX reductions. 

However, these three States are not 

required to make annual reductions 

under the final CAIR. (In the ‘‘Proposed 

Rules’’ section of today’s Federal 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25197

Register, EPA is publishing a proposal 

to include Delaware and New Jersey in 

the CAIR region for annual SO2 and 

NOX reductions.) The addition of these 

three States made a total of 26 States 

and the District of Columbia covered by 

annual SO2 and NOX caps for the initial 

model run. The initial model run also 

included individual State ozone season 

NOX caps for Connecticut and 

Massachusetts, and did not include 

ozone season NOX caps for any other 

States.

The Agency conducted revised final 

IPM modeling that reflects the final 

CAIR control strategy. The final IPM 

modeling includes regionwide annual 

SO2 and NOX caps on the 23 States and 

the District of Columbia that are 

required to make annual reductions, and 

includes a regionwide ozone season 

NOX cap on the 25 States and the 

District of Columbia that are required to 

make ozone season reductions. The EPA 

modeled the final CAIR NOX strategy as 

an annual NOX cap with a nested, 

separate ozone season NOX cap. 

In this section of today’s preamble, 

the projected CAIR costs and emissions 

are generally derived from the final IPM 

run reflecting the final CAIR. However, 

some of EPA’s analyses are based on the 

initial IPM run, described above, which 

reflected a similar but not identical 

control strategy to the final CAIR. 

Analyses that are presented in this 

section of the preamble that are based 

on the initial IPM run include: IPM 

sensitivity runs that examine the effects 

of using the Energy Information 

Administration (EIA) natural gas price 

and electricity growth assumptions; 

marginal cost effectiveness curves 

developed using the Technology 

Retrofitting Updating Model; estimates 

of average annual SO2 and NOX control 

costs and average non-ozone season 

NOX control costs, and projected control 

retrofits used in the feasibility analysis. 

The air quality analysis in section VI of 

today’s preamble and the benefits 

analysis in section X, as well as the 

analyses presented in the Regulatory 

Impact Analysis (RIA), are based on 

emissions projections from the initial 

IPM run. 

The EPA believes that the differences 

between the initial IPM run that the 

Agency used for many of the analyses 

for the CAIR, and the final IPM run 

reflecting the final CAIR requirements, 

have very little impact on projected 

control costs and emissions. For the two 

IPM runs, projected marginal costs of 

CAIR annual NOX reductions in 2009 

and 2015 are identical. In addition, for 

the two IPM runs, projected marginal 

costs of CAIR annual SO2 reductions in 

2010 and 2015 are almost identical. 

Also, the 2009 and 2015 projected 

annual NOX emissions in the region 

encompassing the States that are 

affected by the final CAIR annual NOX

requirements are virtually identical 

when compared between the two model 

runs (difference between projected NOX

emissions is less than 1 percent for 2009 

and less than 2 percent for 2015). In 

addition, the 2010 and 2015 projected 

annual SO2 emissions in the region 

encompassing the States that are 

affected by the final CAIR annual SO2

requirements are virtually the same 

when compared between the two runs 

(difference between projected SO2

emissions is less than 1 percent for 2010 

and less than 2 percent for 2015). These 

comparisons confirm EPA’s belief that 

the initial IPM run very closely 

represents the final CAIR program.

The IPM output files for the model 

runs used in CAIR analyses are available 

in the CAIR docket. A Technical 

Support Document in the CAIR docket 

entitled ‘‘Modeling of Control Costs, 

Emissions, and Control Retrofits for Cost 

Effectiveness and Feasibility Analyses’’

further explains the IPM runs used in 

the analyses for section IV of the 

preamble. 

2. The EPA’s Proposed Methodology To 

Determine Amounts of Emissions That 

Must be Eliminated 

a. Overview of EPA Proposal for the 

Levels of Reductions and Resulting 

Caps, and Their Timing 

In the NPR, the amounts of SO2 and 

NOX emissions reductions that EPA 

proposed could be cost effectively 

eliminated in the CAIR region in 2010 

and 2015, and the amount of the 

proposed EGU emissions caps for SO2

and NOX that would exist if all affected 

States achieved those reductions by 

capping EGU emissions, appear in 

Tables IV–1 and IV–2, respectively.

TABLE IV–1.—PROJECTED SO2 AND

NOX EMISSION REDUCTIONS IN THE

CAIR REGION IN 2010 AND 2015 

FOR THE PROPOSED RULE

[Million Tons] 1

Pollutant 2010 2015 

SO2 ................... 3.6 3.7 

NOX .................. 1.5 1.8 

1 CAIR Notice of Proposed Rulemaking (69 

FR 4618, January 30, 2004). The proposed 

annual SO2 and NOX caps covered a 27-State 

(AL, AR, DE, FL, GA, IL, IN, IA, KS, KY, LA, 

MD, MA, MI, MN, MO, NJ, NY, NC, OH, PA, 

SC, TN, TX, VA, WV, WI) plus DC region. In 

addition, we proposed an ozone-season only 

cap for Connecticut. 

TABLE IV–2.—PROPOSED ANNUAL

ELECTRIC GENERATING UNIT SO2

AND NOX EMISSIONS CAPS IN THE

CAIR REGION

[Million Tons] 1

Pollutant 2010–2014 2015 and 

later 

SO2 ................... 3.9 2.7 

NOX .................. 1.6 1.3 

1 CAIR Notice of Proposed Rulemaking (69 

FR 4618, January 30, 2004). The proposed 

annual SO2 and NOX caps covered a 27-State 

(AL, AR, DE, FL, GA, IL, IN, IA, KS, KY, LA, 

MD, MA, MI, MN, MO, NJ, NY, NC, OH, PA, 

SC, TN, TX, VA, WV, WI) plus DC region. In 

addition, we proposed an ozone-season only 

cap for Connecticut. 

In the NPR, EPA evaluated the 

amounts of SO2 and NOX emissions in 

upwind States that contribute 

significantly to downwind PM2.5

nonattainment and the amounts of NOX

emissions in upwind States that 

contribute significantly to downwind 

ozone nonattainment. That is, EPA 

determined the amounts of emissions 

reductions that must be eliminated to 

help downwind States achieve 

attainment, by applying highly costeffective control measures to EGUs and 

determining the emissions reductions 

that would result. 

From past experience in examining 

multi-pollutant emissions trading 

programs for SO2 and NOX, EPA 

recognized that the air pollution control 

retrofits that result from a program to 

achieve highly cost-effective reductions 

are quite significant and can not be 

immediately installed. Such retrofits 

require a large pool of specialized labor 

resources, in particular, boilermakers, 

the availability of which will be a major 

limiting factor in the amount and timing 

of reductions. 

Also, EPA recognized that the 

regulated industry will need to secure 

large amounts of capital to meet the 

control requirements while managing an 

already large debt load, and is facing 

other large capital requirements to 

improve the transmission system. 

Furthermore, allowing pollution control 

retrofits to be installed over time 

enables the industry to take advantage 

of planned outages at power plants 

(unplanned outages can lead to lost 

revenue) and to enable project 

management to learn from early 

installations how to deal with some of 

the engineering challenges that will 

exist, especially for the smaller units 

that often present space limitations. 

Based on these and other 

considerations, EPA determined in the 

NPR that the earliest reasonable 

deadline for compliance with the final 

25198 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

highly cost-effective control levels for 

reducing emissions was 2015 (taking 

into consideration the existing bank of 

title IV SO2 allowances). First, the 

Agency confirmed that the levels of SO2

and NOX emissions it believed were 

reasonable to set as annual emissions 

caps for 2015 lead to highly costeffective controls for the CAIR region.

Once EPA determined the 2015 

emissions reductions levels, the Agency 

determined a proposed first (interim) 

phase control level that would 

commence January 1, 2010, the earliest 

the Agency believed initial pollution 

controls could be fully operational (in 

today’s final action, the first NOX

control phase commences in 2009 

instead of in 2010, as explained in detail 

in section IV.C). The first phase would 

be the initial step on the slope of 

emissions reductions (the glide-path) 

leading to the final (second) control 

phase to commence in 2015. The EPA 

determined the first phase based on the 

feasibility of installing the necessary 

emission control retrofits, as described 

in section IV.C. 

Although EPA’s primary costeffectiveness determination is for the 

2015 emissions reductions levels, the 

Agency also evaluated the cost 

effectiveness of the first phase control 

levels to ensure that they were also 

highly cost effective. Throughout this 

preamble section, EPA reports both the 

2015 and 2010 (and 2009 for NOX) costeffectiveness results, although the first 

phase levels were determined based on 

feasibility rather than cost effectiveness. 

The 2015 emissions reductions include 

the 2010 (and 2009 for NOX) emissions 

reductions as a subset of the more 

stringent requirements that EPA is 

imposing in the second phase. 

b. Regulatory History: NOX SIP Call 

In the NPR, EPA generally followed 

the statutory interpretation and 

approach under CAA section 

110(a)(2)(D) developed in the NOX SIP 

Call rulemaking. Under this 

interpretation, the emissions in each 

upwind State that contribute 

significantly to nonattainment are 

identified as being those emissions that 

can be eliminated through highly costeffective controls. 

In the NOX SIP Call, EPA relied 

primarily on the application of highly 

cost-effective controls in determining 

the amount of emissions that the 

affected States were required to 

eliminate. Specifically, EPA developed 

a reference list of the average cost 

effectiveness of recently promulgated or 

proposed controls, and compared the 

cost effectiveness of those controls to 

the cost effectiveness of the NOX SIP 

Call controls under consideration. In 

addition, EPA considered several other 

factors, including the fact that 

downwind nonattainment areas had 

already implemented ozone controls but 

upwind areas generally had not, the fact 

that some otherwise required local 

controls would be less cost-effective 

than the regional controls, and the 

overall ambient effects of the reductions 

required in the NOX SIP Call (63 FR 

57399–57403; October 27, 1998). 

i. Highly Cost-Effective Controls 

In the NOX SIP Call, EPA presented 

control costs in 1990 dollars (1990$). 

For the electric power industry, these 

expenditures were the increase in 

annual electric generation production 

costs in the control region that result 

from the rule. In the CAIR NPR, SNPR, 

and today’s final action, EPA presents 

the same type of electric generation as 

well as other costs in 1999$, and rounds 

all values related to the cost per ton of 

air emissions controls to the nearest 100 

dollars. 

In the NOX SIP Call, EPA’s decision 

on the amount of required NOX

emissions reductions was that this 

amount must be computed on the 

assumption of implementing highly 

cost-effective controls. The 

determination of what constituted 

highly cost effective controls was 

described as a two-part process: (1) The 

setting of a dollar-limit upper bound of 

highly cost-effective emissions 

reductions; and (2) a determination of 

what level of control below this upperbound was appropriate based upon 

achievability and other factors.

With respect to setting the upper 

bound of potential highly cost-effective 

controls, EPA determined this level on 

the basis of average cost effectiveness 

(the average cost per ton of pollutant 

removed). The EPA explained that it 

relied on average cost effectiveness for 

two reasons:

Since EPA’s determination for the core 

group of sources is based on the adoption of 

a broad-based trading program, average cost 

effectiveness serves as an adequate measure 

across sources because sources with high 

marginal costs will be able to take advantage 

of this program to lower their costs. In 

addition, average cost-effectiveness estimates 

are readily available for other recently 

adopted NOX control measures (63 FR 

57399).

At that time, EPA acknowledged that 

average cost effectiveness did not 

directly address the fact that certain 

units might have higher costs relative to 

the average cost of reduction (e.g., units 

with lower capacity factors tend to have 

higher costs):

[I]ncremental cost effectiveness helps to 

identify whether a more stringent control 

option imposes much higher costs relative to 

the average cost per ton for further control. 

The use of an average cost effectiveness 

measure may not fully reveal costly 

incremental requirements where control 

options achieve large reductions in emissions 

(relative to the baseline) (63 FR 57399).

Examination of marginal cost 

effectiveness—which examines what the 

cost would be of the next ton of 

reduction after the defined control 

level—would fill this gap. However, for 

the NOX SIP Call rulemaking, adequate 

information concerning marginal cost 

effectiveness was not available. 

For the NOX SIP Call, to determine 

the average cost effectiveness that 

should be considered to be highly cost 

effective, EPA developed a ‘‘reference 

list’’ of NOX emissions controls that are 

available and of comparable cost to 

other recently undertaken or planned 

NOX measures. The EPA explained that 

‘‘the cost effectiveness of measures that 

EPA or States have adopted, or 

proposed to adopt, forms a good 

reference point for determining which 

of the available additional NOX control 

measures can most easily be 

implemented by upwind States whose 

emissions impact downwind 

nonattainment problems.’’ (63 FR 

57400). The EPA explained that the 

measures on the reference list had 

already been implemented or were 

planned to be implemented, and 

therefore could be assumed to be less 

expensive than other measures to be 

implemented in the future. The EPA 

found that the costs of the measures on 

the reference list approached but were 

below $2,000 per ton (1990$). The EPA 

concluded that ‘‘controls with an 

average cost effectiveness [of] less than 

$2,000 [1990$, or $2,500 (1999$)] per 

ton of NOX removed [should be 

considered] to be highly cost-effective.’’

(63 FR 57400). Notably, the reference 

costs were taken from the supporting 

analyses used for the regulatory actions 

covering the NOX pollution controls—

they are what regulatory decision 

makers and the public believed were the 

control costs. 

Mindful of this $2,000 limit [1990$, or 

$2,500 (1999$)], EPA considered a 

control level that would have resulted 

in estimated average costs of 

approximately $1,800 (1990$) per ton. 

However, EPA concluded that because 

the corresponding level of controls—

nominally a 0.12 lb/mmBtu control 

level—was not well enough established, 

EPA was ‘‘not as confident about the 

robustness’’ of the cost estimates. 

Moreover, EPA expressed concern that 

its ‘‘level of comfort’’ was not as high as 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25199

53U.S. Environmental Protection Agency, Office 

of Air and Radiation, EPA’s Clean Air Power 

Initiative, October 1996.

54U.S. Environmental Protection Agency, Office 

of Air and Radiation, Analysis of Emission 

Reduction Options for the Electric Power Industry, 

March 1999.

55EPA’s Clear Skies Act analysis is on the web 

at: http://www.epa.gov/air/clearskies/

technical.html.

it would have liked that the nominal 

0.12 lb/mmBtu control level ‘‘will not 

lead to installation of SCR technology at 

a level and in a manner that will be 

difficult to implement or result in 

reliability problems for electric power 

generation’’ (63 FR 57401).

Accordingly, EPA selected the next 

control level that it had evaluated—a 

nominal 0.15 lb/mmBtu level—which 

would result in an average cost of 

approximately $1,500 [1990$, or $1,900 

(1999$)] per ton. The EPA determined 

that this control level did not present 

the uncertainty concerns associated 

with the 0.12 level. The EPA added, in 

this 1998 rule: ‘‘With a strong need to 

implement a program by 2003 that is 

recognized by the States as practical, 

necessary, and broadly accepted as 

highly cost-effective, the Agency has 

decided to base the emissions budgets 

for EGUs on a 0.15 * * * level.’’ (63 FR 

57401—57402). The EPA summarized 

its approach as determining ‘‘the 

required emission levels * * * based on 

the application of NOX controls that 

achieve the greatest feasible emissions 

reduction while still falling within a 

cost-per-ton reduced range that EPA 

considers to be highly costeffective.* * *’’ (63 FR 57399). 

The bulk of the cost for reducing NOX

emissions for EGUs is in the capital 

investment in the control equipment, 

which would be the same whether 

controls are installed for ozone season 

only, or for annual controls. The 

increased costs to run the equipment 

annually instead of only in the ozone 

season is relatively small. Although the 

NOX SIP Call is an ozone season NOX

reduction program, most of the NOX

control costs on the reference list are for 

annual reductions. If the NOX SIP Call 

were an annual program instead of 

seasonal, its average control costs would 

be lower, relative to the annual control 

costs in the reference list. 

ii. Other Factors 

In the NOX SIP Call, although 

considering air quality and cost to be 

the primary factors for determining 

significant contribution, EPA identified 

several other factors that it generally 

considered. As one factor, EPA 

reviewed ‘‘overall considerations of 

fairness related to the control regimes 

required of the downwind and upwind 

areas,’’ particularly, the fact that the 

major urban nonattainment areas in the 

East had implemented controls on 

virtually all portions of their inventory 

of ozone precursors, but upwind sources 

had not implemented reductions 

intended to reduce their impacts 

downwind (63 FR 57404). 

As another factor, EPA generally 

considered ‘‘the cost effectiveness of 

additional local reductions in the * * * 

ozone nonattainment areas.’’ The EPA 

included in the record information that 

nationally, on average, additional local 

measures would cost more than the cost 

of the upwind controls required under 

the NOX SIP Call. This consideration 

further indicated that the regional 

controls under the NOX SIP Call were 

highly cost effective (63 FR 57404).

In addition, EPA conducted air 

quality modeling to determine the 

impact of the controls, and found that 

they benefitted the downwind areas 

without being more than necessary for 

those areas to attain (63 FR 57403—

57404). 

c. Proposed Criteria for Emissions 

Reduction Requirements 

i. General Criteria 

In the CAIR NPR, EPA proposed 

criteria for determining the appropriate 

levels of annual emissions reductions 

for SO2 and NOX and ozone-season 

emissions reductions for NOX. The EPA 

stated that it considers a variety of 

factors in evaluating the source 

categories from which highly costeffective reductions may be available 

and the level of reduction assumed from 

that sector. These include: 

• The availability of information, 

• The identification of source 

categories emitting relatively large 

amounts of the relevant emissions, 

• The performance and applicability 

of control measures, 

• The cost effectiveness of control 

measures, and 

• Engineering and financial factors 

that affect the availability of control 

measures (69 FR 4611). 

Further, EPA stated that overall, ‘‘We 

are striving * * * to set up a reasonable 

balance of regional and local controls to 

provide a cost-effective and equitable 

governmental approach to attainment 

with the NAAQS for fine particles and 

ozone.’’ (69 FR 4612) 

The EPA has used these types of 

criteria in a number of efforts to develop 

regional and national strategies to 

reduce interstate transport of SO2 and 

NOX. Starting in 1996, EPA performed 

analysis and engaged in dialogue with 

power companies, States, environmental 

groups and other interested groups in 

the Clean Air Power Initiative (CAPI).53

In that study of national emission 

reduction strategies, EPA initially 

considered an emissions cap based on a 

50 percent reduction in SO2 emissions 

from title IV levels (i.e., 4.5 million tons 

nationwide) in 2010. For NOX, EPA 

initially looked at ozone season and 

non-ozone season caps. Commencing in 

2000, the ozone season emissions cap 

would be based on an emission rate of 

0.20 lb/mmBtu, and in 2005, the ozone 

season cap would be reduced to a level 

based on 0.15 lb/mmBtu (these cap 

levels would be similar to the phased 

caps adopted by the Ozone Transport 

Commission (OTC) States). The nonozone season cap would be based on the 

proposed title IV phase II NOX rule. The 

EPA also considered other options in 

the CAPI study, including setting NOX

caps based on emission rates of 0.20 lb/

mmBtu and 0.25 lb/mmBtu; setting NOX

caps based on rates of 0.15 lb/mmBtu 

and 0.20 lb/mmBtu but lowering the 

SO2 allowance cap by 60 percent 

instead of 50 percent; and, keeping a 

NOX cap based on a rate of 0.15 lb/

mmBtu but lowering the SO2 allowance 

cap by 50 percent in 2005 instead of in 

2010.

The EPA did a follow-up study in 

1999 and discussed those results with 

various stakeholder groups, as well.54

That study considered a variety of SO2

emission caps ranging from a 40 percent 

reduction from title IV cap levels in 

2010 to a 55 percent reduction from title 

IV cap levels in 2010. The 1999 study 

did not consider additional reductions 

in NOX emissions beyond those 

required under the NOX SIP Call.

In the last several years, EPA has 

performed significant additional 

analysis in support of the proposed 

Clear Skies Act.55 That legislation, 

proposed in 2002 and 2003, would 

include nationwide SO2 caps of 4.5 

million tons in 2010 and 3.0 million 

tons in 2018 (i.e., 50 percent and 67 

percent reductions from title IV cap 

levels). The Clear Skies Act also 

includes a two-phase, two-zone NOX

emission cap program, with the first 

phase in 2008 and the second phase in 

2018. In the 2003 legislation, the first 

phase NOX caps would result in 

effective NOX emissions rates of 0.16 lb/

mmBtu in the east and 0.20 lb/mmBtu 

in the west, and the second phase 

would result in effective emission rates 

of 0.12 lb/mmBtu in the east and 0.20 

lb/mmBtu in the west.

25200 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

ii. Reliance on Average and Marginal 

Cost Effectiveness 

In the CAIR NPR, EPA supported the 

conclusion that its emissions caps are 

highly cost effective based upon ‘‘(1) 

comparison to the average cost 

effectiveness of other regulatory actions 

and (2) comparison to the marginal cost 

effectiveness of other regulatory 

actions.’’ (69 FR 4585). We 

supplemented these comparisons of 

cost-effectiveness tables with an 

auxiliary evaluation of the marginal 

costs curves, which allowed us to show 

that the selected control levels would be 

‘‘below the point at which there would 

be significant diminishing returns on 

the dollars spent for pollution control.’’

(69 FR 4614). 

Although in the NOX SIP Call, EPA 

based the required controls on average 

cost alone, in today’s rule, EPA uses 

both average and marginal costs, 

including an evaluation of the marginal 

cost curves. At the time of the NOX SIP 

Call, marginal cost information was not 

as readily available. Today, such 

information is available for both SO2

and NOX controls, although marginal 

cost information remains more limited 

and EPA has had to specifically develop 

marginal cost estimates for use in this 

rulemaking.

Marginal costs are a useful measure of 

cost effectiveness because they indicate 

how much any additional level of 

control at the margin will cost relative 

to other actions that are available. Using 

both average and marginal control costs, 

provides a more complete picture of the 

costs of controls than using average 

costs alone. Average costs provide a 

means for a straightforward comparison 

between the CAIR and other emissions 

reductions programs for which average 

costs are generally the only type of costs 

available. Where marginal cost 

information is available, it enables EPA 

to compare the costs of the CAIR at the 

stringency level being considered to the 

costs of the last increment of control in 

other programs. Moreover, evaluation of 

marginal cost curves allows us to 

corroborate that the selected level of 

stringency of the selected program stops 

short of the point where the returns 

begin to diminish significantly. 

Projected marginal cost information 

for controlling emissions from EGUs is 

now available for some State programs, 

because EPA includes the programs in 

its base case power sector modeling 

using the IPM to develop the 

incremental costs of electricity 

production for the CAIR. Marginal EGU 

control costs from State programs 

modeled using the IPM were compared 

to projected marginal EGU control costs 

under the CAIR, as discussed in more 

detail below. 

3. What Are the Most Significant 

Comments That EPA Received About Its 

Proposed Methodology for Determining 

the Amounts of SO2 and NOX Emissions 

That Must Be Eliminated, and What Are 

EPA’s Responses? 

Some commenters took issue with 

EPA’s reliance on cost-per-ton-ofemissions-reductions as the metric for 

determining cost effectiveness. These 

commenters observed that this metric 

does not take into account that any 

given ton of pollutant reduction may 

have different impacts on ambient 

concentration and human exposure. 

Some of these commenters advocated 

use of a metric based on cost per unit 

of pollutant concentration reduced. 

Another stated that EPA should account 

for cost effectiveness based on 

geographical location relative to the area 

of nonattainment. 

Still other commenters took a 

contrasting view. They argued that a 

metric based on cost-per-ambientimpact might be useful in justifying 

control cost effectiveness for source 

categories within an individual 

nonattainment area as part of an 

attainment SIP, but not for evaluating 

costs of controlling long-range transport. 

These commenters stated that it is 

impractical to calculate cost 

effectiveness of control on the basis of 

cost per unit reduction in ambient 

concentration. One queried: ‘‘Where 

would the ambient reduction be 

measured? 100 miles downwind? 1,500 

miles downwind?’’

The EPA agrees that optimally, the 

cost-per-ambient-impact of controls 

could play a major role in determining 

upwind control obligations (although 

equitable considerations and other 

factors identified in the NOX SIP Call 

rulemaking and today’s action may also 

play a role). The EPA recognized the 

potential importance of this factor 

during the NOX SIP Call rulemaking and 

endeavored to develop technical 

information to support it. However, in 

that rulemaking, EPA was not able to 

develop an approach to quantify, with 

sufficient accuracy, cost-per-ambient 

impact because the NOX SIP Call region 

was large—covering approximately half 

of the continental U.S. and including 

approximately half the States—and 

many upwind States with different 

emissions inventories had widely varied 

impacts on many different 

nonattainment areas downwind. 

This problem—the complexity of the 

task and the dearth of analytic tools—

remains today for both PM2.5 and 8-hour 

ozone regional transport. Not 

surprisingly, no commenter presented to 

EPA the analytic tools, which we would 

expect would consist of a complex, 

computerized program that could 

integrate, on a State-by-State basis, both 

control costs and ambient impacts by 

each State on each of its downwind 

receptors under the CAIR control 

scenario. 

In the absence of a scientifically 

defensible, practicable method for 

implementing a program design 

approach based on the cost-per-ambientimpact of emissions reductions, EPA is 

not able to employ such an approach. 

However, EPA believes it appropriate to 

continue to examine ways to develop 

such an approach for future use. 

A few commenters suggested that EPA 

should use a cost-benefit analysis for 

determining reduction levels. One noted 

that cost-benefit analysis can help find 

the reduction levels that maximize 

societal net benefit (benefits minus 

costs), and suggested the Agency should 

compare the marginal cost of each ton 

of pollutant reduced to the marginal 

benefit achieved, as well as compare the 

total costs to the total benefits. Another 

stated that an optimal allocation of 

resources is where the marginal cost 

equals the marginal benefit, and 

observed that comparing the average 

cost to the average benefit of the 

controls proposed in the CAIR NPR 

yields an average benefit significantly 

higher than the average cost. This 

commenter concluded that EPA should 

require controls beyond the controls 

described in the NPR as highly cost 

effective.

Although EPA strongly agrees that 

examination of costs and benefits is very 

useful, in today’s rulemaking, EPA does 

not interpret CAA section 110(a)(2)(D) 

to base the amount of emissions 

reductions on benefits other than 

progress towards attainment of the PM2.5

or the 8-hour ozone NAAQS. The EPA’s 

interpretation does, however, use cost 

effectiveness per ton of pollutant 

reduced, and we are using that analytic 

tool for setting SO2 and NOX emission 

reduction requirements. Additionally, 

EPA has prepared a cost-benefit analysis 

to inform the Agency and public of the 

many other important impacts of this 

rulemaking. 

A few commenters suggested that the 

Agency should set its NOX and SO2

reduction requirements based on Best 

Available Control Technology (BACT) 

emission rates for EGUs. Although not 

clearly stated, the commenters appear to 

suggest BACT level controls for both 

existing and new units. 

The emission reduction requirements 

that EPA determined are based on the 

application of highly cost-effective 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25201

56The updated reference list includes estimated 

average costs for SO2 reductions from EGUs under 

best available retrofit technology (BART) requirements. The BART rule was proposed and has 

not been finalized (69 FR 25184; May 5, 2004).

controls that are a step that the Agency 

is taking at this time to eliminate 

emissions that contribute significantly 

to nonattainment of the ozone and fine 

particle NAAQS. As explained 

elsewhere, this step is reasonable in 

light of the current status of 

implementation for those NAAQS. 

Basing emission reduction 

requirements on a presumption of BACT 

emission rates across the board would 

require scrubbers and SCRs on all coalfired units and SCRs on all gas-fired and 

oil-fired units. The cost of these controls 

would vary considerably from source to 

source, be expensive for many sources, 

and may cause substantial fuel 

switching to natural gas and closure of 

smaller coal-fired units. Having 

considered this suggestion for deeper 

regional reductions that would not be as 

cost effective as the highly cost-effective 

reductions in today’s rule, EPA believes 

that a more tailored approach, such as 

the CAIR level control as well as local 

controls under SIPs (where necessary), 

is a more reasonable approach to 

achieving the level of ambient 

improvement needed for attainment 

throughout the United States. 

4. The EPA’s Evaluation of Highly CostEffective SO2 and NOX Emissions 

Reductions Based on Controlling EGUs 

a. SO2 Emissions Reductions 

Requirements 

i. CAIR Proposal for SO2

The NPR focused primarily on 

determining highly cost-effective 

amounts of emissions reductions based 

on, as in the NOX SIP Call, comparison 

to reference lists of the cost 

effectiveness of other regulatory 

controls. In the NPR, EPA developed 

reference lists for both the average cost 

effectiveness and the marginal cost 

effectiveness of those other controls. 

These reference lists indicated that the 

average annual costs per ton of SO2

removed ranged from $500 to $2,100; 

and marginal costs of SO2 removal 

ranged from $800 to $2,200. 

Moreover, EPA further considered the 

cost effectiveness of alternative 

stringency levels for this regulatory 

proposal. That is, EPA examined 

changes in the marginal cost curve at 

varying levels of emissions reductions. 

The EPA determined in the NPR that the 

‘‘knee’’ in the marginal costeffectiveness curve—the point at which 

the marginal cost per ton of SO2

removed begins to increase at a 

noticeably higher rate—appears to start 

above $1,200 per ton (69 FR 4613—

4615). 

In the NPR, EPA then provided 

further analysis of a two-phase SO2

reduction program. The final (second) 

phase, in 2015, would reduce SO2

emissions in the CAIR region by the 

amount that results from making a 65 

percent reduction from the title IV 

Phase II allowance levels (taking into 

consideration the existing bank of title 

IV SO2 allowances). The first phase, in 

2010, would reduce SO2 emissions in 

the CAIR region by a lesser amount, i.e., 

a 50 percent reduction from title IV 

Phase II allowance levels (again, taking 

into consideration the banked title IV 

SO2 allowances). The EPA developed 

this target SO2 control level for further 

evaluation because, based on all of the 

earlier work performed on multipollutant power plant reduction 

programs and general consideration, 

with technical support, of overall 

emissions reductions, costs to industry 

and the general public, ambient 

improvement, and consistency with the 

emerging PM2.5 implementation 

program, we believed it would meet the 

criteria set forth above. 

Then, EPA conducted cost analyses of 

this control level using the IPM as well 

as additional analysis of the 

implications of this control level to 

determine if it did indeed meet those 

criteria. The IPM analysis considered 

the increase in annual electric 

generation production costs in the CAIR 

region that result from the rule. The 

EPA evaluated the cost effectiveness of 

the final phase (2015) cap to determine 

if it is highly cost effective; and, we also 

evaluated the cost effectiveness of the 

2010 cap. The EPA used the IPM to 

estimate cost effectiveness of the CAIR 

in the future. The IPM incorporates 

projections of future electricity demand, 

and thus heat input growth. The EPA’s 

IPM analyses for the CAIR includes all 

fossil fuel-fired EGUs with capacity 

greater than 25 MW. A description of 

the IPM is included elsewhere in this 

preamble, and a detailed model 

documentation is in the docket.

The SO2 annual control costs that 

were presented in the CAIR NPR were 

average costs of $700 per ton and $800 

per ton for years 2010 and 2015, 

respectively, and marginal costs of $700 

per ton and $1,000 per ton for years 

2010 and 2015. In addition, the NPR 

included the results of sensitivity 

analyses that examined costs of the 

proposed SO2 controls based on the 

Energy Information Administration’s 

projections for electricity growth and 

natural gas prices. These sensitivity 

analyses showed marginal SO2 control 

costs of $900 per ton and $1,100 per ton 

for years 2010 and 2015, respectively. 

The EPA proposed to consider the SO2

emissions reductions proposed in the 

NPR as highly cost effective because 

they were consistent with the lower end 

of the reference list range of cost per ton 

of SO2 reduction for controls on both an 

average and a marginal cost basis (69 FR 

4613—4615). 

ii. Analysis of SO2 Emission Reduction 

Requirements for Today’s Final Rule 

(I) Reference Lists of Cost-Effective SO2

Controls 

For today’s action, EPA updated the 

reference list of controls included in the 

NPR of the average and marginal costs 

per ton of recent SO2 control actions. 

The EPA systematically developed a list 

of cost information from both recent 

actions and proposed actions. The EPA 

compiled cost information for actions 

taken by the Agency, and examined the 

public comments submitted after the 

NPR was published, to identify all 

available control cost information to 

provide the updated reference list for 

today’s preamble. The updated 

reference list includes both average and 

marginal costs of control, to which EPA 

compares the CAIR control costs, and 

the list represents what regulatory 

decision makers and/or the public 

believes are the control costs.56

Table IV–3 provides average costs of 

SO2 controls. This table includes 

average costs for recent BACT 

permitting decisions for SO2. Under 

EPA’s New Source Review (NSR) 

program, if a company is planning to 

build a new plant or modify an existing 

plant such that a significant net increase 

in emissions will occur, the company 

must obtain a NSR permit that addresses 

controls for air emissions. BACT is the 

type of control required by the NSR 

program for existing sources in 

attainment areas. The BACT decisions 

are determined on a case-by-case basis, 

usually by State or local permitting 

agencies, and reflect consideration of 

average and incremental cost 

effectiveness. These decisions are 

relevant for EPA’s reference list of 

average costs of SO2 controls, because 

they represent cost-effective controls 

that have been demonstrated.

25202 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

57The EPA used the difference between EIA’s 

estimates for well-head natural gas prices and 

minemouth coal prices to determine the sensitivity 

of IPM’s results to higher natural gas prices. The 

EPA describes this sensitivity analysis as ‘‘EIA 

natural gas prices’’. For electric demand, we 

replaced EPA’s assumed annual growth of 1.6 

percent with EIA’s projection of annual growth of 

1.8 percent.

TABLE IV–3.—AVERAGE COSTS PER TON OF ANNUAL SO2 CONTROLS

SO2 control action Average cost per 

ton 

Best Available Control Technology (BACT) Determinations ......................................................................................................... 1 $400–$2,100 

Nonroad Diesel Engines and Fuel ................................................................................................................................................ 2 $800 

Proposed Best Available Retrofit Technology (BART) for Electric Power Sector ........................................................................ 3 $2,600–$3,400 

1These numbers reflect a range of cost-effectiveness data entered into EPA’s RACT/BACT/LAER Clearinghouse (RBLC) for add-on SO2 controls (www.epa.gov/ttn/catc/). We identified actions in the data base for large, utility-scale, coal-fired boiler units for which cost effectiveness data 

were reported. The range of costs shown here is for boilers ranging from 30 MW to an estimated 790 MW (we used a conversion factor of 10 

mmBtu/hr = 1 MW for units for which size was reported in mmBtu/hr). Emission limits for these actions ranged from 0.10 lb/mmBtu to 0.27 lb/

mmBtu. Add-on controls reported for these units are dry or wet scrubbers (in one case with added alkali and in one case with a baghouse). 

Where the dollar-year was not reported we assumed 1999 dollars. The cost range presented in the NPR was $500–$2,100–today’s range includes additional BACT costs that were entered into the clearinghouse after the NPR was published. 2 Control of Emissions of Air Pollution From Nonroad Diesel Engines and Fuel; Final Rule (69 FR 39131; June 29, 2004). The value in this 

table represents the long-term cost per ton of emissions reduced from the total fuel and engine program (cost per ton of emissions reduced in 

the year 2030). 1999$ per ton. 3The EPA IPM modeling 2004, available in the docket. The EPA modeled the Regional Haze Requirements as source specific limits (90 percent SO2 reduction or 0.1 lb/mmBtu rate; except the five state WRAP region for which we did not model SO2 controls beyond what is done for 

the WRAP cap in the base case modeling). Estimated average costs based on this modeling are $2,600 per ton in 2015 and $3,400 per ton in 

2020. 1999$ per ton. 

Table IV–4 provides the marginal cost 

per ton of recent State and regional 

decisions for annual SO2 controls.

TABLE IV–4.—MARGINAL COSTS PER TON OF ANNUAL SO2 CONTROLS

SO2 control action Marginal cost per 

ton 

New Hampshire Rule ..................................................................................................................................................................... 1 $600 

WRAP Regional SO2 Trading Program ......................................................................................................................................... 2 $1,100–$2,200 

1The EPA IPM base case modeling August 2004, available in the docket. (1999$ per ton). We modeled New Hampshire’s State Bill ENVA2900, which caps SO2 emissions at all existing fossil steam units. 2 ‘‘An Assessment of Critical Mass for the Regional SO2 Trading Program,’’ prepared for Western Regional Air Partnership Market Trading 

Forum by ICF Consulting Group, September 27, 2002, available in the docket. This analysis looked at the implications of one or more States 

choosing to opt-out of the WRAP regional SO2 trading program. (1999$ per ton) 

(II) Cost Effectiveness of the CAIR 

Annual SO2 Reductions 

In the NPR, EPA evaluated an annual 

SO2 control strategy based on a 

specified level of emissions reductions 

from EGUs. Available information 

indicated that emissions reductions 

from this industry would be the most 

cost effective. (As noted elsewhere, EPA 

considered control strategies for other 

source categories, but concluded that 

they would not qualify as highly costeffective controls.) Of course, under 

today’s rule, although EPA calculates 

the amount of emissions reductions 

States must achieve by evaluation of the 

EGU control strategy, States remain free 

to achieve those reductions by 

implementing controls on any sources 

they wish. 

For today’s action, EPA updated the 

predicted annual SO2 control costs 

included in the NPR. The EPA analyzed 

the costs of the CAIR using an updated 

version of the IPM (documentation for 

the IPM update is in the docket). 

Further, EPA modified the modeling to 

match the final CAIR strategy (see 

section IV.A.1 for a description of EPA’s 

CAIR IPM modeling).

The EPA also updated its analysis of 

the sensitivity of the marginal cost 

results to assumptions of higher electric 

growth and natural gas prices than we 

used in the base case. These sensitivity 

analyses were based on the Energy 

Information Administration’s Annual 

Energy Outlook for 2004.57

In determining whether our control 

strategy is highly cost effective, EPA 

believes it is important to account for 

the variable levels of cost effectiveness 

that these sensitivity analyses indicate 

may occur if electricity demand or 

natural gas prices are appreciably higher 

than assumed in the IPM. Those two 

factors are key determinants of control 

costs and, over the relatively long 

implementation period provided under 

today’s action, a meaningful degree of 

risk arises that these factors may well 

vary to the extent indicated by the 

sensitivity analyses. As a result, EPA 

wanted to examine the marginal costs 

that would occur under the scenarios 

modeled in the sensitivity analyses to 

see how they differed from the costs 

using EPA’s assumptions. 

Table IV–5 provides the average and 

marginal costs of annual SO2 reductions 

under the CAIR for 2010 and 2015. 

(When presenting estimated CAIR 

control costs in section IV of this 

preamble, EPA uses ‘‘Main Case’’ to 

indicate the primary CAIR IPM 

analyses, as differentiated from other 

IPM analyses such as sensitivity runs 

used to examine the impacts of varying 

assumptions about natural gas price and 

electric growth.)

TABLE IV–5.—ESTIMATED COSTS PER

TONS OF SO2 CONTROLLED UNDER

CAIR, CAP LEVELS BEGINNING IN

2010 AND 2015 1

Type of cost effectiveness 2010 2015 

Average Cost—Main Case $500 $700 

Marginal Cost—Main Case 700 1,000 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25203

58The updated reference list of average SO2

control costs includes estimated average EGU costs 

under BART. The BART rule has been proposed but 

not finalized (69 FR 25184; May 5, 2004).

59EPA did promulgate Phase I of the ozone 

implementation rule in April 2004 (69 FR 23951; 

April 30, 2004) but has not issued Phase II of the 

rule, which will interpret CAA requirements 

relating to local controls (e.g., RACT, RACM, RFP).

TABLE IV–5.—ESTIMATED COSTS PER

TONS OF SO2 CONTROLLED UNDER

CAIR, CAP LEVELS BEGINNING IN

2010 AND 2015 1—Continued

Type of cost effectiveness 2010 2015 

Sensitivity Analysis: Marginal Cost Using EIA 

Electric Growth and Natural Gas Prices ............. 800 1,200 

1The EPA IPM modeling 2004, available in 

the docket. $1999 per ton. 

These estimated SO2 control costs 

under the CAIR reflect annual EGU SO2

caps of 3.6 million tons in 2010 and 2.5 

million tons in 2015 within the CAIR 

region. Based on IPM modeling, EPA 

projects that SO2 emissions in the CAIR 

region will be about 5.1 million tons in 

2010 and 4.0 million tons in 2015. The 

projected emissions are above the cap 

levels because of the use of the existing 

title IV bank of SO2 allowances. Average 

costs shown for 2015 are an estimate of 

the average cost per ton to achieve the 

total difference in projected emissions 

between the base case conditions and 

the CAIR in the year 2015 (the 2015 

average costs are not based on the 

increment in reductions between 2010 

and 2015). (A more detailed description 

of the final CAIR SO2 and NOX control 

requirements is provided below in 

today’s preamble.) 

(III) SO2 Cost Comparison for CAIR 

Requirements 

The EPA believes that if an SO2

control strategy has a cost effectiveness 

that is at the low end of the updated 

reference tables, the approach should be 

considered to be highly cost effective. 

The costs in the reference range should 

be considered to be cost effective 

because they represent actions that have 

already been taken to reduce emissions. 

In deciding to require these actions, 

policymakers at the local, State and 

Federal levels have determined them to 

be cost-effective reductions to limit or 

reduce emissions. Thus, costs at the 

bottom of the range must necessarily be 

considered highly cost effective. 

Today’s action requires SO2 emissions 

reductions (or an EGU emissions cap) in 

2015. The EPA has determined that 

those emissions reductions are highly 

cost effective. In addition, today’s action 

requires that some of those SO2

emissions reductions (or a higher EGU 

emissions cap) be implemented by 2010. 

The EPA has examined the cost 

effectiveness of implementing those 

earlier emissions reductions (or cap) by 

2010, and determined that they are also 

highly cost effective. 

The cost of the SO2 reductions 

required under today’s action—if the 

States choose to implement those 

reductions through EGUs, for which the 

most cost-effective reductions are 

available—on average and at the margin, 

are at the lower end of the range of cost 

effectiveness of other, recent SO2

control requirements.58 This is true for 

our analysis of both the costs EPA 

generally expects as well as the 

somewhat higher costs that would result 

from higher than expected electricity 

demand and natural gas prices, as 

indicated in the sensitivity analyses that 

EPA has done.

Specifically, the average cost 

effectiveness of the SO2 requirements is 

$700 per ton removed in 2015. This 

amount falls toward the low end of the 

reference range of average costs per ton 

removed of $400 to $3,400. Similarly, 

the marginal cost effectiveness of the 

SO2 requirements ranges from $1,000 to 

$1,200 for 2015 (with the higher end of 

the range based on the sensitivity 

analyses). These amounts fall toward 

the lower end of the reference range of 

marginal cost per ton removed of $600 

to $2,200.

The EPA believes that selecting as 

highly cost-effective amounts toward 

the lower end of our average and 

marginal cost ranges for SO2 and NOX

control is appropriate because today’s 

rulemaking is an early step in the 

process of addressing PM2.5 and 8-hour 

ozone nonattainment and maintenance 

requirements. The CAA requires States 

to submit section 110(a)(2)(D) plans to 

address interstate transport, and overall 

attainment plans to ensure the NAAQS 

are met in local areas. By taking the 

early step of finalizing the CAIR, we are 

requiring a very substantial air emission 

reduction that addresses interstate 

transport of PM2.5 as well as a further 

reduction in interstate transport of 

ozone beyond that required by the NOX

SIP Call Rule. Much of the air quality 

improvement resulting from reduced 

transport is likely to occur through 

broad and deep emissions reductions 

from the electric power sector, which 

has been a major part of the transport 

problem. Other air quality benefits will 

occur as the result of Federal mobile 

source regulations for new sources, 

which cover passenger vehicles and 

light trucks, heavy-duty trucks and 

buses, and non-road diesel equipment. 

Against this backdrop of Federal 

actions that lower air emissions (as well 

as some substantial State control 

programs), States will develop plans 

designed to achieve the standards in 

their local nonattainment areas. The 

EPA has not yet promulgated rules 

interpreting the CAA’s requirements for 

SIPs for PM2.5 and ozone nonattainment 

areas,59 nor have States developed plans 

to demonstrate attainment. As a result, 

there are significant uncertainties 

regarding potential reductions and 

control costs associated with State 

plans. We believe that some areas are 

likely to attain the standards in the near 

term through early CAIR reductions and 

local controls that have costs per ton 

similar to the levels we have determined 

to be highly cost effective. We expect 

that other areas with higher PM2.5 or 

ozone levels will determine through the 

attainment planning process that they 

need greater emissions reductions, at 

higher costs per ton, to reach attainment 

within the CAA’s timeframes. For those 

areas, States will need to assess targeted 

measures for achieving local attainment 

in a cost-effective (but not necessarily 

highly cost-effective) manner, in 

combination with the CAIR’s significant 

reductions. Given the uncertainties that 

exist at this early stage of the 

implementation process, EPA believes 

this rule is a rational approach to 

determining the highly cost-effective 

reductions in PM2.5 and ozone 

precursors that should be required for 

interstate transport purposes.

As discussed above, the Agency 

believes this approach is consistent with 

our action in the NOX SIP Call. While 

the cost level selected for the NOX SIP 

Call was not at the low end of the 

reference range of costs, if the NOX SIP 

Call costs were for annual rather than 

seasonal controls they would have been 

lower relative to the annual control 

costs on the list. This would make the 

relationship between the cost of the 

NOX SIP Call and the reference costs 

used in that rulemaking, more similar to 

relative costs of CAIR compared to its 

reference lists. Also, significant local 

controls for meeting the 1-hour ozone 

standard had already been adopted in 

many areas. 

Although EPA’s primary costeffectiveness determination is for the 

2015 emissions reductions levels, the 

Agency also evaluated the cost 

effectiveness of the interim phase 

control levels to ensure that they were 

also highly cost effective. For the SO2

requirements for 2010, the average cost 

effectiveness is $500 per ton removed, 

and the marginal cost effectiveness 

25204 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

60EPA is using the knee in the curve analysis 

solely to show that the required emissions 

reductions are very cost effective. The marginal cost 

curve reflects only emissions reduction and cost 

information, and not other considerations. We note 

that it might be reasonable in a particular regulatory 

action to require emissions reductions past the knee 

of the curve to reduce overall costs of meeting the 

NAAQS or to achieve benefits that exceed costs. It 

should be noted that similar analysis for other 

source categories may yield different curves.

ranges from $700 to $800. The 2010 

costs indicate that the interim phase 

CAIR reductions are also highly costeffective.

(IV) Cost Effectiveness: Marginal Cost 

Curves for SO2 Control 

As noted above, the Agency also 

considered another factor to corroborate 

its conclusion concerning the cost 

effectiveness of the selected levels of 

control:

The cost effectiveness of alternative 

stringency levels for today’s action. 

Specifically, EPA examined changes in 

the marginal cost curve at varying levels 

of emissions reductions for EGUs. 

Figure IV–1 shows that the ‘‘knee’’ in 

the 2010 marginal cost-effectiveness 

curve—the point where the cost of 

controlling a ton of SO2 from EGUs is 

increasing at a noticeably higher rate—

appears to occur at about $2,000 per ton 

of SO2. Figure IV–2 shows that the 

‘‘knee’’ in the 2015 marginal costeffectiveness curve also appears to occur 

at about $2,000 per ton of SO2. (As 

discussed above, the projected marginal 

costs of SO2 reductions for the CAIR are 

$700 per ton in 2010 and $1,000 per ton 

in 2015.) The EPA used the Technology 

Retrofitting Updating Model (TRUM), a 

spreadsheet model based on the IPM, for 

this analysis. (The EPA based these 

marginal SO2 cost-effectiveness curves 

on the electric growth and natural gas 

price assumptions in the main CAIR 

IPM modeling run. Marginal cost 

effectiveness curves based on other 

electric growth and natural gas price 

assumptions would look different, 

therefore it would not be appropriate to 

compare the curves here to the marginal 

costs based on the IPM modeling 

sensitivity run that used EIA 

assumptions.) These results make clear 

that this rule is very cost effective 

because the control level is below the 

point at which the cost begins to 

increase at a significantly higher rate. 

In this manner, these results 

corroborate EPA’s findings above 

concerning the cost effectiveness of the 

emissions reductions.60


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Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25205

b. NOX Emissions Reductions 

Requirements 

i. The CAIR Proposal for NOX and 

Subsequent Analyses for Regionwide 

Annual and Ozone Season NOX Control 

Levels 

In this section, EPA describes its 

proposed method for determining 

regionwide NOX control levels and the 

method used for the final CAIR. 

In the CAIR NPR, EPA updated the 

reference list included in the NOX SIP 

Call for the average annual cost 

effectiveness of recent or proposed NOX

controls, and determined that these 

amounts ranged from approximately 

$200 to $2,800. In addition, in the NPR, 

EPA developed a reference list for 

marginal annual cost effectiveness for 

NOX controls, and determined that these 

amounts ranged from approximately 

$1,400 to $3,000 (69 FR 4614—4615). 

In the NPR, EPA proposed a twophased annual NOX control program, 

with a final phase in 2015 and a first 

phase in 2010. The regionwide 

emissions reduction requirements that 

EPA proposed—and the budget levels 

that would apply if all States chose to 

implement the reductions from EGUs—

were based on using a combination of 

recent historical heat input and NOX

emissions rates for fossil fuel-fired 

EGUs. For historical heat input, EPA 

proposed determining the highest heat 

input from units affected by the Acid 

Rain Program for each affected State for 

the years 1999–2002. The EPA then 

summed this heat input for all of the 

States affected for annual NOX

reductions. For 2015, EPA calculated a 

proposed regionwide annual NOX

budget by multiplying this heat input by 

an emission rate of 0.125 lb/mmBtu, and 

for 2010 by multiplying by 0.15 lb/

mmBtu. 

In developing the CAIR NPR, when 

EPA considered the appropriate amount 

of annual SO2 emissions reductions, 

EPA relied on the existing title IV 

annual SO2 cap as a starting point. 

However, in considering the appropriate 

amount of NOX reductions, the situation 

is different because title IV does not cap 

NOX emissions. Therefore, EPA and the 

States have focused on emissions caps 

based on a combination of heat input 

and NOX emission rates. Emission rates 

similar to the rates used to develop the 

CAIR NPR have been considered in the 

past. For example, the CAPI 1996 study, 

noted above, contemplated NOX caps 

based on an emission rate of 0.15 lb/

mmBtu (and other options based on 

NOX rates of 0.20 lb/mmBtu and 0.25 lb/

mmBtu). The NOX SIP Call is based on 

an emission rate of 0.15 lb/mmBtu. 

The methodology described in the 

NPR is best understood as the means for 

developing the target 2015 annual NOX

control level (or emissions budget) for 

further evaluation through IPM. The 

EPA developed this level mindful of its 

experience to date with the NOX SIP 

Call and the earlier work EPA has 

performed on multi-pollutant power 

plant reduction programs. The EPA also 

considered available technical 

information on pollution controls, costs 

to industry and the general public, 

ambient air improvement, and 

consistency with the emerging PM2.5

implementation program, in developing 

its target control level. 

Recent advances in combustion 

control technology for NOX reductions, 

as well as widespread use of selective 

catalytic reduction (SCR) on U.S. coalfired EGU boilers achieving NOX

emission rates of 0.06 lb/mmBtu and 

below, provide evidence that even lower 

average NOX emission rates are more 

highly cost-effective than rates 

considered in the past (based on 

analyzing EGUs), possibly on the order 

of 0.12 lb/mmBtu or less. The EPA 

developed the target annual NOX

control level (or emissions budget) with 


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25206 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

61The EPA does not collect annual heat input 

data from these non-Acid Rain units. EIA does 

collect heat input from such units, however there 

are some limitations to the data. First, there are no 

requirements specifying how the data should be 

collected or quality assured. Second, the data is 

collected on a plant-wide basis rather than on a 

unit-by-unit basis.

62 These projected average NOX emissions rates 

are from updated IPM modeling done in 2004. The 

IPM modeling done prior to the NPR also projected 

similar average emission rates, about 0.15 lb/

mmBtu and 0.11 lb/mmBtu in 2010 and 2015, 

respectively.

the understanding that the evaluation of 

that level might indicate that average 

emission rates on the order of 0.12 lb/

mmBtu or less might be highly cost 

effective for the final (2015) control 

phase, and an interim level resulting in 

an average emission rate of less than 

0.15 lb/mmBtu might be feasible for the 

first phase. 

The EPA did evaluate the target 

annual NOX control levels (or emissions 

budgets) using the IPM. The EPA 

confirmed that the 2015 level is highly 

cost effective. The Agency also 

evaluated the cost effectiveness of the 

proposed 2010 cap to assure that the 

interim phase reductions would also be 

highly cost effective. The EPA’s IPM 

analyses for the CAIR includes all fossil 

fuel-fired EGUs with generating capacity 

greater than 25 MW. 

The proposed cap for the first phase 

was developed taking into consideration 

how much pollution control for NOX

and SO2 could be installed without 

running into a shortage of skilled labor, 

in particular boilermakers (EPA’s 

assumptions regarding boilermaker 

labor are described in section IV.C.2 of 

this preamble). The Agency focused on 

providing substantial reductions of both 

SO2 and NOX emissions at the outset of 

the proposed program, leading to 

significant retrofits of Flue Gas 

Desulfurization units (FGD) for SO2

control and SCR for NOX control.

In the NPR, EPA explained that using 

the highest Acid Rain Program heat 

input for each State to develop a 

regionwide heat input amount, rather 

than the average Acid Rain Program 

heat input, provided a cushion that 

represented a reasonable adjustment to 

reflect that there are some non-Acid 

Rain units that operate in these States 

that will be subject to the proposed 

CAIR emission reduction levels. The 

EPA explained that it did not use heat 

input data from non-Acid Rain units in 

the proposal because it did not have all 

the necessary data available at the time 

the NPR was developed.61 Using the 

highest of recent years’ Acid Rain 

Program heat input provided an 

approximation of the regionwide heat 

input, although it did not include heat 

input from non-Acid Rain sources. 

Multiplying the approximate recent heat 

input by 0.125 lb/mmBtu to develop a 

proposed regionwide annual 2015 NOX

cap could reasonably be expected to 

yield an average effective NOX emission 

rate (considering all EGUs potentially 

affected by CAIR for annual reductions, 

not only the Acid Rain units, and 

considering growth in heat input) 

somewhat less than 0.125 lb/mmBtu. 

Likewise, multiplying the approximate 

recent heat input by 0.15 lb/mmBtu to 

develop a regionwide annual 2010 NOX

cap could reasonably be expected to 

yield an average effective NOX emission 

rate for all CAIR units of about 0.15 lb/

mmBtu or less.

Although EPA calculated—in essence, 

as a target level for further evaluation—

the proposed regionwide annual NOX

control levels (or emissions budgets) 

based on heat input from only Acid 

Rain Program units, the Agency 

evaluated the cost effectiveness of the 

control levels using heat input from all 

EGUs that potentially would be affected 

by the proposed CAIR. The EPA 

evaluated cost effectiveness using the 

IPM, which includes both Acid Rain 

units and non-Acid Rain units. Further, 

the IPM incorporates assumptions for 

electricity demand growth, and thus 

heat input growth. 

Specifically, EPA evaluated these 

target annual NOX caps on EGUs for 

2010 and 2015—and therefore the 

associated regionwide emissions 

reductions—using the IPM, which, in 

effect, demonstrated that these proposed 

NOX emissions cap levels can be met 

using highly cost-effective controls with 

the expected levels of electricity 

demand in 2010 and 2015, respectively. 

Those expected levels of electricity 

demand are higher than the electricity 

demand during the 1999 to 2002 years 

upon which EPA based heat input; and 

as a result, the amount of heat input 

necessary to meet the projected 

electricity demand is expected to be 

higher than the amount that EPA 

developed for evaluation purposes 

through the method described above. 

The projected average future emissions 

rates that would be associated with the 

2010 and 2015 heat input levels needed 

to meet electricity demand (coupled 

with the NOX emissions budgets 

developed through the methodology 

described above) would be about 0.14 

lb/mmBtu and 0.11 lb/mmBtu in 2010 

and 2015, respectively.62 These average 

rates would be for all units affected by 

annual NOX controls under CAIR, 

including non-Acid Rain units. Thus, 

the heat input is projected to be higher 

in 2010 and 2015 than the recent 

historic heat input used to develop the 

target emissions budgets, and the 

projected NOX emission rates in 2010 

and 2015 are lower than the 0.15 lb/

mmBtu and 0.125 lb/mmBtu rates that 

were used to develop the budgets. IPM 

determined the costs of meeting these 

average future NOX emission rates of 

0.14 lb/mmBtu and 0.11 lb/mmBtu. The 

EPA considers these emission rates to be 

highly cost-effective and feasible.

In the NPR, EPA proposed an interim 

(Phase I) annual NOX phase in 2010 and 

a final (Phase II) annual NOX phase in 

2015. However, in today’s final rule, 

EPA is promulgating a Phase I for NOX

in 2009 (with the Phase II for NOX in 

2015, as proposed). The EPA 

determined the regionwide NOX control 

levels for 2009 and 2015 for today’s 

final action using the same methodology 

as we used to determine proposed 

levels. The Agency evaluated the cost 

effectiveness of the final reduction 

requirements (and average NOX

emission rates) using IPM and 

determined them to be highly costeffective, assuming controls on EGUs. 

The EPA’s evaluation of the cost 

effectiveness of the emission reduction 

strategy we assumed in establishing the 

final CAIR control levels is discussed 

further below. 

The average NOX emission rates in the 

first and second phases of CAIR will be 

lower than the nominal emission rate on 

which the NOX SIP Call was based, 

which was 0.15 lb/mmBtu. In the NOX

SIP Call, EPA also considered a control 

level based on a lower nominal 

emission rate, 0.12 lb/mmBtu. However, 

at that time the use of SCR was not 

sufficiently widespread to allow EPA to 

conclude that the controls necessary to 

meet a tighter cap could be installed in 

the required timeframe, without causing 

reliability problems for the electric 

power sector. Now, through the 

experience gained from the NOX SIP 

Call, EPA has confidence that with SCR 

technology average emissions rates 

lower than the NOX SIP Call nominal 

emission rate can be achieved on a 

regionwide basis. 

In the CAIR NPR, after determining 

the regionwide control level and 

evaluating it to assure that it is highly 

cost-effective, the Agency then 

apportioned the regionwide budgets to 

the affected States. The EPA proposed to 

apportion regionwide NOX budgets to 

individual States on the basis of each 

State’s share of recent average heat 

input. In the NPR, EPA used the average 

share of Acid Rain Program heat input. 

However, as discussed in the SNPR and 

the NODA, in order to distribute more 

equitably to States their share of the 

regionwide NOX budgets, EPA then 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25207

63The control costs for this model sensitivity that 

were presented in the NPR were in error (69 FR 

4615). The corrected costs from the sensitivity are 

as shown here.

considered each State’s proportional 

share of recent average heat input using 

data from non-Acid Rain Program 

sources as well as Acid Rain Program 

sources. The EPA obtained EIA heat 

input data reported for non-Acid Rain 

sources and combined the EIA heat 

inputs with Acid Rain heat inputs to 

determine each State’s share of 

combined average recent heat input.

The fact that EPA distributed the 

regionwide budget to individual States 

based on their proportional share of heat 

input from Acid Rain and non-Acid 

Rain units combined does not affect the 

determination of the regionwide budgets 

themselves. The regionwide budgets 

were determined to be highly costeffective when tested for all units—both 

non-Acid Rain units as well as Acid 

Rain units—that would be affected by 

CAIR. (The EPA’s method for 

apportioning regionwide NOX budgets 

to States is discussed in more detail 

elsewhere in today’s preamble. That 

discussion includes an explanation of 

the differences between the State 

budgets that were presented in the NPR, 

the SNPR, and the NODA. In addition, 

see the TSD entitled ‘‘Regional and State 

SO2 and NOX Emissions Budgets.’’) 

In the NPR, EPA proposed that 

Connecticut contributed significantly to 

downwind ozone nonattainment, but 

not to PM2.5 nonattainment. Thus, the 

Agency proposed that Connecticut 

would not be subject to an annual NOX

control requirement and was not 

included in the region proposed for 

annual controls. We proposed that 

Connecticut would be affected by an 

ozone season-only NOX control level, 

and proposed to calculate Connecticut’s 

ozone season control level in a parallel 

way to how the regionwide annual NOX

control levels were calculated. That is, 

EPA selected the highest of the same 4 

years of (ozone season-only) heat input 

used for the regionwide budget 

calculation, and multiplied that heat 

input by the same NOX emission rates 

used to calculate the regionwide control 

levels. Connecticut is the only State for 

which an ozone season budget was 

proposed. 

The EPA used the same methodology 

for developing regionwide budgets for 

today’s final rule as was proposed in the 

NPR. For the final CAIR, EPA found that 

23 States and the District of Columbia 

contribute significantly to downwind 

PM2.5 nonattainment and found that 25 

States and the District of Columbia 

contribute significantly to downwind 

ozone nonattainment (section III in 

today’s preamble describes the 

significance determinations). CAIR 

requires annual NOX reductions in all 

States determined to contribute 

significantly to downwind PM2.5

nonattainment, and requires ozone 

season NOX reductions in all States 

determined to contribute significantly to 

downwind ozone nonattainment (many 

of the CAIR States are affected by both 

annual and ozone season NOX reduction 

requirements). The final CAIR ozone 

season NOX reductions are required in 

two phases, with Phase I commencing 

in 2009 and Phase II in 2015, the same 

years as the annual NOX reduction 

requirements. 

As described above, the Agency 

proposed ozone season NOX reduction 

requirements for Connecticut, and did 

not propose separate ozone season 

reduction requirements in any other 

State. For today’s final rule, EPA 

requires ozone season reductions in all 

States contributing significantly to 

downwind ozone nonattainment. The 

EPA determined regionwide ozone 

season NOX control levels for the final 

CAIR using the same methodology as 

was used for the annual NOX reduction 

requirements (which is the same 

method that was proposed for 

Connecticut’s ozone season budget). 

That is, EPA determined the highest 

(ozone season) heat input from Acid 

Rain Program units for the years 1999–

2002 for each State, then summed this 

heat input for all of the States affected 

for ozone season NOX reductions. For 

the final 2015 control level, EPA 

calculated a regionwide ozone season 

NOX budget by multiplying this heat 

input by an emission rate of 0.125 lb/

mmBtu, and for 2009 by multiplying by 

0.15 lb/mmBtu. The Agency evaluated 

the cost effectiveness of these ozone 

season NOX control levels (and average 

NOX emission rates) using IPM and 

determined them to be highly costeffective, assuming controls on EGUs. 

The EPA’s evaluation of the cost 

effectiveness of the final CAIR control 

requirements is discussed further below.

Based on EPA’s analysis of proposed 

annual NOX control levels, in the NPR 

the Agency presented average costs for 

annual NOX control of $800 per ton and 

$700 per ton for 2010 and 2015, and 

marginal costs of $1,300 per ton and 

$1,500 per ton for 2010 and 2015. In the 

NPR, EPA also presented marginal costs 

of annual NOX control from sensitivity 

analyses that used EIA assumptions for 

electricity growth and natural gas 

prices. Those marginal control costs 

were $1,300 per ton and $1,600 per ton 

for 2010 and 2015, respectively. The 

EPA also presented costs from a 

sensitivity model run that used EIA 

assumptions for electricity growth and 

natural gas price and higher SCR costs. 

These marginal control costs were 

$1,700 per ton and $2,200 per ton for 

2010 and 2015, respectively.63

In the NPR, EPA also presented the 

average cost effectiveness for ozone 

season-only NOX control of $1,000 per 

ton and $1,500 per ton for 2010 and 

2015, respectively, and a marginal cost 

for ozone season-only control of $2,200 

per ton and $2,600 per ton for 2010 and 

2015. The EPA also presented average 

costs for the non-ozone season 

(remaining seven months of the year) 

control of $700 per ton and $500 per ton 

in 2010 and 2015, respectively. (As 

noted above, the capital costs of 

installing NOX control equipment 

would be largely identical whether the 

equipment will be operated during the 

ozone season only or for the entire year. 

However, the amount of reductions 

would be less if the control equipment 

were operated only during the ozone 

season compared to annual operation.) 

The EPA proposed the conclusion 

that these costs met the criteria for 

highly cost-effective emissions 

reductions for NOX (69 FR 4613–4615). 

As with SO2, EPA also considered the 

cost effectiveness of alternative 

stringency levels for this regulatory 

proposal (examining changes in the 

marginal cost curve at varying levels of 

emission reductions). 

ii. What Are the Most Significant 

Comments That EPA Received About 

Proposed NOX Emission Reduction 

Requirements, and What Are EPA’s 

Responses? 

Some commenters expressed concern 

that EPA did not account for growth of 

heat input in calculating regionwide 

NOX emissions budgets, noting that 

growth was used in the calculation of 

the regional budget for the NOX SIP 

Call. Commenters suggest that, by not 

taking heat input growth into account, 

EPA developed regionwide budgets that 

are unduly stringent. 

On the other hand, some commenters 

noted that they supported EPA’s 

proposal to base regionwide budgets on 

historical heat input and did not want 

EPA to use growth projections for 

calculating regionwide NOX emissions 

budgets. Some stated that using actual, 

historic heat input numbers would be 

more straightforward than using growth 

projections, and some pointed to 

complications with the growth 

projection methodologies used in the 

NOX SIP Call. 

The EPA recognizes that it employed 

a growth factor in the NOX SIP Call. 

25208 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

64The updated reference list includes estimated 

average NOX control costs under BART. The BART 

rule has been proposed but not finalized (69 FR 

25184; May 5, 2004).

There, EPA determined the amount of 

the regional emissions reductions and 

budgets by applying a growth factor to 

a historic heat input baseline. The DC 

Circuit, after first remanding that growth 

methodology for a better explanation, 

upheld it. West Virginia v. EPA, 362 

F.3d 861 (DC Cir., 2004). See 67 FR 21 

868 (May 1, 2002). 

For CAIR, as described above, EPA 

developed a target level for the 

proposed NOX regionwide cap based on 

recent historic heat input and assumed 

emission rates of 0.125 lb/mmBtu and 

0.15 lb/mmBtu for 2015 and 2010, 

respectively. The EPA evaluated these 

target NOX emissions levels using IPM, 

which indicated that those target caps—

in conjunction with expected electricity 

demand for 2015 and 2010—would 

result from higher heat input levels and 

lower average emissions rates (about 

0.11 lb/mmBtu and 0.14 lb/mmBtu for 

2015 and 2010, respectively) than the 

amounts assumed in developing the 

target NOX caps. Most importantly, IPM 

indicated the cost levels associated with 

those projected 2015 and 2010 average 

NOX emission rates, and EPA has 

determined that those cost levels are 

highly cost-effective. For the final rule, 

EPA revised its analyses to reflect the 

2009 initial NOX control phase, and 

determined that the final CAIR 

requirements are highly cost-effective. 

The EPA’s methodology, in which the 

CAIR emissions reductions are 

predicted to be cost-effective under 

conditions of projected electricity 

growth that, in turn, projects heat input 

growth, in effect accounts for heat input 

growth. Moreover, the amount of heat 

input growth is the amount determined 

by IPM, a state-of-the-art model of the 

electricity sector (detailed 

documentation for IPM is in the docket). 

Some commenters suggested that EPA 

adjust the NOX regionwide budget 

amounts to include heat input from 

non-Acid Rain units. For example, some 

suggested adding the non-Acid Rain 

unit heat input amounts that EPA used 

in apportioning regionwide NOX

budgets to the States, to the total 

regionwide heat inputs that EPA used to 

calculate regionwide NOX budgets. 

The regionwide budgets determined 

in the NPR were target levels developed 

as a starting point for further evaluation. 

The regionwide heat input amounts and 

NOX emission rates used to develop 

target budget levels were inherently 

imprecise. As discussed above, IPM 

modeling indicates that the projected 

future heat input amounts (based on 

electricity growth) are greater than the 

recent historic regionwide amount used 

to develop the target budget levels, and 

the future average emission rates for all 

units affected by CAIR annual NOX

controls (including non-Acid Rain 

units) are less than the rates used to 

develop the target budget levels. IPM 

indicates that the target regionwide NOX

budget levels (and corresponding future 

average NOX emission rates and heat 

input levels) are highly cost-effective for 

all CAIR units, including non-Acid Rain 

units. The EPA does not believe it is 

necessary to adjust the target regionwide 

budget levels to include the relatively 

small additional amount of heat input 

from non-Acid Rain units. The method 

the Agency used to develop target levels 

was not intended to be a precise 

methodology for determining the NOX

caps; rather, it was a reasonable method 

for selecting a target level to be 

evaluated further. Upon evaluation of 

the target level, EPA determined that it 

can be achieved using highly costeffective controls for all affected EGUs, 

including non-Acid Rain units. 

iii. Analysis of NOX Emission Reduction 

Requirements for Today’s Final Rule

(I) Reference Lists of Cost-Effective 

Controls 

For today’s action, EPA updated the 

reference list of controls included in the 

NPR of the average and marginal costs 

per ton of recent NOX control actions. 

The EPA systematically developed a list 

of cost information from recent actions 

and proposed actions. The Agency 

sought cost information for actions 

taken by EPA, and examined the 

comments submitted after the NPR was 

published, to identify all available 

control cost information to provide the 

updated reference list for today’s 

preamble. The updated reference list 

includes both average and marginal 

costs of control to which EPA compares 

the CAIR control costs, although the 

Agency has limited information on 

marginal costs of other programs. 

The EPA’s updated summary of 

average costs of annual NOX controls are 

shown in Table IV–6. The results of this 

reexamination show that costs of recent 

actions are generally very similar to 

those identified in the NOX SIP Call. 

The cost figures are presented in 1999 

dollars.64

TABLE IV–6.—AVERAGE COSTS PER TON OF ANNUAL NOX CONTROLS

NOX control action Average cost 

per ton 

Marine Compression Ignition Engines .............................................................................................................................................. Up to $200 2

Off-highway Diesel Engine ............................................................................................................................................................... $400–$700 2

Nonroad Diesel Engines and Fuel ................................................................................................................................................... $600 1

Marine Spark Ignition Engines ......................................................................................................................................................... $1,200–$1,800 2

Tier 2 Vehicle Gasoline Sulfur .......................................................................................................................................................... $1,300–$2,3002

Revision of New Source Performance Standards for NOX Emissions-EGUs ................................................................................. $1,700 3

2007 Highway Heavy Duty Diesel Standards .................................................................................................................................. $1,600–$2,100 2

National Low Emission Vehicle ........................................................................................................................................................ $1,900 2

Tier 1 Vehicle Standards .................................................................................................................................................................. $2,100–$2,800 2

Revision of New Source Performance Standards for NOX Emissions-Industrial Units ................................................................... $2,200 3

On-board Diagnostics ....................................................................................................................................................................... $2,300 2

Texas NOX Emission Reduction Grants FY 2002–2003 ................................................................................................................. $300–$12,700 4

Best Available Retrofit Technology (BART) for Electric Power Sector ............................................................................................ $800 5

1 Control of Emissions of Air Pollution From Nonroad Diesel Engines and Fuel; Final Rule (69 FR 39131; June 29, 2004). The value in this 

table represents the long-term cost per ton of emissions reduced from the total fuel and engine program (cost per ton of emissions reduced in 

the year 2030). This value includes the cost for NOX plus NMHC reductions. 1999$ per ton. 2 Control of Air Pollution from New Motor Vehicles: Heavy-Duty Engine and Vehicle Standards and Highway Diesel Fuel Sulfur Control Requirements; Final Rule (66 FR 5102; January 18, 2001). The values shown for 2007 Highway HD Diesel Stds are discounted costs. Costs shown 

in this table include a VOC component. 1999$ per ton. 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25209

65The CSP consists of 200,000 tons, which is 

apportioned to each of the 23 States and the District 

of Columbia that are required by CAIR to make 

annual NOX reductions, as well as the 2 States 

(Delaware and New Jersey) for which EPA is 

proposing to require annual NOX reductions.

3Proposed Revision of Standards of Performance for Nitrogen Oxide Emissions From New Fossil-Fuel Fired Steam Generating Units; Proposed Revision to Reporting Requirements for Standards of Performance for New Fossil-Fuel Fired Steam Generating Units; Proposed Rule (62 

FR 36953; July 9, 1997), Table 4 (the Agency’s estimate of average control costs was unchanged for the NSPS revisions final rule, published 

September 5, 1998). In the CAIR NPR, we included a value from the range of NOX controls for coal-fired EGUs from Table 2 in the proposed 

NSPS proposed rule (62 FR 36951). 1999$ per ton. 4 Costs shown in this table are the range of project costs reported for projects that were FY 2002–2003 recipients of the TERP Emission Reductions Incentive Grants Program. These costs may not be in 1999 dollars. (www.tnrcc.state.tx.us/oprd/sips/grants.html) 5The EPA IPM modeling 2004 of the proposed BART for the electric power sector (69 FR 25184, May 5, 2004), available in the docket. The 

EPA modeled the Regional Haze Requirements as a source specific 0.2 lb/mmBtu NOX emission rate limit. Estimated average costs based on 

this modeling are $800 per ton in 2015 and 2020. 1999$ per ton. 

Table IV–7 presents modeled 

marginal costs for recent State annual 

NOX rules.

TABLE IV–7.—MARGINAL COSTS PER TON OF REDUCTION, RECENT ANNUAL NOX RULES

NOX control action Marginal cost per 

ton 

Texas Rules ................................................................................................................................................................................... $2,000–$19,600 1

1The EPA IPM base case modeling August 2004, available in the docket. 1999$ per ton. We modeled Senate Bill 7 and Ch. 117, which impose varying NOX control requirements in different areas of the State; the range of marginal costs shown here reflects the range of 

requirements. 

The EPA does not believe that it has 

sufficient information, for today’s 

rulemaking, to treat controls on source 

categories other than certain EGUs as 

providing highly cost-effective 

emissions reductions. The CAA Section 

110 permits States to choose the sources 

and source categories that will be 

controlled in order to meet applicable 

emission and air quality requirements. 

This means that some States may choose 

to meet their CAIR obligations by 

imposing control requirements on 

sources other than EGUs.

As examples of cost-effective actions 

that States can take in efforts to provide 

for attainment with the air quality 

standards, Table IV–8 presents 

estimated average costs for potential 

local mobile source NOX control 

actions. The EPA received these cost 

data during the public comments on the 

NPR.

TABLE IV–8.—AVERAGE COSTS OF POTENTIAL LOCAL MOBILE SOURCE CONTROL ACTIONS TO REDUCE NOX EMISSIONS

[$ per Ton] 1

Source category Average cost per 

ton 

MWCOG Analysis: Mobile Source, Bicycle racks in DC ............................................................................................................... $9,000 

MWCOG Analysis: Mobile Source, Telecommuting Centers ........................................................................................................ 7,300 

MWCOG Analysis: Mobile Source, Government Action Days (ozone action days) ..................................................................... 5,000 

MWCOG Analysis: Mobile Source, Permit Right Turn on Red ..................................................................................................... 1,200 

MWCOG Analysis: Mobile Source, Employer Outreach ............................................................................................................... 3,500 

MWCOG Analysis: Mobile Source, Mass Marketing Campaign ................................................................................................... 2,900 

MWCOG Analysis: Mobile Source, Transit Prioritization .............................................................................................................. 8,500 

1Washington DC Metro Area MWCOG Analysis of Potential Reasonably Available Control Measures (RACM). Projects determined to be ‘‘Possible’’ by MWCOG but not RACM because benefits from the possible control measures do not meet the 8.8 tpd NOX or 34.0 tpd VOC threshold 

necessary for RACM. These costs may not be in 1999 dollars. (www.mwcog.org/uploads/committee-documents/z1ZZXg20040217144350.pdf) 

Comments submitted to the EPA CAIR docket from the Clean Air Task Force et al., dated March 30, 2004, included costs from the MWCOG 

analysis. 

(II) Cost Effectiveness of CAIR Annual 

NOX Reductions 

Table IV–9 provides the average and 

marginal costs of annual NOX

reductions under CAIR for 2009 and 

2015. These costs are updated from the 

NPR figures—the EPA analyzed the 

costs of the CAIR using an updated 

version of IPM (documentation for the 

IPM update is in the docket). Further, 

EPA modified the modeling to match 

the final CAIR strategy (see section 

IV.A.1 for a description of EPA’s CAIR 

IPM modeling). 

CAIR provides for a Compliance 

Supplement Pool (CSP) of NOX

allowances that can be used for 

compliance with the annual NOX

reduction requirements. The CSP is 

discussed in detail later in this 

preamble. The EPA used IPM to model 

marginal costs of CAIR with the CSP. 

The magnitude of the NOX CSP is 

relatively small compared to the annual 

NOX budget,65 thus the CSP does not 

significantly impact the marginal costs 

(see Table IV–9).

As with SO2 marginal costs, EPA 

considered the sensitivity of the NOX

marginal cost results to assumptions of 

higher electric growth and future 

natural gas prices than the Agency used 

in the base case, as shown in Table IV–

9.

TABLE IV–9.—ESTIMATED COSTS PER

TON OF ANNUAL NOX CONTROLLED

UNDER CAIR 1

Type of cost effectiveness 2009 2015 

Average Cost—Main Case $500 $700 

Marginal Cost—Main Case 1,300 1,600 

25210 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

TABLE IV–9.—ESTIMATED COSTS PER

TON OF ANNUAL NOX CONTROLLED

UNDER CAIR 1—Continued

Type of cost effectiveness 2009 2015 

Marginal Cost—With Compliance Supplement 

Pool (CSP) .................... 1,300 1,600 

Sensitivity Analysis: Marginal Cost Using Alternate Electricity Growth 

and Natural Gas Price 

Assumptions .................. 1,400 1,700 

1The EPA IPM modeling 2004, available in 

the docket. 1999$ per ton. 

These estimated NOX control costs 

under CAIR reflect annual EGU NOX

caps of 1.5 million tons in 2009 and 1.3 

million tons in 2015 within the CAIR 

annual NOX control region (the 23 

States and DC that must make annual 

reductions). In both the main IPM 

modeling case and the modeling case 

that includes the CSP, projected annual 

NOX emissions in the CAIR region will 

be about 1.5 million tons in 2009 and 

1.3 million tons in 2015. The projected 

emissions are very similar in both 

modeling cases because the CSP is 

relatively small compared to the annual 

NOX budget. 

Average costs shown for 2015 are 

based on the amount of reductions that 

would achieve the total difference in 

projected emissions between the base 

case conditions and CAIR in the year 

2015. These costs are not based on the 

increment in reductions between 2009 

and 2015. (A more detailed description 

of the final CAIR SO2 and NOX control 

requirements is provided later in today’s 

preamble.) 

Most of the States subject to today’s 

PM2.5 control requirements have been 

subject to the NOX SIP Call 

requirements. Some sources in these 

States have installed SCRs, and run 

them during the ozone season. These 

sources might comply with the PM2.5

annual NOX requirements by, at least in 

part, running the SCR controls for the 

remaining months of the year. Under 

these circumstances, the compliance 

costs for the PM2.5 SIP requirements are 

lower. 

Table IV–10 provides estimated costs 

per ton of NOX for non-ozone season 

reductions under CAIR. These figures 

are updated from the NPR 

calculations—the EPA analyzed the 

costs of the CAIR using an updated 

version of IPM (documentation for the 

IPM update is in the docket) and 

modeled controls on a region that more 

closely matches the region affected by 

CAIR.

TABLE IV–10.—PREDICTED COSTS

PER TON OF NON-OZONE SEASON

NOX CONTROLLED UNDER CAIR 1

Type of cost effectiveness 2009 2015 

Average Cost .................... $500 $500 

1The EPA IPM modeling 2004, available in 

the docket. 1999$ per ton. 

The estimated non-ozone season NOX

costs, like the annual NOX costs, are on 

the low end of the cost effectiveness 

range described in Table IV–6. The EPA 

considers the 2015 and also the 2009 

costs to represent highly cost-effective 

controls.

Environmental Defense reached 

similar conclusions regarding the cost 

effectiveness of non-ozone season NOX

reductions, as described in their report 

‘‘A Plan for All Seasons: Costs and 

Benefits of Year-Round NOX Reductions 

in Eastern States (2002).’’ As stated in 

that report, ‘‘[As Figure 4 shows,] 

extending NOX reductions throughout 

the year results in dramatic decreases in 

the per-ton costs of NOX emission 

reductions for the 19 NOX SIP Call 

States. This is because the bulk of the 

cost for reducing NOX emissions from 

power plants lies in the capital 

investment in the control equipment. 

Once the primary investment has been 

made, it costs relatively little to 

continue running the control equipment 

beyond the summer months required by 

EPA’s NOX SIP Call.’’ Environmental 

Defense based these conclusions on 

analysis conducted by Resources for the 

Future (RFF). In an RFF paper, ‘‘CostEffective Reduction of NOX Emissions 

from Electricity Generation (July 2001),’’

RFF draws similar conclusions. 

(III) NOX Cost Comparison for CAIR 

Requirements 

The EPA believes that selecting as 

highly cost-effective amounts at the 

lower end of these average and marginal 

cost ranges is appropriate for reasons 

explained above in this section of the 

preamble. 

As discussed above, although in the 

NOX SIP Call the cost level selected was 

not at the low end of the reference range 

of costs, if the NOX SIP Call costs were 

for annual rather than seasonal controls 

they would have been lower relative to 

the other control costs on the reference 

list which were mostly for annual 

programs. 

For annual NOX, the range of average 

cost effectiveness extends broadly, from 

under $200 to thousands of dollars 

(Table IV–6). The 2015 estimated 

average costs for CAIR annual NOX

control of $700 are consistent with the 

lower end of this range. 

Less information is available for the 

marginal costs of controls than for 

average costs. Looking at the available 

marginal costs (Table IV–7), the 2015 

CAIR marginal costs for annual NOX

controls are at the lower end of the 

range. The EPA also evaluated the cost 

effectiveness of the 2009 cap, and 

concluded that the 2009 requirements 

are highly cost-effective. 

(IV) Cost Effectiveness: Marginal Cost 

Curves for Annual NOX Control 

As with SO2 controls, EPA also 

considered the cost effectiveness of 

alternative stringency levels for NOX

control for today’s action by examining 

changes in the marginal cost curve at 

varying levels of emissions reductions. 

Figure IV–3 shows that the ‘‘knee’’ in 

the 2010 marginal cost effectiveness 

curve for EGUs—the point where the 

cost of controlling a ton of NOX begins 

to increase at a noticeably higher rate—

appears to occur at over $1,700 per ton 

of NOX. Although EPA conducted this 

marginal cost curve analysis based on 

an initial NOX control phase in 2010, 

the results would be very similar for 

2009, which is the initial NOX phase in 

the final CAIR. Figure IV–4 shows that 

the ‘‘knee’’ in the 2015 marginal cost 

effectiveness curve for EGUs appears to 

occur at over $1,700 per ton of NOX. 

(The EPA based these marginal NOX

cost effectiveness curves on the 

electricity growth and natural gas price 

assumptions in the main CAIR IPM 

modeling run. Marginal cost 

effectiveness curves based on other 

electric growth and natural gas price 

assumptions would look different, 

therefore it would not be appropriate to 

compare the curves here to the marginal 

costs based on the IPM modeling 

sensitivity run that used EIA 

assumptions.) The EPA used the 

Technology Retrofitting Updating Model 

(TRUM), a spreadsheet model based on 

IPM, for this analysis. These results 

make clear that this rule is very costeffective because the control level is 

below the point at which the cost begins 

to increase at a significantly higher rate. 

In this manner, these results 

corroborate EPA’s findings above 

concerning the cost effectiveness of the 

emissions reductions.66

BILLING CODE 6560–50–P

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25211

66EPA is using the knee in the curve analysis 

solely to show that the required emissions 

reductions are very cost effective. The marginal cost 

curve reflects only emissions reduction and cost 

information, and not other considerations. We note 

that it might be reasonable in a particular regulatory 

action to require emissions reductions past the knee 

of the curve to reduce overall costs of meeting the 

NAAQS or to achieve benefits that exceed costs. As 

in the case of SO2 controls, described above, it 

should be noted that similar analysis for other 

source categories may yield different curves.


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25212 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

67For both the NOX SIP Call and CAIR, the NOX

control costs on the reference lists are generally for 

annual reductions. The EPA compared the costs of 

ozone season reductions under the NOX SIP Call, 

as well as ozone season CAIR NOX reductions, to 

the annual reduction programs on the reference 

lists.

68 In the NOX SIP Call EPA used average, not 

marginal, costs to evaluate cost effectiveness. For 

the reasons discussed above we are evaluating both 

average and marginal costs for CAIR.

69Estimated costs for regionwide CAIR NOX

controls during the ozone season are higher than 

the average and marginal costs for CAIR annual 

NOX controls. This is because, as noted above, the 

capital costs of installing NOX control equipment 

would be largely identical whether the SCR will be 

operated during the ozone season only or for the 

entire year. However, the amount of reductions 

would be less if the control equipment were 

operated only during the ozone season compared to 

annual operation.

70EPA is using the knee in the curve analysis 

solely to show that the required emissions 

reductions are very cost effective. The marginal cost 

curve reflects only emissions reduction and cost 

information, and not other considerations. We note 

that it might be reasonable in a particular regulatory 

action to require emissions reductions past the knee 

of the curve to reduce overall costs of meeting the 

NAAQS or to achieve benefits that exceed costs. As 

in the case of SO2 controls, described above, it 

should be noted that similar analysis for other 

source categories may yield different curves.

(V) Cost Effectiveness of Ozone Season 

NOX Reductions 

The CAIR requires ozone season NOX

emissions reduction for all States 

determined to contribute significantly to 

ozone nonattainment downwind (25 

States and the District of Columbia). The 

EPA used IPM to model average and 

marginal costs of the ozone season 

reductions assuming EGU controls. In 

this modeling case, EPA modeled an 

ozone season NOX cap for the region 

affected by CAIR for downwind ozone 

nonattainment, but did not include the 

CAIR annual SO2 or NOX caps. Based on 

that modeling, Table IV–11 provides 

estimated average and marginal costs of 

regionwide ozone season NOX

reductions for 2009 and 2015. Table IV–

11 shows the estimated cost 

effectiveness of today’s ozone season 

NOX control requirements for 8-hour 

transport SIPs.

TABLE IV–11.—ESTIMATED COSTS

PER TON OF OZONE SEASON NOX

CONTROLLED UNDER CAIR 1

Type of cost effectiveness 2009 2015 

Average Cost .................... $900 $1,800 

Marginal Cost ................... 2,400 3,000 

1The EPA IPM modeling 2004, available in 

the docket. 1999$ per ton. 

These estimated NOX control costs are 

based on ozone season EGU NOX caps 

of 0.6 million tons in 2009 and 0.5 

million tons in 2015 within the CAIR 

ozone season NOX control region. 

Average costs shown for 2015 are based 

on the amount of reductions that would 

achieve the total difference in projected 

emissions between the base case 

conditions and CAIR in the year 2015. 

These costs are not based on the 

increment in reductions between 2009 

and 2015. (A more detailed description 

of the final CAIR SO2 and NOX control 

requirements is provided later in today’s 

preamble.) 

The EPA believes that selecting as 

highly cost-effective amounts at the 

lower end of the average and marginal 

cost ranges is appropriate for reasons 

explained above in section IV in this 

preamble. 

In the NOX SIP Call, EPA identified 

average costs of $2,500 (1999$) (or 

$2,000 (1990$)) as highly costeffective.67 The estimated average costs 

of regionwide ozone season NOX control 

under CAIR are $1,800 per ton in 2015 

and $900 per ton in 2009. Thus, with 

respect to average costs the controls for 

the final phase (2015) cap, which are 

below the $2,500 identified in the NOX

SIP Call, are also highly cost-effective, 

as are those for the 2009 cap. In 

addition, the estimated average costs of 

CAIR ozone season NOX control are at 

the lower end of the reference range of 

average annual NOX control costs (the 

reference list of average annual NOX

control costs is presented above).

Similarly, the estimated marginal 

costs 68 of ozone season CAIR NOX

controls are within EPA’s reference 

range of marginal costs, at the lower end 

of the range (the reference list of 

marginal annual NOX control costs is 

presented above). We note that the 

marginal costs in the reference range are 

for annual NOX reductions, and would 

likely be higher for ozone season only 

programs. Considering both average and 

marginal costs, the CAIR ozone season 

control level is highly cost-effective.

For purposes of estimating costs of 

ozone season control under CAIR, EPA 

set up this modeling case with CAIR 

ozone season NOX requirements but 

without the annual NOX requirements. 

The Agency believes that the cost of the 

ozone season CAIR requirements will 

actually be lower than the costs 

presented here because interactions will 

occur between the CAIR annual and 

ozone season NOX control 

requirements.69 In addition, for States in 

both programs, the same controls 

achieving annual reductions for PM 

purposes will achieve ozone season 

reductions for ozone purposes; this is 

not reflected in our cost-per-ton 

estimates.

As with SO2 controls, and annual 

NOX controls, EPA also considered the 

cost effectiveness of alternative 

stringency levels for CAIR NOX

reductions for ozone purposes by 

examining changes in the marginal cost 

curve at varying levels of emissions 

reductions. Figure IV–5 shows that the 

‘‘knee’’ in the 2010 marginal cost 

effectiveness curve for ozone season 

NOX reductions from EGUs—the point 

where the cost of controlling an ozone 

season ton of NOX begins to increase at 

a noticeably higher rate—appears to 

occur somewhere between $3,000 and 

$4,000 per ton of NOX. Although EPA 

conducted this marginal cost curve 

analysis based on an initial NOX control 

phase in 2010 the results would be very 

similar for 2009, which is the initial 

NOX phase in the final CAIR. Figure IV–

6 shows that the ‘‘knee’’ in the 2015 

marginal cost effectiveness curve for 

ozone season NOX reductions from 

EGUs appears to occur somewhere 

between $3,000 and $4,000 per ton of 

NOX. The EPA used the Technology 

Retrofitting Updating Model (TRUM), a 

spreadsheet model based on the IPM, for 

this analysis. These results make clear 

that CAIR NOX reductions for ozone 

purposes are very cost-effective because 

the control level is below the point at 

which the cost begins to increase at a 

significantly higher rate. 

In this manner, these results 

corroborate EPA’s findings above 

concerning the cost effectiveness of the 

emissions reductions.70

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25213

B. What Other Sources Did EPA 

Consider When Determining Emission 

Reduction Requirements? 

1. Potential Sources of Highly CostEffective Emissions Reductions 

In today’s rulemaking, EPA 

determines the amount of regionwide 

emissions reductions required by 

determining the amount of emissions 

reductions that could be achieved 

through the application of highly costeffective controls on certain EGUs. The 

EPA has reviewed other source 

categories, but concludes that for 

purposes of today’s rulemaking, there is 

insufficient information to conclude 

that highly cost-effective controls are 

available for other source categories. 

a. Mobile and Area Sources 

In the NPR (69 FR 4610), EPA 

explained that ‘‘it did not identify 

highly cost-effective controls on mobile 

or area sources.’’ No comments were 

received suggesting that mobile or area 

sources should be controlled. Therefore, 

in developing emission reduction 

requirements, EPA is not assuming any 

emissions reductions from mobile or 

area sources. 

b. Non-EGU Boilers and Turbines 

The largest single category of 

stationary source non-EGUs are large 

non-EGU boilers and turbines. This 


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source category emits both SO2 and 

NOX. In the CAIR NPR, EPA proposed 

not to include any potential SO2 or NOX

emissions reductions from non-EGU 

boilers and turbines as constituting 

‘‘highly cost-effective’’ reductions and 

thus to be taken into account in 

establishing emissions requirements 

because EPA believed it had insufficient 

information on their control costs, 

particularly costs associated with the 

integration of NOX and SO2 controls. In 

addition, based on information EPA 

does have, projected base case (without 

the CAIR) emissions of SO2 and NOX

from these sources are significantly 

lower than projected EGU emissions. 

The EPA projects that in 2010 under 

base case conditions, EGUs would 

contribute 70 percent of SO2 in the 

CAIR region compared to 15 percent 

from non-EGU boilers and turbines in 

the CAIR region. The Agency also 

predicts that in 2010 under the base 

case, EGUs would contribute 25 percent 

of NOX emissions in the CAIR region 

compared to 16 percent from non-EGU 

boilers and turbines in the CAIR region. 

Thus, simply on an absolute basis, nonEGU emissions are relatively less 

significant than emissions from EGUs. 

The EPA is finalizing its proposed 

approach to these sources and has not 

based today’s requirements on any 

presumed availability of highly costeffective emissions reductions from 

non-EGU boilers and turbines. 

A number of commenters believe EPA 

should determine that emissions 

reductions from non-EGUs should be 

taken into account in establishing 

emission requirements because, they 

believe, highly cost-effective controls 

are available for these sources. These 

commenters argued that highly costeffective controls are available for these 

sources and that EPA should have 

sufficient emissions and control cost 

information because the same sources 

were included in the NOX SIP Call. 

In addition, while it is true that these 

sources were included in the NOX SIP 

Call, EPA only addressed NOX

reductions from these sources. Neither 

SO2 reductions nor monitoring of SO2

emissions is required by the NOX SIP 

Call. As a result, for these sources, EPA 

has less reliable SO2 emissions data and 

very little information on the integration 

of NOX and SO2 controls. Although EPA 

has more information on NOX emissions 

from these sources because of the NOX

SIP Call (and other programs in the 

northeastern U.S.), the geographic 

coverage of the CAIR includes some 

States that were not included in the 

NOX SIP Call, some of which States 

contain significant amounts of industry. 

The EPA has even less emissions data 

from non-EGUs in these non-SIP call 

States affected by the CAIR. While EPA 

has incorporated State-submitted 

emissions inventory data for 1999 into 

its analysis for the CAIR, even this data 

is generally lacking information on fuel, 

sulfur content, and existing controls. 

Without this data, it is very difficult to 

assess the emission reduction 

opportunities available for non-EGU 

boilers and turbines. Furthermore, with 

regards to NOX, many non-EGU boilers 

and turbines are making reductions 

using low NOX burners (the control 

technology EPA assumed in making the 

cost-effectiveness determinations in the 

NOX SIP Call). Since these controls are 

operated year-round, annual emissions 

reductions are already being obtained 

from many of these units. Additional 

reductions would likely be less cost 

effective. 

Another commenter stated that nonEGU ‘‘major sources’’ are subject to the 

requirements of title V of the CAA and, 

therefore, EPA should have adequate 

emissions data provided as part of the 

sources’ permitting obligations. 

However, title V simply requires that a 

source’s permit include the substantive 

requirements (such as emission 

monitoring requirements) imposed by 

other sections of the CAA and does not 

itself impose any substantive 

requirements. Thus, the mere fact that a 

source is a major source required to 

have a title V permit does not mean that 

the source is monitoring and submitting 

emissions, fuel, and control device data. 

Many such sources do not, in fact, 

provide such data.

One commenter submitted cost 

information for FGD technology 

applications on industrial boilers. 

However, the information submitted by 

the commenter was based on the use of 

a limited number of technologies and 

for a limited number of boiler sizes. The 

EPA does not believe that the limited 

information demonstrates that SO2

emissions from these sources could be 

controlled in a highly cost-effective 

manner across the entire sector in 

question, or to what level the emissions 

could be controlled. 

Some commenters recommended 

including non-EGU boilers and turbines 

because in the future, after reductions 

from EGUs are made, the relative 

contribution of non-EGU boilers and 

turbines to the total NOX and SO2

emissions will increase. The EPA agrees 

that the relative contribution of nonEGUs to total NOX and SO2 emissions 

will increase in the future if States 

choose to meet their CAIR emissions 

reduction obligations solely by way of 

emission reductions made by EGUs. 

However, EPA does not believe that 

this, by itself, provides any basis for 

determining that in the context of this 

rule emissions reductions from nonEGUs should be determined to be highly 

cost-effective. As discussed above, EPA 

believes it is necessary to have more 

reliable emissions data and better 

control cost information for these 

sources before assuming reductions 

from them in the CAIR. The EPA is 

working to improve its inventory of 

emissions and control cost information 

for non-EGU boilers and turbines. 

Specifically, we are assessing the 

emission inventory submittals for 2002 

made by States in response to the 

relatively new requirements of 40 CFR 

part 51 (the Consolidated Emission 

Reporting Rule), and we will work with 

States whose submissions appear to 

have gaps in required data. We also note 

that EPA provides financial and 

technical support for the efforts of the 

five Regional Planning Organizations to 

coordinate among and assist States in 

improving emission inventories. 

Another commenter expressed 

concern that if the decision whether to 

control large industrial boilers is left to 

the States, the result may be inequitable 

treatment of EGUs on a State-by-State 

basis, particularly with respect to 

allowances, and therefore it would make 

sense to require NOX and SO2

reductions from large industrial boilers. 

Section 110 of the CAA leaves the 

ultimate choice of what sources to 

control to the States, and EPA cannot 

require States to control non-EGUs. 

Even if EPA had included reductions 

from non-EGUs in determining the total 

amount of reductions required under 

the CAIR, EPA could not have required 

any State to achieve those reductions 

through emission limitations on nonEGUs. 

The recent economic circumstances 

faced by the manufacturing sector 

accentuates EPA’s concerns about the 

lack of reliable emissions data and 

control information regarding nonEGUs. We note that the U.S. 

manufacturing sector was adversely 

affected by the latest business cycle 

slowdown. As noted in the 2004 

Economic Report of the President, the 

manufacturing sector was hit earlier, 

longer, and harder than other sectors of 

the economy. The 2004 Report also 

points out that, although manufacturing 

output has dropped much more than the 

real gross domestic product (GDP) 

during past business cycles, the latest 

recovery has been unusual because it 

has been weaker for the manufacturing 

sector than the recovery in the real GDP. 

The disparity across sectors (and even 

within individual sectors) in the 

economic condition of firms reinforces 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25215

EPA’s concerns about moving forward 

to consider emission controls on nonEGUs at this time. 

As explained elsewhere in this 

preamble, although the CAIR does not 

require that States achieve the required 

emissions reductions by controlling 

particular source categories, we expect 

that States will meet their CAIR 

obligations by requiring emissions 

reductions from EGUs because such 

reductions are highly cost effective. We 

believe the States are in the best 

position to make decisions regarding 

any additional control requirements for 

non-EGU sources. In making such 

decisions, States may take into 

consideration all relevant factors and 

information, such as differences across 

States in the need for control, 

differences in relative contribution of 

various sources, and differences in the 

operating and economic conditions 

across sources. 

c. Other Non-EGU Stationary Sources 

In the NPR and in the technical 

support document entitled 

‘‘Identification and Discussion of 

Sources of Regional Point Source NOX

and SO2 Emissions Other Than EGUs 

(January 2004),’’ EPA applied a similar 

rationale for non-EGU stationary sources 

other than boilers and turbines. For SO2, 

EPA noted that the emissions from such 

sources were a relatively small part of 

the emissions inventory, and we also 

noted the lack of information on costs. 

For NOX, we explained that more 

information was available than for SO2. 

This is because the NOX SIP Call 

included consideration of emissions 

control measures for internal 

combustion (IC) engines and cement 

kilns, and developed cost estimates for 

other NOX-emitting categories such as 

process heaters and glass 

manufacturing. However, we believed—

as for boilers and turbines, discussed 

above—that insufficient information on 

emission control options and costs, was 

available to apply these measures to the 

entire geographic area covered by the 

proposed rule.

No adverse comments were received 

suggesting inclusion of SO2 emissions 

reductions from non-EGU stationary 

sources other than boilers and turbines. 

Accordingly, EPA has determined not to 

consider SO2 reductions from these 

other non-EGU stationary sources. 

Several commenters suggested that 

EPA should have been able to consider 

NOX emissions reductions from nonEGU categories other than boilers and 

turbines, such as internal combustion 

(IC) engines and refinery fluid catalytic 

cracking units. These commenters 

believed such reductions were 

demonstrated to be cost effective, and 

questioned EPA’s assertion that 

insufficient information is available. 

Finally, some commenters believe EPA 

should have, at a minimum, required 

that controls for NOX SIP Call sources—

including large IC engines and cement 

kilns—should be extended from the 

ozone season to the entire year. 

We believe it likely that inclusion in 

today’s requirements of reductions from 

any highly cost-effective controls—if 

available—for these categories would 

have very small effects. First, most of 

the States included in the CAIR rule 

were also included in the NOX SIP Call, 

so that many of the emissions 

reductions that would be available from 

these sources have already occurred due 

to implementation of the NOX SIP Call. 

Second, in the States included in the 

CAIR rule, but which were not covered 

by the NOX SIP Call, only a small 

portion of NOX emissions come from 

cement kilns and IC engines compared 

to EGUs. Moreover, in some parts of this 

geographic area, in particular for Texas, 

many sources in these source categories 

are already regulated under ozone 

nonattainment plans (including SIPs for 

the Texas cities of Houston, Galveston, 

and Dallas). 

Regarding the commenters’

recommendation that extending NOX

SIP Call control requirements to a yearround basis for large IC engines and 

cement kilns should be considered to be 

highly cost effective, EPA believes that 

few emissions reductions would be 

achieved from doing so. The types of 

controls that were applied in the NOX

SIP Call States, while required to be in 

place only during the ozone season, 

will, as a practical matter, be applied on 

a year-round basis, whether or not so 

required by today’s rule. Most, if not all, 

of the NOX SIP Call States have 

developed regulations to control NOX

emissions from IC engines and cement 

kilns during the ozone season. The 

control of choice to meet these 

reductions from large lean burn IC 

engines is low emission combustion 

(LEC), which for retrofit applications is 

a substantial equipment modification of 

the engine’s combustion system. The 

engine will operate with LEC year round 

because this modification is a 

permanent change to the engine. Most, 

if not all, new large lean-burn IC engines 

have LEC. In addition, year-round 

emissions controls are already required 

for rich-burn engines greater than 500 

hp which will likely install nonselective 

catalyst reduction to comply with the 

recently adopted hazardous air 

pollutant standards (see final rule for 

reciprocating IC engines, 69 FR 33474, 

June 15, 2004). For cement kilns, the 

controls of choice are low NOX burners 

and mid-kiln firing. Low NOX burners 

(LNB) are a permanent part of the kiln, 

so that the kiln will operate year-round 

with LNB. Mid-kiln firing is a kiln 

modification for which a solid and slow 

burning fuel (typically tires) is injected 

in the mid-kiln area. Due to tipping fees 

and fuel credits, mid-kiln firing results 

in an operating cost savings. After this 

system is installed, year-round 

operation is expected. 

C. Schedule for Implementing SO2 and 

NOX Emissions Reduction Requirements 

for PM2.5 and Ozone 

1. Overview 

In the NPR, EPA proposed a twophased schedule for implementing the 

CAIR annual emission reduction 

requirements: implementation of the 

first phase would be required by January 

1, 2010 (covering 2010–2014), and that 

for the second phase by January 1, 2015 

(covering after 2014). The EPA based its 

proposal on its analysis of engineering, 

financial, and other factors that affect 

the timing for installing the emission 

controls that would be most costeffective—and are therefore the most 

likely to be adopted—for States to meet 

the CAIR requirements. Those air 

pollution controls are primarily 

retrofitted FGD systems (i.e., scrubbers) 

for SO2 and SCR systems for NOX on 

coal-fired power plants. 

The EPA’s projections showed a 

significant number of affected sources 

installing these controls. The proposed 

two-phased schedule allowed the 

implementation of as much of the 

controls as feasible by an early date, 

with a later time for the remaining 

controls. 

The EPA received detailed, technical 

comments from commenters who 

argued that the controls could not be 

implemented until later than proposed, 

and from other commenters who argued 

that the controls could be implemented 

sooner than proposed. The EPA has 

reviewed the comments and has 

conducted additional research and 

analyses to verify availability of 

adequate industrial resources, including 

boilermakers, for constructing the 

emission control retrofits required by 

CAIR. These analyses are based on 

conservative assumptions, including 

those suggested by the commenters, to 

ensure that the requirements imposed 

by CAIR do not result in shortages of the 

required resources that could 

substantially increase construction costs 

for pollution controls and reduce the 

cost effectiveness of this program. 

Today, EPA is taking final action to 

require the annual emissions reductions 

25216 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

71The NOX SIP Call Rule allowed approximately 

31⁄2 years for implementation of all NOX Controls.

on the same two-phase schedule as 

proposed. However, the requirements 

for the first phase include two separate 

compliance deadlines: Implementation 

of NOX reductions are required by 

January 1, 2009 (covering 2009–2014) 

and for SO2 reductions by January 1, 

2010 (covering 2010–2014). The 

compliance deadline requirements for 

the second phase are the same as 

proposed. The EPA believes that its 

action is consistent with the Agency’s 

obligations under the CAA to require 

emission reductions for obtaining 

NAAQS to be achieved as soon as 

practicable. The EPA applied the same 

criterion in implementing the NOX SIP 

Call, which was based on a singlephased schedule.71

2. Engineering Factors Affecting Timing 

for Control Retrofits 

a. NPR

In the NPR, EPA identified the 

availability of boilermakers as an 

important constraint for the installation 

of significant amounts of SCR and FGD 

retrofits. Boilermakers are skilled 

laborers that perform various 

specialized construction activities, 

including welding and rigging, for 

boilers and high pressure vessels. The 

air pollution control devices, such as 

scrubber and SCR vessels, require 

boilermakers for their construction. 

Apprentices with no prior work-related 

experience complete a four-year training 

program, to become full boilermakers. 

For apprentices with relevant 

experience, this training period could be 

shorter. For example, union members 

representing the shipbuilding trade 

could be expedited into the boilermaker 

division within a year. 

The boilermaker constraint was 

considered more important for the 

initiation of the first phase of CAIR, 

since the NOX SIP Call experience had 

shown that many sources would be 

adverse to committing significant funds 

to install controls until after SIPs were 

finalized. With the States required to 

finalize SIPs in 18 months after the 

signing of the final rule, the sources 

would have three years in which to 

complete purchasing, construction, and 

startup activities associated with these 

controls, to meet the proposed CAIR 

deadline. 

The EPA’s projections showed power 

plants installing 51.4 gigawatts (GW) of 

FGD and 28.2 GW of SCR retrofits 

during the first CAIR phase. These 

projections include retrofits for CAIR as 

well as retrofits for base case policies 

(i.e., retrofits for existing regulatory 

requirements). We estimated the total 

boilermaker-years required for installing 

these controls at 12,700, which was 

based on the boilermakers being utilized 

over a period of 18 months during the 

installation process. Also, based on the 

projected boilermaker population in the 

timeframe relevant to the installation of 

these controls, we estimated that 14,700 

boilermaker-years were available over 

the same 18-month period. The 

availability of approximately 15 percent 

more boilermaker-years than required, 

as shown by these estimates, confirms 

the adequacy of this critical resource for 

CAIR and EPA assumed this to be a 

reasonable contingency factor. 

The EPA also determined that 

installation of the projected amounts of 

FGD and SCR retrofits could be 

completed within the three-year period 

available for CAIR. This determination 

was based on a previous report prepared 

by EPA for the proposed Clear Skies 

Act, ‘‘Engineering and Economic Factors 

Affecting the Installation of Control 

Technologies for Multi-Pollutant 

Strategies,’’ (docket no. OAR–2003–

0053–0106). According to this report, an 

average of 21 months are required to 

install SCR on one unit, and 27 months 

to install a scrubber on one unit. For 

multiple units within the same plant, 

installation of controls would normally 

be staggered to avoid operational 

disruptions. The EPA projected that the 

maximum number of multiple-unit 

controls required for each affected 

facility could all be installed within 

three years.The NPR proposal included 

a second phase, with a compliance 

deadline of January 1, 2015. The EPA’s 

projections showed power plants 

installing 19.1 GW of FGD and 31.7 GW 

of SCR retrofits by 2015, which 

included retrofits for CAIR as well as 

retrofits for base case policies (i.e., 

retrofits for existing regulatory 

requirements). Availability of 

boilermaker labor was not an important 

constraint for this phase. 

b. Comments 

The EPA received several comments 

relating to the requirements for the twophased implementation program, the 

emission caps and compliance deadline 

for each phase, and resources required 

to install necessary controls. The 

commenters offered opposing 

viewpoints, which can be broadly 

categorized as follows. 

Several commenters indicated that the 

compliance deadline of 2010 for the first 

phase was not attainable and argued 

that EPA should either extend the 

deadline, or set higher emission caps for 

this phase. The commenters raised the 

following specific points in support of 

their concerns: 

• The time allowed for completing 

various activities from planning to 

startup of the required controls was not 

sufficient. Other related activities, 

including project financing and 

obtaining a landfill permit for the 

scrubber waste, could also require more 

time than what the rule allowed. In 

addition, the short implementation 

period would require simultaneous 

outages of too many units to tie the new 

equipment into the existing systems, 

which would affect the reliability of the 

electrical grid. 

• Implementation of controls to the 

required large number of units would 

cause shortages in the supply of critical 

industrial resources, especially 

boilermakers. An analysis performed by 

a commenter showed a shortfall in the 

supply of boilermaker labor during the 

construction period relevant to CAIR 

retrofits. This commenter anticipated 

that certain key variables would be 

greater in value than those used by EPA 

and based their analysis on higher SCR 

prices, EIA-projected higher natural gas 

prices and electricity demand factors, 

and more stringent boilermaker duty 

rates (boilermaker-year/MW) and 

availability factors.

Commenters who favored more 

stringent compliance deadlines argued 

that the required controls could be 

installed in less time and more controls 

could be built in early years. These 

commenters raised the following 

specific points in support of their 

concerns. 

• The compliance deadlines for the 

two phases did not support the ozone 

and fine particulate (PM2.5) attainment 

dates mandated by the CAA. The Phase 

I deadline should be accelerated to meet 

these attainment dates. Sufficient 

industrial resources, including 

boilermakers, would be available to 

support such an acceleration. While 

some commenters supported an earlier 

Phase I deadline of January 1, 2008, the 

others supported a deadline of January 

1, 2009. Some of these commenters also 

suggested that the Phase I deadline be 

accelerated only for NOX. 

• The EPA’s estimates for the 

boilermaker availability were too 

conservative. A boilermaker labor 

analysis performed by one commenter 

showed an adequate supply of this 

resource to support installation of all 

Phase I and II controls by the start of the 

first phase (by 2010), thereby 

eliminating the need for two phases. 

• The time allowed for installing 

controls for Phase II was excessive. The 

initiation of this phase could be moved 

forward. 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25217

Several commenters supported EPA’s 

assumptions used in support of the 

adequacy of the implementation period 

and resources to build the required 

CAIR controls. These assumptions 

included the overall construction 

schedule durations for SCR and FGD 

systems and boilermaker unit rates. 

c. Responses 

The EPA reviewed the above 

comments and performed additional 

research and analyses, including new 

IPM runs that incorporated higher SCR 

and natural gas costs and greater electric 

demand. We also found that more units 

had installed SCR under the NOX SIP 

Call and other regulatory actions than 

what our records previously showed. 

This increase in the number of existing 

SCR installations was also incorporated 

into these IPM runs. In addition, the 

number of existing FGD installations 

was also revised slightly downward, for 

the same reason. 

The revised IPM analyses for today’s 

final action show that the amounts of 

controls that need to be put on for Phase 

I are 39.6 GW of FGD and 23.9 GW of 

SCR. These amounts represent a 

reduction from the estimates for the 

NPR. For Phase II, the amount of the 

required controls are 32.4 GW of FGD 

and 26.6 GW of SCR. These amounts 

represent an increase from the estimates 

for the NPR. The amounts shown for 

both phases reflect all retrofits required 

for the CAIR and base case (non-CAIR) 

policies. The retrofit projections for the 

base case policies are included, since 

some of the available boilermaker labor 

would be consumed in building these 

retrofits during the CAIR time-frame. 

The EPA also contacted the 

International Brotherhood of 

Boilermakers (IBB), U.S. Bureau of 

Labor Statistics (BLS), and National 

Association of Construction Boilermaker 

Employers (NACBE) to verify its 

assumptions on boilermakers 

population, percentage of boilermakers 

available to work on the control retrofit 

projects, and average annual hours of 

boilermaker employment. Except for the 

boilermaker population, the information 

received as a result of these 

investigations validated EPA’s 

assumptions. IBB also confirmed that 

the boilermaker population would at 

least be maintained at the current level 

of 26,000 members, during the period 

relevant to construction of CAIR 

retrofits. It did not want to forecast 

growth and historically has not done so. 

Therefore, instead of the 28,000 

boilermaker forecasted population used 

in the NPR, we have conservatively 

used a boilermaker population of 26,000 

for the final CAIR. A detailed discussion 

on these assumptions and the 

information received from these sources 

is available in the docket to this 

rulemaking as a technical support 

document (TSD), entitled ‘‘Boilermaker 

Labor and Installation Timing Analysis, 

(docket no. OAR–2003–0053–2092).’’

The responses to the most significant 

comments on these issues are 

summarized in the following sections. 

i. Issues Related to Compliance 

Deadline Extension 

(I) Adequacy of Phase I Implementation 

Period 

Today’s action initiates State 

activities in conjunction with EPA to set 

up the administrative details of CAIR. 

With the first phase compliance 

deadline of January 1, 2009, for NOX

and January 1, 2010, for SO2, the 

affected sources would have 

approximately 33⁄4 and 43⁄4 years for the 

implementation of the overall 

requirements for this phase, 

respectively. The final SIPs would be 

submitted at the end of the first 18 

months of these implementation 

periods. The remaining 21⁄4 and 31⁄4

years would be available for the sources 

to complete activities required for the 

procurement and installation of NOX

and SO2 controls, respectively. For the 

reasons outlined below, EPA believes 

that these deadlines provide enough 

time to install the required Phase I 

controls. 

(A) Engineering/Construction 

Schedule Issues

The EPA notes that, for CAIR, the 

States would finalize the SIPs in 18 

months after the rule is signed, and that 

until then, the majority of sources 

required to install controls may not 

initiate activities that require 

commitment of major funds. However, 

some activities, such as planning, 

preparation of conceptual designs, 

selection of technologies, and contacts 

with equipment suppliers can be started 

or completed prior to the finalization of 

SIPs, at least for major sources expected 

to require longer implementation 

periods. In addition, other activities, 

such as permitting and financing can be 

started after the rule is finalized. This is 

based on the NOX SIP Call experience. 

After the SIPs are finalized, the 

sources would have approximately 21⁄4

and 31⁄4 years in which to complete 

purchasing, detailed design, fabrication, 

construction, and startup of the required 

NOX and SO2 controls, respectively. 

This assumes that activities, such as 

planning and selection of technologies, 

have already been started or completed, 

prior to the start of these 21⁄4- and 31⁄4-

year periods. As discussed in the NPR 

proposal, EPA projects an average 

single-unit installation time of 21 

months for SCR and 27 months for a 

scrubber. Our revised IPM analysis for 

the final rule shows that many facilities 

would install controls on multiple units 

(a maximum of six for SCR and five for 

FGD) at the same plant. We expect these 

facilities to stagger these installations to 

minimize operational disruptions. 

The EPA also projects that SCRs and 

scrubbers could be installed on the 

multiple units in the available time 

periods of 21⁄4 and 31⁄4 years, 

respectively. The issues related to the 

availability of boilermakers and the 

ability of the plants requiring multipleunit controls to stagger their 

installations during these periods are 

discussed later in this preamble. 

As compared to projections in the 

NPR proposal, earlier signing of the 

final rule adds approximately three 

additional months to the overall 

implementation periods for SO2

controls. Furthermore, EPA’s 

projections for the final rule show fewer 

Phase I NOX and SO2 controls being 

added than the projections in the NPR 

proposal. Since the compliance 

deadline for NOX has been moved up a 

year from the proposal, a three-month 

earlier rule promulgation provides more 

time for implementing SO2 controls 

only. However, since it does allow use 

of critical resources, such as 

boilermakers, for SO2 controls to be 

spread over a longer period of time, the 

net effect would be to make more of 

these resources available for both SO2

and NOX controls (as compared to a 

scenario where promulgation was not 

three months earlier). This is especially 

true since the implementation periods 

for both NOX and SO2 controls would 

start at the same time and the plants 

installing these controls would be 

competing for the same resources until 

January 1, 2009, the compliance 

deadline for NOX. The EPA, therefore, 

believes that 21⁄4- and 31⁄4-year time 

periods provide reasonable amounts of 

time from the approval of State 

programs by September 2006, until the 

commencement of compliance 

deadlines for meeting the NOX and SO2

emission requirements. 

Certain commenters have provided 

their own estimates of schedule 

requirements for installing the required 

controls. In some cases, these estimates 

are longer than those determined by 

EPA. For scrubbers, including spray 

dryer and wet limestone or lime type 

systems, the control implementation 

requirements provided by the 

commenters range from 30 to 54 months 

for the overall project and 18 to 36 

months for the phase following 

25218 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

72Reference: Announcement by Wheelabrator Air 

Pollution Control Inc. for award of a wet limestone 

scrubber system for K.C. Coleman Generating 

Station, Western Kentucky Energy Corp., August 2, 

2004, and other related documents. (docket no. 

OAR–2003–0053–1953)

73Summary of telephone calls with States to 

discuss landfill permit timing (docket no. OAR–

2003–0053–1927).

74Reference: ‘‘NERC, Generating Availability Data 

System: All MW Sizes—Coal-Fired Generation 

Report,’’ http://www.nerc.com/∼filez/gar.html,

October 17, 2003.

equipment awards. In this case, the 

lowest 18-month schedule requirement 

cited applies to spray dryers, whereas 

the shortest schedule cited for wet 

scrubbers for the activities following the 

equipment awards is 24 months. For 

SCR, the control implementation 

requirements cited by the commenters 

range from 24 to 36 months for the 

overall project and 17 to 25 months for 

the phase following the equipment 

awards.

One commenter has pointed out that 

the construction schedule requirements 

for the FGD and SCR retrofit projects 

have shortened, because of the lessons 

learned from a significant number of 

such projects completed during the last 

few years. The EPA notes that a recent 

announcement for a new 485 MW 

limestone scrubber facility indicates a 

construction schedule duration (from 

equipment award to startup) of only 18 

months.72 This is well below the 

schedule requirement cited by the 

commenters for a wet limestone 

scrubber.

The EPA also notes that most of the 

commenters’ schedule estimates are 

consistent with the time periods 

available for completing the CAIRrelated NOX and SO2 projects. Some of 

the longer schedules submitted by 

commenters would exceed the CAIR 

Phase I dates. However, EPA considers 

these longer schedules to be speculative, 

as these commenters did not justify 

them. The major factors that influence 

schedule requirements include size of 

the installation, degree of retrofit 

difficulty, and plant location. The EPA 

does not expect these factors to make a 

difference of more than a few months 

between the schedule requirements of 

various installations. The commenters 

who have cited long schedule 

requirements that fall at the higher end 

of the above ranges have not provided 

any data to support the wide differences 

between their schedules and those 

proposed by others, including EPA. It 

should also be noted that EPA’s 

schedules are based on information 

from several actual SCR and scrubber 

installations. Therefore, EPA cannot 

accept the excessive schedule 

requirements proposed by these 

commenters. 

(B) Landfill Permit Issue 

The EPA contacted several key States 

requiring FGD retrofits, to investigate 

the amount of time required to obtain a 

landfill permit for scrubber waste. We 

note that not all scrubber installations 

would require landfills, as some 

scrubber designs produce saleable waste 

products, such as gypsum. 

Specifically, EPA contacted Georgia, 

Ohio, Indiana, Alabama, Pennsylvania, 

West Virginia, Tennessee, and 

Kentucky.73 Except for Kentucky, all 

States indicated that their permit 

approval periods ranged from 12 to 27 

months. Some of these States indicated 

that permit approval may require more 

time than 27 months, but only for the 

cases in which major landfill design 

issues persist or the permit applicant 

has not provided complete and proper 

information with the permit application.

The Kentucky Department of 

Environmental Protection indicated 

that, based on their historical records, 

the average permit approval period was 

31⁄2 years. They also stated that the State 

was sensitive to an applicant’s time 

restrictions and the permit approval 

times had varied depending on the level 

of urgency surrounding a permit 

application. They further confirmed that 

they would work with the industry to 

meet compliance deadlines, such as 

those required by CAIR, as efficiently as 

possible. 

Based on the above investigations, 

EPA notes that the landfill permitting 

requirements quoted by all States fall 

well within the 43⁄4-year 

implementation period for Phase I. Also, 

landfill permitting activities as well as 

its design and construction can be 

accomplished, independent of the 

design and construction of the FGD 

system. The EPA, therefore, believes 

that landfill permitting is not a 

constraint for compliance with the rule. 

(C) Project Financing Issue 

Commenters representing small units 

or units owned by the co-operatives 

raised concerns that arrangement of 

financing for control retrofits could take 

long periods of time. However, EPA’s 

projections show a larger portion of the 

smaller units installing controls only 

during the second phase. These 

projections also show that only a few 

co-operative units would require 

installation of controls. Therefore, EPA 

believes that the Phase I implementation 

periods of approximately 33⁄4 and 43⁄4

years for NOX and SO2 controls, 

respectively, provide enough time for 

completing the financing activity for all 

controls. Of course, if individual 

sources face difficulties in meeting 

deadlines to implement controls, they 

may use the allowance-trading 

provisions of CAIR to defer 

implementation of controls. 

(D) Electrical Grid Reliability Issue 

Based on available data for the NOX

SIP Call, approximately 68 GW of SCR 

retrofits were started up during the 

years from 2001 to 2003. This included 

approximately 42 GW of SCRs in 2003 

alone, which exceeds the combined 

capacity of SCR and FGD retrofits for 

CAIR that we expect to be started up in 

any one year. The EPA projects that 

startup of the 23.9 GW of SCR and 39.6 

GW of FGD capacity required for Phase 

I would be spread over a period of two 

years (2008 and 2009). The total 

capacity of units starting up in each year 

is therefore expected to be 

approximately 32 GW (half of the 

combined SCR and FGD capacity of 63.5 

GW).

The NOX SIP Call experience shows 

that outages required to complete 

installation of the large SCR capacity, 

especially during 2003, did not have an 

adverse impact on the electrical grid 

reliability. The EPA notes that the 

outage requirement for SCR usually 

exceeds that for scrubbers, since SCR is 

located closer to the boiler and it may 

be more intrusive to the existing 

equipment. As shown above, the CAIR 

retrofits are projected to include more 

scrubbers than SCRs and the capacity of 

these retrofits starting up in any one 

year is below the capacity of the NOX

SIP Call units that started up in 2003. 

Therefore, the overall outage 

requirement for CAIR would be less 

than that experienced for the NOX SIP 

Call. 

Based on published industry data, the 

planned outage times for coal-fired units 

from 2001–2002 (SCR buildup years) 

decreased by over two percent 

compared to the previous two years 

from 1998–1999.74 The reduction in the 

overall outage time in the 2001–2002 

period also shows that the SCR retrofits 

did not adversely affect the grid 

reliability. Therefore, EPA believes that 

the concern regarding electrical grid 

reliability is unwarranted for CAIR 

retrofits.

(II) Availability of Boilermaker Labor in 

Phase I 

The EPA has performed several 

analyses to verify the adequacy of the 

available boilermaker labor for the 

installation of CAIR’s Phase I controls. 

These analyses were not just based on 

using EPA’s assumptions for the key 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25219

factors affecting the boilermaker 

availability, but also the assumptions 

suggested by commenters for these 

factors to determine how sure we could 

be on our key conclusions. If there was 

insufficient labor for the amount of air 

pollution controls that will need to be 

installed, the program would be in 

jeopardy. For instance, shortages in 

manpower could lead to high wage rates 

that could substantially increase 

construction costs for pollution controls 

and reduce the cost effectiveness of this 

program. During the peak of the NOX

SIP Call SCR construction period, the 

power industry did experience an 

increase in the SCR construction costs. 

One of the reasons cited for these higher 

costs was an increased demand for 

boilermaker labor. The EPA strongly 

wanted to avoid this possibility for 

CAIR. The EPA also wanted to be very 

sure that the levels of controls and 

timing of the program’s start were 

appropriate. Therefore, EPA tended to 

make conservative assumptions and to 

test the sensitivity of key assumptions 

that were uncertain. 

Boilermakers population, percentage 

of boilermakers available to work on the 

control retrofit projects, and average 

annual hours of boilermaker 

employment are some of the key factors 

that affect boilermaker availability. As 

discussed previously, EPA’s 

assumptions on these factors were 

validated or revised through our 

discussions with IBB, BLS, and NACBE. 

Two other key factors that also have 

an impact on boilermaker availability 

include the number of required SCR and 

FGD retrofits and boilermaker duty rates 

(boilermaker-year/MW, i.e., the number 

of boilermaker years needed to install 

SCR or FGD on one MW of electric 

generation capacity). The EPA’s 

projections for the required SCR and 

FGD retrofits are based on the IPM 

analyses performed for the final rule. 

The basis for the boilermaker duty rates 

used by EPA is a report prepared by 

EPA for the proposed Clear Skies Act, 

‘‘Engineering and Economic Factors 

Affecting the Installation of Control 

Technologies for Multi-Pollutant 

Strategies.’’

Some commenters have suggested use 

of EIA’s projections of natural gas prices 

and electricity demand rates that are 

higher than EPA’s projections used in 

the IPM analyses. Use of higher values 

for these parameters would increase the 

number of required control retrofits. 

While not agreeing with these 

commenters that EIA’s projections 

should replace the data that EPA uses, 

we acknowledge that there is reasonable 

uncertainty concerning these 

assumptions and that addressing the 

uncertainty explicitly by considering 

EIA’s alternative assumptions is 

prudent, given the importance of having 

sufficient labor resources to meet the 

program’s requirements in 2010. 

Therefore, EPA has performed a 

sensitivity analysis to determine the 

required control retrofits resulting from 

the use of these EIA projections, and 

then used the increased amounts of the 

required control retrofits to determine 

their impacts on the boilermaker 

availability. 

The EPA also received comments 

suggesting that the SCR costs used in 

our IPM analyses were below the levels 

experienced in recent SCR installations. 

We note that the SCR costs were revised 

in the IPM analyses performed for the 

final rule, to reflect recent industry 

experience. One commenter reported 

SCR capital costs that exceeded our 

revised costs. The EPA does not agree 

with these reported costs, as they are 

not supported by the overall cost data 

submitted by the commenter. However, 

to address the concern with the SCR 

costs in general, we have performed a 

sensitivity analysis to determine the 

impact of increasing the SCR capital and 

fixed O&M costs by 30 percent.

An increase in the SCR costs would 

affect the amounts of the required 

control retrofits. Table IV–12 shows the 

projected Phase I SCR and FGD retrofits 

for the above two alternate cases, based 

on using EIA’s projections for natural 

gas prices and electricity demand rates 

and higher SCR costs.

TABLE IV–12.—IPM PROJECTIONS FOR TOTAL CAPACITIES OF FGD AND SCR RETROFIT PROJECTS FOR COAL-FIRED

ELECTRIC GENERATION UNITS FOR CAIR PHASE I USING EPA AND COMMENTER ASSUMPTIONS

Retrofit type EPA base case 

assumptions 

EIA

projections 1

EIA projections 

and higher SCR 

costs 2

CAIR FGD, GW ...................................................................................................................... 37 45.4 47.9 

Non-CAIR FGD, GW .............................................................................................................. 2.6 3.7 Included Above 

CAIR SCR, GW ...................................................................................................................... 18.2 20.6 25.2 

Non-CAIR SCR, GW .............................................................................................................. 5.7 4.6 Included Above 

1The required control retrofits shown are based on using EIA projections for natural gas prices and electricity demand rates. 

2The required control retrofits shown are based on using EIA projections for natural gas prices and electricity demand rates as well as 30 percent higher SCR capital and fixed O&M costs. 

As shown in Table IV–12 above, the 

alternate case using just the EIA’s 

projections for natural gas prices and 

electricity demand rates requires the 

largest amounts of control retrofits. 

Therefore, a boilermaker availability 

analysis was performed for just this 

case. 

One commenter has suggested use of 

higher boilermaker duty rates for both 

SCR and FGD retrofits, based on an 

industry survey they had conducted. 

Use of higher duty rates would result in 

more boilermakers being needed to 

install the controls. Table IV–13 shows 

the boilermaker duty rates used by EPA 

as well as those suggested by this 

commenter.

TABLE IV–13.—BOILERMAKER DUTY

RATES FOR SCR AND FGD SYSTEMS FOR COAL-FIRED ELECTRIC

GENERATION UNITS

Source FGD SCR 

EPA’s estimate, boilermaker-year/MW ............. 0.152 0.175 

TABLE IV–13.—BOILERMAKER DUTY

RATES FOR SCR AND FGD SYSTEMS FOR COAL-FIRED ELECTRIC

GENERATION UNITS—Continued

Source FGD SCR 

Commenter-suggested, 

boilermaker-year/MW 1 .. 0.269 0.343 

1The duty rate values shown are average 

values calculated by using the FGD and SCR 

correlations provided by the commenter along 

with the MW size of individual units projected 

by the IPM to require FGD or SCR controls for 

Phase I of CAIR. 

25220 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

75Reference: ‘‘Email from Institute of Clean Air 

Companies,’’ September 15, 2004 (See Appendix B, 

Boilermaker Labor Analysis and Installation 

Timing).

76Reference: ‘‘Annual Energy Outlook 2005 

(Early Release), Tables A9 and 9,’’ December 2004, 

http://www.eia.doe.gov/oiaf/aeo/index.html.

77TSD, ‘‘Boilermaker Labor and Installation 

Timing Analysis,’’ (Docket no. OAR–2003–0053–

2092).

Our review of the limited supporting 

information submitted by the 

commenter about their survey for these 

duty rates shows that they are based on 

data from a small number of 

installations and represent scope of 

work at each power plant that is well 

above the average installation 

conditions used in determining the duty 

rates used by EPA. Therefore, EPA 

considers these commenter-suggested 

duty rates to represent the upper end of 

the range of values that would be 

expected for the SCR and FGD controls 

under consideration. This is also 

supported by the average duty rate 

(0.199) submitted by one other 

commenter for installing FGDs, which is 

well below the average duty rate (0.269) 

suggested by the first commenter. 

However, EPA also notes that the duty 

rate suggested by the second commenter 

is higher than that (0.152) used by EPA. 

The EPA conducted the boilermaker 

analysis for the final rule using 

alternative assumptions for boilermaker 

duty rates. These alternative 

assumptions yield a range of estimates 

of the amount of control that could 

feasibly be installed. In keeping with 

EPA’s desire to be very sure that there 

is sufficient boilermaker labor available 

during the CAIR’s Phase I construction 

period, the Agency has considered the 

most stringent duty rates suggested by 

the first commenter, as well as other 

duty rates (see Table IV–13), in 

analyzing the impact on the boilermaker 

availability. The EPA considers this to 

be a bounding analysis in which the 

estimates based on the most stringent 

duty rates reflect conditions with the 

highest retrofit difficulty level that EPA 

could realistically expect to occur. We 

expect that the average boilermaker duty 

rates applicable to the overall boiler 

population required to retrofit controls 

under this rule would not fall outside of 

the values used by EPA and those 

suggested by the first commenter.

In the NPR, only the union 

boilermakers belonging to the IBB were 

considered in the EPA’s availability 

analysis. Some commenters have 

pointed out that additional sources of 

boilermakers will be available for CAIR. 

Two such sources include non-union 

and Canadian boilermakers. IBB has 

confirmed that 1,325 Canadian 

boilermakers were brought in to support 

the NOX SIP Call SCR work in 2003. The 

EPA also projects that approximately 15 

percent of FGDs and 43 percent of SCRs 

will be installed for Phase I in the 

traditionally non-union States and 

believes there will be nonunion labor 

available in these States. One source has 

confirmed that a substantial amount of 

SCR retrofit work during the 2000–2002 

period was executed by non-union 

labor.75 Based on these data, we have 

conservatively assumed that 1,000 

boilermakers from Canada will be 

available and 10 percent of the retrofits 

would be installed by non-union 

boilermakers for Phase I.

Based on EPA data, an average 32 GW 

of new gas-fired, combined cycle 

generating capacity was being added 

annually, during the NOX SIP Call SCR 

construction years of 2002 and 2003. A 

substantial number of boilermakers 

were involved in the construction of 

these gas-fired projects. Since 

projections for the timeframe relevant to 

CAIR retrofits show only a small 

amount of new electric generating 

capacity being added, the number of 

boilermakers involved in the building of 

new plants would be smaller and more 

of the boilermaker population would be 

available to work on the Phase I 

retrofits. As pointed out by one 

commenter, the boilermakers available 

due to this projected drop in the 

building of new generation capacity 

represents a third additional source of 

boilermakers for CAIR. 

The EPA projects only an 

insignificant amount of new coal-fired 

generating capacity being added during 

Phase I. The most recent EIA’s 

projections also do not show any new 

coal fired capacity being added between 

2007 and 2010, the timeframe relevant 

to boilermaker-related construction 

activities for CAIR.76 However, EPA’s 

projections do show approximately 15 

GW of new or repowered gas-fired 

capacity being added, during 2007–

2010. The EIA’s projections for new gasfired capacity addition during Phase I 

are well below those of EPA’s. We used 

the more conservative EPA projections 

for new generating capacity additions 

and the gas-fired capacity additions 

during the NOX SIP Call period to 

estimate the additional boilermaker 

labor that would become available for 

the Phase I retrofits. This estimate 

shows that approximately 28 percent 

more boilermakers would be available to 

work on the CAIR retrofits, because of 

a slowdown in the construction of new 

power plants.77

In the boilermaker availability 

analyses performed by EPA, the 

required boilermaker-years were 

determined for each case, based on the 

amounts of SCR and FGD retrofits being 

installed and the pertinent boilermaker 

availability factors and duty rates. The 

required boilermaker-years were then 

compared to the available boilermaker 

years to verify adequacy of the 

boilermaker labor. All sources of 

boilermakers were considered in these 

analyses, including the union 

boilermakers and the boilermakers from 

the three additional sources discussed 

previously. 

The EPA’s boilermaker availability 

analyses firmly support CAIR’s Phase I 

requirements. Using EPA’s projections 

of FGD and SCR retrofits installed for 

Phase I and EPA’s assumptions for 

boilermaker duty rates, there are ample 

boilermakers available with a large 

contingency factor to support the 

predicted levels of CAIR retrofits. For 

the most conservative analysis using the 

boilermaker duty rates suggested by one 

commenter and the EIA’s projections for 

natural gas prices and electricity 

demand rates, there are sufficient 

boilermakers available with a 

contingency factor of approximately 14 

percent.

In the NPR proposal, EPA estimated 

that a contingency factor of 15 percent 

was available to offset any increases in 

boilermaker requirements due to 

unforeseen events, such as sick leave, 

time lost due to inclement weather, time 

lost due to travel between job-sites, 

inefficiencies created due to project 

scheduling issues, etc. The EPA had 

considered this 15 percent contingency 

factor to be adequate for these 

unforeseen events. We also note that 

EPA did not receive any comments 

suggesting a need for a higher 

contingency factor. 

The EPA also notes that the above 

boilermaker labor estimates have not 

considered the benefits of the 

experiences gained by the U.S. 

construction industry from the recent 

buildup of large amounts of air 

pollution controls, including the NOX

SIP Call SCRs. As pointed out by one 

commenter, such experiences include 

use of modular construction, which can 

result in a significant reduction in the 

required boilermaker labor for CAIR 

retrofits. Also, as a result of this controls 

buildup, an increased number of 

experienced designers and construction 

personnel have become available to the 

industry. Some of these benefits may be 

offset by factors, such as the increased 

level of retrofit difficulty expected for 

the CAIR retrofits, especially for the 

small size units. However, we believe 

that the net effect of this experience is 

a more efficient use of the boilermaker 

labor in the construction of the air 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25221

pollution control retrofits projects. 

Unfortunately, EPA cannot quantify the 

value of this experience in determining 

its overall impact on boilermaker 

requirements. 

Therefore, EPA considers the 14 

percent contingency in the available 

boilermaker-years for the above 

bounding analysis using commentersuggested assumptions to be adequate. 

ii. Issues Related to Compliance 

Deadline Acceleration 

(I) Acceleration of Phase I Compliance 

Deadline 

As a result of EPA’s review of the 

comments received and further 

investigations conducted by the Agency 

for the final rule, the compliance 

deadline for implementing Phase I NOX

controls has been moved up by one 

year. We believe that the affected plants 

would have sufficient time with this 

change to meet the CAIR requirements 

associated with NOX emissions, as long 

as the compliance deadline for 

implementing SO2 controls is not 

changed. The EPA does not agree that 

accelerating the originally proposed 

Phase I compliance deadline of January 

1, 2010, for implementing both NOX and 

SO2 controls is possible. These issues 

are discussed below. 

(A) Two-Year Phase I Acceleration for 

NOX and SO2 Controls 

With today’s final action and allowing 

18 months for the SIPs, sources 

installing controls would have 

approximately 31⁄4 years for 

implementing the rule’s requirements. 

Some commenters suggested moving 

Phase I forward by 2 years, with a new 

compliance deadline of January 1, 2008, 

which would reduce the 

implementation period to 11⁄4 years. It is 

recognized that sources generally would 

not initiate any implementation 

activities that require major funding, 

before the final SIPs are available. 

The EPA’s projections show that, for 

SCR installation on one unit, an average 

21-month schedule is required to 

complete purchasing, construction, and 

startup activities. For the same activities 

for FGD, an average 27-month schedule 

is required. As can be seen, the total 

time required for just one SCR or FGD 

installation exceeds the 11⁄4-year 

implementation period available for 

Phase I, if the compliance deadline is 

moved to January 1, 2008. 

(B) One-Year Phase I Acceleration for 

NOX and SO2 Controls 

If the Phase I compliance deadline for 

both NOX and SO2 controls is moved up 

by 1 year, the affected facilities would 

have 21⁄4 years or 27 months to complete 

installation of these controls. As 

discussed in the preceding section, FGD 

installation on one unit requires an 

average 27-month schedule to complete 

purchasing, construction, and startup 

activities. 

The sources installing controls on 

more than one unit at the same facility 

would likely stagger the outage-related 

activities, such as final hookup of the 

new equipment into the existing plant 

settings and startup, to minimize 

operational disruptions and avoid losing 

too much generating capacity at one 

time. The EPA projects that an average 

2-month period is required to complete 

the outage construction activities and a 

1-month period to complete the startup 

activities for FGD. Therefore, if back-toback outages are assumed for a plant 

installing FGD on just two units, the 27 

months needed to install FGD on the 

first unit and an additional 3 months 

needed for outage activities on the 

second unit would result in an overall 

schedule requirement of 30 months. 

This 30-month schedule exceeds the 

available 27-month implementation 

period, if the compliance deadline is 

moved up by 1 year. For plants 

installing FGD controls on more than 

two units and performing hookup 

construction and startup activities in 

back-to-back outages, an additional 3 

months would be added to the 30-

month schedule requirement for each 

additional unit.

The EPA notes that certain plants 

installing multiple-unit controls may be 

able to meet the compliance deadline 

requirement by using alternative 

approaches, such as simultaneous unit 

outages and purchase of allowances to 

defer installation of controls on some 

units. However, our projections for the 

final rule show that some facilities 

would be installing FGD controls on five 

multiple units at a single site. Moreover, 

these projections show 26 plants 

requiring FGD retrofit on more than one 

unit, which represents a major portion 

of the total number of plants required to 

install such controls under CAIR. We 

believe it would not be appropriate to 

expect this number of plants to resort to 

alternative means to accommodate such 

installations, such as simultaneous unit 

outages or purchasing of allowances. 

For FGD retrofits, some plants would 

be required to obtain solid waste landfill 

permits. As discussed previously, the 

time required to obtain these permits 

could range from one to 31⁄2 years. With 

the compliance deadline moved up by 

one year, the overall implementation 

period would be reduced from 43⁄4 to 

33⁄4 years. For those plants subjected to 

a 31⁄2-year permit approval period, only 

3 months would be available to prepare 

the permit applications at the beginning 

of the compliance period and to prepare 

the landfill area for accepting the waste 

after permit approval. The EPA does not 

believe that 3 months is adequate for 

such activities. These plants would, 

therefore, need the 43⁄4-year 

implementation period to complete 

activities related to landfills associated 

with the FGD systems. 

The EPA also performed an analysis 

to verify if the available boilermaker 

labor is adequate to support the January 

1, 2009, compliance deadline for both 

NOX and SO2. This analysis was 

performed, using commenter-suggested 

boilermaker duty rates and EIA’s 

assumptions for the natural gas prices 

and electricity demand rates. The 

results show that given these 

assumptions sufficient number of 

boilermakers will not be available and 

that there will be a shortfall of 

approximately 32 percent in the 

boilermakers available to support Phase 

I activities for this case. 

Considering the constraints identified 

in the above analyses for the FGD 

installation schedule requirements and 

boilermaker labor availability, EPA 

believes that it is not reasonable to move 

the Phase I compliance deadline for 

both NOX and SO2 caps to January 1, 

2009. 

(C) One-Year Phase I Acceleration for 

NOX Controls Only 

A 1 year acceleration would result in 

a compliance deadline of January 1, 

2009, for installing Phase I NOX

controls. With this change, the affected 

sources installing these controls would 

have approximately 21⁄4 years for 

implementing the rule’s requirements, 

following the approval of State 

programs. However the implementation 

period for installing FGD controls 

would still be at 31⁄4 years. 

As shown previously, 21 months 

would be required to complete 

purchasing, construction, and startup of 

SCR on one unit. For multiple-unit 

installations with back-to-back unit 

outages for the tie-in construction and 

startup, the available 21⁄4-year 

implementation period would permit 

staggering of SCR installations on a 

maximum of three units (see the above 

referenced TSD). For a plant requiring 

SCR retrofit on more than three units, 

simultaneous outages of two units 

would become necessary. However, EPA 

notes that there are only six plants 

projected to require SCR installation on 

more than three units and, therefore, it 

is expected that simultaneous outages of 

two units at each of these plants would 

not have an adverse impact on the 

reliability of the electrical grid. 

25222 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

78The 200,000-ton Compliance Supplement Pool 

is apportioned to each of the 23 States and the 

District of Columbia that are required by CAIR to 

make annual NOX reductions, as well as the 2 States 

(Delaware and New Jersey) for which EPA is 

proposing to require annual NOX reductions.

In addition, the plants installing SCR 

on more than three units at the same site 

would have two other options to meet 

the rule’s requirements, without having 

to resort to simultaneous two-unit 

outages. First, these plants would be 

able to defer installation of SCRs on 

some of the units by receiving allocated 

allowances or purchasing allowances 

from the 200,000-ton Compliance 

Supplement Pool being made available 

as part of CAIR.78 Second, the outage 

activities for some of the units at these 

plants could be extended into the first 

quarter of 2009, which is beyond the 

compliance deadline of January 1, 2009, 

since these units would not generate 

NOX emissions during an outage and 

therefore not require any allowances to 

compensate for them. The EPA’s 

projections show that, of the above six 

plants installing SCR on more than three 

units, four of them require SCR retrofits 

on four units each. If it is assumed that 

these four plants would perform outage 

activities on the fourth unit during the 

first quarter of 2009, there would only 

be two plants left that would be 

required to either purchase allowances 

or perform work during simultaneous 

outages.

The EPA also notes that the total 

schedule requirements for multiple-unit 

plants can be reduced further by 

performing some of the activities, 

especially those related to planning and 

engineering, prior to the 21⁄4-year 

period. Also, with the total installation 

time requirement for FGD being more 

than that for SCR, EPA expects the 

outages associated with most Phase I 

FGDs to take place after January 1, 2009. 

The overall impact of the outages taken 

for these SCR and FGD retrofits would, 

therefore, be minimized. 

The EPA also performed an analysis 

to determine the impact of an 1-year 

acceleration in the NOX compliance 

deadline on Phase I boilermaker labor 

requirements. Since the amounts of the 

required Phase I NOX and FGD retrofits 

are not affected by this change, the 

overall boilermaker requirements for 

this phase will remain the same as 

previously reported for the case with the 

same compliance deadline for both NOX

and SO2. However, with the new NOX

compliance deadline, installation of all 

NOX retrofits would have to be 

completed by January 1, 2009, and some 

of the FGD construction work requiring 

boilermakers would also be done during 

this period. The EPA assumed that, 

along with completing installation of all 

SCRs, 35 percent of the boilermaker 

labor required to install all FGDs would 

be used in the period prior to January 

1, 2009. This is a conservative 

assumption, since the amount of 

boilermaker labor used for this period 

would be greater than 50 percent of the 

total Phase I boilermaker labor 

requirement. The analysis performed by 

EPA shows that sufficient boilermakers 

would be available with a contingency 

factor of approximately 14 percent to 

install all SCR controls and 35 percent 

of the FGD retrofit work by January 1, 

2009. This analysis is based on the most 

conservative assumptions, using the 

boilermaker duty rates suggested by one 

commenter and the EIA’s projections for 

natural gas prices and electricity 

demand rates. Based on the above 

analyses, EPA believes that moving the 

compliance deadline for Phase I for both 

NOX and SO2 is not practical. However, 

a 1-year acceleration in the compliance 

deadline for NOX only is feasible. Since 

EPA is obligated under the CAA to 

require emission reductions for 

obtaining NAAQS to be achieved as 

soon as practicable, we have based the 

final rule on two separate Phase I 

compliance deadlines of January 1, 

2009, and January 1, 2010, for NOX and 

SO2, respectively. 

(II) Implementing All Controls in

Phase I 

The EPA proposed a phased program 

with the consideration that for 

engineering and financial reasons, it 

would take a substantial amount of time 

to install the projected controls. This 

program would require one of the most 

extensive capital investment and 

engineering retrofit programs ever 

undertaken in the U.S. for pollution 

control. The capital investment for 

pollution control for CAIR that would 

be installed by 2015 is estimated to be 

approximately 15 billion dollars. By 

2015, close to 340 control unit retrofits 

will occur. This is occurring at a time 

when the industry also faces another 

major infrastructure challenge—

upgrading transmission capacity to 

make the grid more reliable and 

economic to operate. This also will cost 

tens of billions of dollars. 

The proposed program’s objective was 

to eliminate upwind states’ significant 

contribution to downwind 

nonattainment, providing air quality 

benefits as soon as practicable. A 

phased approach was also considered 

necessary because more of the difficultto-retrofit and finance, smaller size units 

would be included in the second phase, 

which would allow them to complete 

activities necessary for implementing 

the required controls as well as provide 

them an opportunity to benefit from the 

lessons learned during the first phase. 

In general, environmental controls 

resulting from legislative or regulatory 

actions are applied to those units first 

that offer superior choices from 

constructability and cost-effectiveness 

standpoints. Experience gained by the 

industry from these installations can 

then be used to develop innovative 

solutions for any constructability issues 

and to improve cost effectiveness, as 

these technologies are applied to harderto-control units. The EPA believes that 

this phenomenon applies to the 

application of the SCR and FGD 

technologies at coal-fired power plants.

In the last few years, SCR and FGD 

systems have been added to several 

existing coal-fired units, under the NOX

SIP Call and Acid Rain Program. These 

were mainly large units that had 

features, such as spacious layouts, 

amenable to the retrofit of the new air 

pollution control equipment. The units 

installing controls during Phase I of 

CAIR would, in general, be smaller in 

size and would offer relatively more 

difficult settings to accommodate the 

new equipment. These units would 

certainly benefit from the experience the 

industry has gained from the 

installations completed in recent years. 

A large portion of the units (47 

percent) projected to implement 

controls during the second phase 

consists of even smaller units, less than 

200 MW in size. Compared to larger 

units, the retrofits for these smaller 

units would be more difficult to plan, 

design, and build. Historically, smaller 

units have been built with less 

equipment redundancy, smaller 

capacity margins, and more congested 

layouts. It is likely, therefore, to be more 

difficult and require additional design 

efforts to accommodate the new 

equipment into the existing settings for 

the smaller units. Use of lessons learned 

by firms constructing these units from 

the previous installations, including 

those to be built during the first phase, 

would help streamline this process and 

maintain the cost effectiveness of these 

installations. Moving a large portion of 

the retrofits required for these smaller 

units to the second phase also provides 

more time to complete the required 

retrofit activities. 

Because EPA’s projections for the 

second phase include a large proportion 

of smaller units, the total number of 

units requiring NOX and SO2 controls 

exceeds that in the first phase (186 vs. 

153). Requiring an acceleration of the 

second phase controls to be completed 

in the first phase would, therefore, more 

than double the number of retrofits 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25223

required for the first phase from 153 to 

339. Based on data available from EPA 

and other sources, the industry 

completed 95 SCR installations for the 

NOX SIP Call in 2002 and 2003. If the 

2004 projections for the NOX SIP Call 

are added to this number, the total 

number of SCR retrofits over the 2002–

2004 period would be 140. This is less 

than half the number that would be 

required for CAIR during a similar 

period, if the Phase II requirements are 

implemented along with the Phase I 

requirements. Also, the combined 

capacity for FGD and SCR retrofits 

required for Phase I would be 122.5 GW, 

which is approximately 57 percent 

greater than the installed SIP-Call SCR 

capacity for the 2002–2004 period. Such 

a change in the rule would therefore 

amount to imposing a requirement over 

the power industry that is significantly 

more demanding and burdensome than 

what the industry was required to do 

under the NOX SIP Call rule. 

The EPA notes that critical resources 

other than the boilermakers are needed 

for the installation of SCR and FGD 

controls, such as construction 

equipment, engineering and 

construction staffs belonging to different 

trades, construction materials, and 

equipment manufacturers. Some 

commenters, based on their experience 

with NOX SIP Call, also pointed out that 

the requirement for some of these 

resources, especially construction 

equipment (e.g., large cranes used to 

mount SCR and scrubber vessels above 

ground), construction materials, 

equipment manufacturing shop 

capacities, and engineering and 

construction management teams 

overseeing these projects, is affected 

directly by the number of installations. 

The greater the requirement is to install 

a large number of retrofits by 2010, the 

greater would be the need for all these 

resources, which would be limited in 

the short term, as demands from 

equipment vendors, project teams, and 

material suppliers ramp up. In the NOX

SIP Call, this led to shortages and 

bottlenecks in projects in certain areas, 

causing increased project times and 

costs. The EPA wants to avoid creating 

a similar situation by requiring too 

much at once. 

The EPA has also acknowledged the 

increase in SCR costs during the NOX

SIP Call implementation period, most 

likely due to an increase in construction 

costs (resulting from increased demand 

for boilermaker labor) and steel prices. 

The EPA has revised its estimates of 

SCR capital costs in the IPM runs for the 

final rule and believes the conservatism 

in its FGD capital costs also accounts for 

this factor. 

The EPA believes that moving the 

Phase II requirements to the Phase I 

period could cause near-term shortages 

in some of the critical resources. This 

would further increase compliance costs 

and could remove the highly costeffective nature of these controls and 

lead to a greater demand for natural gas. 

In addition to the above, financing a 

large amount of controls for Phase I may 

prove challenging, especially for the 

coal plants owned by deregulated 

generators. As discussed later in this 

section, such generators are continuing 

to face serious financial challenges, and 

many have below investment grade 

credit ratings. This significantly 

complicates the financing of costly 

retrofit controls. Such plants would also 

not have the certainty of regulatory 

recovery of investments in pollution 

control, and would have to rely on the 

market to recover their costs. Having a 

second phase cap would allow these 

companies additional time to strengthen 

their finances and improve their cash 

flow. 

In the interest of being prudent in 

evaluating the need to phase in the 

program, EPA also performed an 

analysis to determine if the available 

boilermaker labor would be adequate to 

support installation of all Phase I and II 

controls in 2010. This analysis was 

conservatively based on using 

commenter-suggested boilermaker duty 

rates and EIA’s projections for gas prices 

and electricity demand rates. The 

results show that a sufficient number of 

boilermakers will not be available and 

that there will be a shortfall of 

approximately 25 percent in the 

boilermakers available to support Phase 

I activities for this case. 

Based on the above analyses, EPA 

believes that implementation of controls 

for both phases in Phase I is impractical. 

We also believe that it is prudent and 

reasonable in requiring the industry to 

undertake this massive retrofit program 

on a two-phase schedule, to be largely 

completed in less than a decade. 

(III) Acceleration of Phase II Compliance 

Deadline

The EPA does not believe that 

acceleration of the compliance deadline 

for the second phase is reasonable. As 

pointed out earlier, a large portion of the 

units projected to install controls during 

the second phase consists of small units, 

less than 200 MW in size. Due to the 

issues related to financing of the retrofit 

projects for some of these units and 

considering that planning and designing 

of controls for these units is likely to 

take longer, EPA does not consider the 

schedule acceleration to be appropriate. 

The EPA notes that Phase I of CAIR 

is the initial step on the slope of 

emissions reduction (the glide-path) 

leading to the final control levels. 

Because of the incentive to make early 

emission reductions that the cap-andtrade program provides, reductions will 

begin early and will continue to 

increase through Phases I and II. The 

EPA, therefore, does not believe that all 

of the required Phase II emission 

reductions would take place on January 

1, 2015, the compliance deadline. These 

reductions are expected to accrue 

throughout the implementation period, 

as the sources install controls and start 

to test and operate them. 

The EPA also notes that the 5-year 

implementation period for Phase II is 

consistent with other regulations and 

statutory requirements, such as title IV 

for SO2 and NOX controls. In addition, 

some commenters have cited a need for 

a 6-year period for obtaining financing 

for plants owned by the co-operatives. 

These facilities are likely to commit 

funds for major activities, only after 

financing has been obtained. Therefore, 

for such facilities, a period of 

approximately four years would be 

available for procuring, installing, and 

startup activities, assuming that the 

financing activities were started right 

after the rule is finalized. Since the 

plants owned by co-operatives are 

usually small in size, they are likely to 

require and be benefitted by the extra 

time allowed to them by this four-year 

implementation period. 

The EPA also performed an analysis 

to verify adequacy of the available 

boilermaker labor for pollution control 

retrofits the power industry will install 

to comply with the Phase II CAIR 

requirements. A 36-month construction 

period requiring boilermakers was 

conservatively selected for this analysis. 

Based on the IPM analysis for the final 

rule, conservatively, the power industry 

will build 27.5 GW of FGD and 26.6 GW 

of SCR retrofits for compliance with 

lower emission caps that go into effect 

for NOX and SO2 in 2015. The analysis 

was based on using EIA’s projections for 

the natural gas prices and electricity 

demand rates and the commentersuggested boilermaker duty rates. The 

results show availability of ample 

boilermakers with a contingency factor 

of 46 percent to support Phase II 

activities. 

The EPA notes that the retrofits that 

will occur in Phase II will be smaller, 

more numerous, and more challenging, 

since the easiest controls will likely be 

installed in Phase I. Therefore, having a 

greater contingency factor (as we do) is 

warranted. This is further supported 

when the uncertainty in predicting the 

25224 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

79 In fact, between nine and eleven (depending on 

the credit agency) of the twenty largest owners of 

deregulated coal capacity in the U.S. currently have 

below-investment-grade credit ratings.

construction activities in the areas 

outside of air pollution controls is 

considered. Notably after 2010, the 

excess generation capacity that we have 

today is no longer expected to be 

present and there may be a shift towards 

a requirement for increasing generation 

capacity. Increased construction of new 

power plants will have a direct impact 

on the availability of boilermakers for 

the Phase II controls. The EPA believes 

that a higher contingency factor for 

Phase II is desirable to ensure that the 

industry will succeed in getting the 

required reductions at the required time. 

Any acceleration of the Phase II 

compliance deadline will also cause an 

appreciable reduction in the above 

estimated contingency factor for 

boilermaker labor. For example, based 

on EPA analysis, an acceleration of one 

year is projected to reduce this 

contingency factor to only about one 

percent. Therefore, EPA believes that 

acceleration of the Phase II compliance 

deadline cannot be justified. 

3. Assure Financial Stability 

The EPA recognizes that the power 

sector will need to devote large amounts 

of capital to meet the control 

requirements of the first phase. 

Furthermore, over the next 10 years, the 

power sector is facing additional 

financial challenges unrelated to 

environmental issues, including 

economic restructuring impacts, 

investments related to domestic security 

and investments related to electrical 

infrastructure. Among the consideration 

of other factors, EPA believes it is 

important to take into account the 

ability of the power sector to finance the 

controls required under CAIR. A 

detailed assessment of the status of the 

financial health of the U.S. Utility 

Industry, particularly of the unregulated 

sector is offered in the TSD, ‘‘U.S. 

Utility Industry Financial Status and 

Potential Recovery.’’

Commenters have noted that they 

appreciate EPA’s growing realization 

that many companies may have 

difficulty securing financing, and the 

agency’s establishment of a two-phase 

reduction program on both technical 

and financial grounds.

Utilities and non-utility generating 

companies have felt significant financial 

pressure over the past 5 years. The years 

2000 and 2001 saw the escalation and 

fallout from the California energy crisis, 

the bankruptcy of Enron, and a massive 

building program, largely on the side of 

the merchant generating sector. 

Subsequent low power margins and 

large debt obligations have led to a 

significant number of credit downgrades 

of utilities and power generators and the 

bankruptcy of coal-generating merchant 

companies. According to Standard and 

Poor’s, a leading provider of investment 

ratings, there were almost ten times 

more downgrades of utility credit in 

2002 and 2003 than there were 

upgrades. While more recently the 

sector has stabilized, a significant 

number of owners of coal-fired capacity 

in the CAIR region, particularly those 

with deregulated capacity, are still at 

below investment-grade credit ratings. 

In general, EPA believes that 

regulated plants, given appropriate 

regulatory requirements, should not face 

significant financial problems meeting 

their obligations under CAIR. While 

EPA recognizes that issues such as the 

expiration of rate caps and the time lags 

associated with regulatory approval and 

recovery may provide cash flow 

challenges, regulated electricity rates are 

generally seen as a positive factor in 

credit ratings, as entities are allowed a 

recovery on prudent investment through 

rate cases (and, in some jurisdictions, 

the recovery of allowance expenditures 

through fuel adjustment clauses). 

Deregulated coal capacity (operating 

in an environment of market prices 

rather than electricity rates set by 

regulators) has no such guarantees, and 

would need to recover investments in 

pollution control from market prices 

(which in many cases are not set by coal 

units). Additionally, deregulated 

entities, because of their more 

aggressive building and borrowing 

strategies and reliance on market prices 

(which now reflect the current capacity 

overbuild), have faced more significant 

financial difficulties (including a 

number of bankruptcies) and are 

currently in a weaker position 

financially.79 A number of firms that 

have avoided financial distress in the 

near term have done so by renegotiating 

their pending debt, postponing 

payment. A good portion of this debt is 

of a shorter-term nature, and will be 

coming due in the next five years.

Such financial difficulties increase 

the cost of capital necessary for capital 

expenditures and affect the availability 

of such capital, making required 

controls more expensive. Recent 

financial troubles have been cited as the 

reason for the deferment or cancellation 

of pollution control expenditures. 

Should interest rates rise in the future, 

it will become more difficult and costly 

for utilities seeking financing. 

These problems impact a significant 

segment of coal generators, as 

deregulated coal capacity makes up 

about a third of all U.S. coal capacity 

and almost 90 percent of this 

deregulated capacity would be affected 

by CAIR requirements. 

Given the lead times needed to plan 

and construct such equipment, as well 

as the financial uncertainty many of the 

plant owners are confronting, 

companies may find it difficult to install 

controls at their plants too quickly. The 

EPA believes that the choice of timing 

of the emission caps in CAIR would 

allow firms time to improve their 

current and near-term financial 

difficulties (through reorganization, 

mergers, sales, etc.). Phasing in the more 

stringent emission caps by 2015 would 

also spread investment requirements 

and resulting cash flow demands, rather 

than forcing firms to finance a large 

spike in investments in a very short 

time period, while they are still trying 

to recover financially. 

The timing of controls expected to be 

installed as a result of CAIR are similar 

to that noted in EPA’s analysis of the 

Clear Skies proposal. The EPA looked in 

detail at the potential financial impact 

of the Clear Skies program (particularly 

focusing on the deregulated coal sector). 

The EPA found that some individual 

deregulated coal plants might be 

adversely affected, but on average such 

plants would actually experience a 

small financial improvement under 

Clear Skies. Baseload deregulated coal 

plants would benefit from even slight 

increases in the price of natural gas ( 

units burning natural gas generally set 

the wholesale price of electricity on the 

margin in the regions where deregulated 

coal is located). These units would also 

be recipients of allocated allowances. 

Overall, the phased in nature of CAIR, 

the fact that most coal plants continue 

to be regulated and the fact that sources 

would also receive allowances, would 

all mitigate the financial impact of this 

rule. 

The EPA believes that the timing 

requirements finalized today reflect a 

prudent and cautious approach 

designed to assure that the industry will 

succeed in implementing this program. 

The EPA believes that deferring the 

second phase to 2015 will provide 

enough time for companies to raise 

additional capital needed to install 

controls. Also, we believe that the 

implementation period should account 

(at least broadly) for the possibility that 

electricity demand or natural gas prices 

may increase more than assumed, and 

therefore that additional control 

equipment would be needed. Allowing 

until 2015 for implementation of the 

more stringent control levels in today’s 

rule will provide more flexibility in the 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25225

80The survey results are in ‘‘A Survey of State 

Incentives Encouraging Improved Environmental 

Performance of Base-Load Electric Generation 

Facilities: Policy and Regulatory Initiatives,’’ at 

http://www.naruc.org/

displayindustryarticle.cfm?articlenbr=21826.

81 Detailed documentation of EPA’s IPM update, 

including updated control cost assumptions, is in 

the docket. The SCR control cost assumptions were 

presented in a peer-reviewed paper by Sikander 

Khan and Ravi Srivastava, ‘‘Updating Performance 

and Cost of NOX Control Technologies in the 

Integrated Planning Model,’’ at the Combined 

Power Plant Air Pollution Control Mega 

Symposium, August 30–September 2, 2004, 

Washington, DC.

event of greater electricity demand and 

will ensure that power plants in the 

CAIR region will have the ability, both 

technical and financial, to make the 

pollution control retrofits required. 

Currently, EPA is cooperating with 

the National Association of Regulatory 

Utility Commissioners (NARUC) in 

developing a menu of policy options 

and financial incentives for encouraging 

improved environmental performance 

for generation. A survey of a number of 

States was conducted as part of this 

effort, and policies such as pre-approval 

statutes for compliance plans, state 

income tax credits, accelerated 

depreciation, and special treatment of 

allowance transactions were cited as 

examples of such policies 80. Such 

policies will ease some of the financial 

pressures of CAIR by providing greater 

regulatory certainty and lowering the 

effective costs of controls.

D. Control Requirements in Today’s 

Final Rule 

1. Criteria Used To Determine Final 

Control Requirements 

The EPA’s general approach to 

developing emission reduction 

requirements—basing the requirements 

on the application of highly costeffective controls—was adopted in the 

NOX SIP Call and has been sustained in 

court. In the NPR, the Agency proposed 

this approach for developing SO2 and 

NOX emission reduction requirements. 

The majority of commenters accepted 

this basic approach for determining 

reduction requirements. Some 

commenters did suggest other 

approaches, however, as discussed 

above. 

Many commenters suggested that the 

CAIR regionwide SO2 and NOX control 

levels should be more or less stringent 

than the levels proposed in the NPR. 

The EPA has determined that the 

control levels that we are finalizing 

today are highly cost-effective and 

feasible, and constitute substantial 

reductions that address interstate 

transport, at the outset of State and EPA 

efforts to bring about attainment of the 

PM2.5 NAAQS (EPA believes that most 

if not all States will obtain CAIR 

reductions by capping emissions from 

the power sector). Today, EPA finalizes 

the use of both average and marginal 

cost effectiveness of controls as the basis 

for determining the highly cost-effective 

amounts. 

In the CAIR NPR, EPA proposed 

criteria for determining the appropriate 

levels of SO2 and NOX emissions 

reductions, and stated that EPA 

considered a variety of factors in 

evaluating the source categories from 

which highly cost-effective reductions 

may be available and the level of 

reduction assumed from that sector (69 

FR 4611). The EPA has reviewed 

comments on its NPR, SNPR and NODA 

and conducted further analyses with 

respect to the proposed criteria, and is 

finalizing its control requirements in 

today’s action. Following is a brief 

summary of EPA’s conclusions based on 

the criteria. 

The availability of information, and 

the identification of source categories 

emitting relatively large amounts of the 

relevant emissions, are two criteria used 

in EPA’s evaluation of the CAIR 

program. In the NPR, EPA stated that 

EGUs are the most significant source of 

SO2 emissions and a very substantial 

source of NOX in the affected region, 

and further stated that highly costeffective control technologies are 

available for achieving significant SO2

and NOX emissions reductions from 

EGUs. We requested comment on 

sources of information for emissions 

and costs from other sectors (69 FR 

4610). A detailed discussion regarding 

non-EGU sources is provided above. 

The EPA has not received additional 

information that would change its 

proposed control strategy. 

Another criterion is the performance 

and applicability of control measures. 

The NPR included a detailed discussion 

of the performance and applicability of 

SO2 and NOX control technologies for 

EGUs. In particular, EPA discussed FGD 

for SO2 removal and SCR for NOX

removal, both of which are fully 

demonstrated and available pollution 

control technologies on coal-fired EGU 

boilers (69 FR 4612). None of the 

commenters provided information that 

differed from EPA’s assessment of the 

performance of these control measures. 

In addition, the commenters generally 

supported EPA’s assumptions on the 

applicability of these controls. 

The cost effectiveness of control 

measures is another criterion used in 

EPA’s analysis. As discussed in detail 

above, EPA determined that the 

proposed control levels are highly costeffective, and is finalizing the levels in 

today’s action. The EPA used IPM to 

analyze the cost effectiveness of the 

proposed and final CAIR control 

requirements. IPM incorporates 

assumptions about the capital costs and 

fixed and variable operations and 

maintenance costs of control measures 

for EGUs. Several commenters suggested 

that the SCR control cost assumptions 

that we used in IPM analysis for the 

NPR were too low. Consequently, we 

increased the SCR control cost 

assumptions in IPM and conducted cost 

effectiveness modeling for the final 

control requirements using these 

updated costs.81 Commenters generally 

supported our FGD control costs 

assumptions, which are largely 

unchanged from the NPR modeling to 

the modeling for today’s final rule.

And finally, EPA considered 

engineering and financial factors that 

affect the availability of control 

measures. The EPA conducted a 

detailed analysis of engineering factors 

that affect timing of control retrofits, 

including an evaluation of the 

comments received. The EPA’s analysis 

supports its compliance schedule, a 

two-phase emissions control program 

with the final phase commencing in 

2015, and with a first phase 

commencing in 2010 for SO2 reductions 

and in 2009 for NOX reductions. 

Further, EPA’s analysis demonstrates 

that it would not be realistically 

possible to start the program sooner, or 

to impose more stringent emissions caps 

in the first phase.

Based on EPA’s review of comments 

and analysis, EPA determined that the 

proposed control requirements are 

reasonable with respect to engineering 

factors. As discussed above, EPA also 

considered how to avoid creating 

financial instability for the affected 

sector, and how to ensure the capital 

needed for the required controls would 

be readily available. Assuming States 

choose to control EGUs, the power 

sector will need to devote large amounts 

of capital to meet the CAIR control 

requirements. 

The EPA explained that implementing 

CAIR as a two-phase program, with the 

more stringent control levels 

commencing in the second phase, will 

allow time for the power sector to 

address any financial challenges. The 

EPA’s evaluation of engineering and 

financial factors supports the decision 

to implement CAIR as a two-phase 

program, with the final (second) 

compliance level commencing in 2015 

and a first phased-in level starting in 

2010 for SO2 reductions and in 2009 for 

NOX reductions. A description of the 

final CAIR control requirements follows. 

25226 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

82For a discussion of the emission reduction 

requirements if States choose to control sources 

other than EGUs, see section VII of this preamble.

83For a discussion of the emission reduction 

requirements if States choose to control sources 

other than EGUs, see section VII of this preamble.

2. Final Control Requirements 

Today’s final rule implements new 

annual SO2 and NOX emissions control 

requirements to reduce emissions that 

significantly contribute to PM2.5

nonattainment. The final rule also 

requires new ozone season NOX

emissions control requirements to 

reduce emissions that significantly 

contribute to ozone nonattainment. 

The final rule requires annual SO2

and NOX reductions in the District of 

Columbia and the following 23 States: 

Alabama, Florida, Georgia, Illinois, 

Indiana, Iowa, Kentucky, Louisiana, 

Maryland, Michigan, Minnesota, 

Mississippi, Missouri, New York, North 

Carolina, Ohio, Pennsylvania, South 

Carolina, Tennessee, Texas, Virginia, 

West Virginia, and Wisconsin. (In the 

‘‘Proposed Rules’’ section of today’s 

action, EPA is publishing a proposal to 

include Delaware and New Jersey in the 

CAIR region for annual SO2 and NOX

reductions.) 

In addition, the final rule requires 

ozone season NOX reductions in the 

District of Columbia and the following 

25 States: Alabama, Arkansas, 

Connecticut, Delaware, Florida, Illinois, 

Indiana, Iowa, Kentucky, Louisiana, 

Maryland, Massachusetts, Michigan, 

Mississippi, Missouri, New Jersey, New 

York, North Carolina, Ohio, 

Pennsylvania, South Carolina, 

Tennessee, Virginia, West Virginia, and 

Wisconsin. 

The CAIR requires many of the 

affected States to reduce annual SO2 and 

NOX emissions as well as ozone season 

NOX emissions. However, there are 

three States for which only annual 

emission reductions are required 

(Georgia, Minnesota and Texas). 

Likewise, there are five States for which 

only ozone season reductions are 

required (Arkansas, Connecticut, 

Delaware, Massachusetts, and New 

Jersey). The following 20 States and the 

District of Columbia are required to 

make both annual and ozone season 

reductions: Alabama, Florida, Illinois, 

Indiana, Iowa, Kentucky, Louisiana, 

Maryland, Michigan, Mississippi, 

Missouri, New York, North Carolina, 

Ohio, Pennsylvania, South Carolina, 

Tennessee, Virginia, West Virginia and 

Wisconsin. 

Table IV–14 shows the amounts of 

regionwide annual SO2 and NOX

emissions reductions under CAIR that 

EPA projects, if States choose to meet 

their CAIR obligations by controlling 

EGUs. Table IV–15 shows the amounts 

of regionwide ozone season NOX

emissions reductions under CAIR that 

EPA projects, if States choose to meet 

their CAIR obligations by controlling 

EGUs. If all affected States choose to 

implement these reductions through 

controls on EGUs, the regionwide 

annual SO2 and NOX emissions caps 

that would apply for EGUs are also 

shown in the Table IV–14, and ozone 

season NOX caps for EGUs are in Table 

IV–15. Base case emissions levels for 

affected EGUs as well as emissions with 

CAIR are also shown in Table IV–14 and 

Table IV–15, based on IPM modeling.

The EPA is finalizing the regionwide 

EGU SO2 emissions caps—if States 

choose to comply by controlling EGUs—

as shown in Table IV–14 82. As 

indicated above, EPA identified SO2

budget amounts, as target levels for 

further evaluation, by adding together 

the title IV Phase-II allowances for all of 

the States in the CAIR region, and 

making a 50 percent reduction for the 

2010 cap and a 65 percent reduction for 

the 2015 cap. The EPA determined, 

through IPM analysis, that the resulting 

regionwide emissions caps (if all States 

choose to obtain reductions from EGUs) 

are highly cost-effective levels.

Also, EPA is finalizing the regionwide 

EGU annual and ozone season NOX

emission caps—if States choose to 

comply by controlling EGUs—as shown 

in Table IV–14 and Table IV–15.83 As 

indicated above, EPA identified NOX

budget amounts, as target levels for 

further evaluation, through the 

methodology of determining the highest 

recent Acid Rain Program heat input 

from years 1999–2002 for each affected 

State, summing the highest State heat 

inputs into a regionwide heat input, and 

multiplying the regionwide heat input 

by 0.15 lb/mmBtu and 0.125 lb/mmBtu 

for 2009 and 2015, respectively. The 

EPA determined, through IPM analysis, 

that the resulting regionwide emissions 

caps (if all States choose to obtain 

reductions from EGUs) are highly costeffective levels.

The emission reductions, EGU 

emissions caps, and emissions shown in 

Table IV–14 are for the 23 States and the 

District of Columbia that are required to 

make annual SO2 and NOX reductions 

for CAIR. (Table IV–14 does not include 

information for the five States that are 

required to make ozone season 

reductions only.) 

The emission reductions, EGU 

emissions caps, and emissions shown in 

Table IV–15 are for the 25 States and the 

District of Columbia that are required to 

make ozone season NOX reductions for 

CAIR. (Table IV–15 does not include 

information for the three States that are 

required to make annual reductions 

only.)

The EPA is requiring the CAIR SO2

and NOX emissions reductions in two 

phases. For States affected by annual 

SO2 and NOX emission reductions 

requirements, the final (second) phase 

commences January 1, 2015, and the 

first phase begins January 1, 2010 for 

SO2 reductions and January 1, 2009 for 

NOX reductions. For States affected by 

ozone season NOX emission reductions 

requirements, the final (second) phase 

commences May 1, 2015 and the first 

phase starts May 1, 2009. Notably, the 

first phase control requirements are 

effective in years 2010 through 2014 for 

SO2 and in years 2009 through 2014 for 

NOX, and the 2015 requirements are for 

that year and thereafter.

TABLE IV–14.—FINAL RULE SO2 AND NOX ANNUAL BASE CASE EMISSIONS, EMISSION CAPS, EMISSIONS AFTER CAIR 

AND EMISSION REDUCTIONS IN THE REGION REQUIRED TO MAKE ANNUAL SO2 AND NOX REDUCTIONS (23 STATE

AND DC) FOR THE INTERIM PHASE (2010 FOR SO2 AND 2009 FOR NOX) AND FINAL PHASE (2015 FOR SO2 AND

NOX) FOR EGUS

(Million Tons) 84

Base case 

emissions 

CAIR emissions caps Emissions 

after CAIR 

Emissions 

reduced 

First phase (2010 for SO2 and 2009 for NOX) 

SO2 .................................................................................................................................. 8.7 3.6 5.1 3.5 

NOX .................................................................................................................................. 2.7 1.5 1.5 1.2 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25227

84Table IV–14 includes regionwide information 

for the 23 States and DC that are required by CAIR 

to make annual emission reductions. It does not 

include information for the 5 CAIR States that are 

required to make ozone season reductions only. The 

CAIR requires NOX emission reductions in a total 

of 28 States and DC. For 20 States and DC, both 

annual and ozone season NOX reductions are 

required. For 3 States only annual reductions are 

required, and for 5 States only ozone season 

reductions are required. The total projected NOX

emission reductions that will result from CAIR—if 

all States control EGUs—include the annual 

reductions shown in Table IV–14 (for 23 States and 

DC) plus the ozone season reductions in the 5 States 

required to make ozone season reductions only. The 

EPA projects the total NOX reductions, in all 28 

CAIR States and DC, to be 1.2 million tons in 2009 

and 1.5 million tons in 2015. Note that the values 

in this table represent the final CAIR policy and 

differ slightly from the values in the RIA (which 

were based on an earlier and slightly different IPM) 

(see more detailed discussion both earlier in this 

section and in the RIA).

85Table IV–15 shows regionwide information for 

the 25 States and DC that are required to make 

ozone season emission reductions under CAIR. It 

does not include information for the 3 States that 

are required to make annual emission reductions 

only.

TABLE IV–14.—FINAL RULE SO2 AND NOX ANNUAL BASE CASE EMISSIONS, EMISSION CAPS, EMISSIONS AFTER CAIR 

AND EMISSION REDUCTIONS IN THE REGION REQUIRED TO MAKE ANNUAL SO2 AND NOX REDUCTIONS (23 STATE

AND DC) FOR THE INTERIM PHASE (2010 FOR SO2 AND 2009 FOR NOX) AND FINAL PHASE (2015 FOR SO2 AND

NOX) FOR EGUS—Continued

(Million Tons) 84

Base case 

emissions 

CAIR emissions caps Emissions 

after CAIR 

Emissions 

reduced 

Sum .................................................................................................................................. 11.4 NA 6.6 4.8 

Second Phase (2015 for SO2 and NOX) 

SO2 .................................................................................................................................. 7.9 2.5 4.0 3.8 

NOX .................................................................................................................................. 2.8 1.3 1.3 1.5 

Sum .................................................................................................................................. 10.6 NA 5.3 5.3 

Notes: Numbers may not add due to rounding. 

1. The emission caps that EPA used to make its determination of highly cost-effective controls and the emission reductions associated with 

those caps are shown in Table IV–14. For a discussion of the emission reduction requirements if States control source categories other than 

EGUs, see section VII in this preamble. Emissions shown here are for EGUs with capacity greater than 25 MW. 

2. The District of Columbia and the following 23 States are affected by CAIR for annual SO2 and NOX controls: AL, FL, GA, IA, IL, IN, KY, LA, 

MD, MI, MN, MO, MS, NY, NC, OH, PA, SC, TN, TX, VA, WV, WI. 

3. The 2010 SO2 emissions cap applies to years 2010 through 2014. The 2009 NOX emissions cap applies to years 2009 through 2014. The 

2015 caps apply to 2015 and beyond. 

4. Due to the use of the existing bank of SO2 allowances, the estimated SO2 emissions in the CAIR region in 2010 and 2015 are higher than 

the emissions caps. 

5. Over time the banked SO2 emissions allowances will be consumed and the 2015 cap level will be reached. SO2 emissions levels can be 

thought of as on a flexible ‘‘glide path’’ to meet the 2015 CAIR cap with increasing reductions over time. The annual SO2 emissions levels in 

2020 with CAIR are forecasted to be 3.3 million tons within the region encompassing States required to make annual reductions, an annual reduction of 4.4 million tons from base case levels. 

TABLE IV–15.—FINAL RULE NOX OZONE SEASON BASE CASE EMISSIONS, EMISSIONS CAPS, EMISSIONS AFTER CAIR 

AND EMISSION REDUCTIONS IN THE REGION REQUIRED TO MAKE OZONE SEASON NOX REDUCTIONS (25 STATES AND

DC) FOR THE INTERIM PHASE (2009) AND FINAL PHASE (2015) FOR ELECTRIC GENERATION UNITS

(Million Tons) 85

Ozone Season NOX

Phase Base case 

emissions 

CAIR emissions caps Emissions 

after CAIR 

Emissions 

reduced 

2009 ................................................................................................................................. 0.7 0.6 0.6 0.1 

2015 ................................................................................................................................. 0.7 0.5 0.5 0.2 

Notes:

1. The emission caps that EPA used to make its determination of highly cost-effective controls and the emission reductions associated with 

those caps are shown in Table IV–15. For a discussion of the emission reduction requirements if States control source categories other than 

EGUs, see section VII in this preamble. Emissions shown here are for EGUs with capacity greater than 25 MW. 

2. The District of Columbia and the following 25 States are affected by CAIR for ozone season NOX controls: AL, AR, CT, DE, FL, IA, IL, IN, 

KY, LA, MA, MD, MI, MO, MS, NJ, NY, NC, OH, PA, SC, TN, VA, WV, WI. 

3. The 2009 NOX emissions cap applies to years 2009 through 2014. The 2015 cap applies to 2015 and beyond. 

Table IV–16 shows the estimated 

amounts of regionwide annual SO2 and 

NOX emissions reductions that would 

occur if EPA finalizes its proposal to 

find that Delaware and New Jersey 

contribute significantly to downwind 

PM2.5 nonattainment, and if all affected 

States choose to control EGUs (the 

proposal is published in the ‘‘Proposed 

Rules’’ section of today’s action). In that 

case, the estimated regionwide annual 

SO2 and NOX emissions caps that would 

apply for EGUs are as shown in Table 

IV–16. Annual base case emissions 

levels for EGUs in the CAIR region 

(including Delaware and New Jersey) as 

well as emissions with CAIR are also 

shown in the Table, based on IPM 

modeling. If EPA finalizes its proposal 

to include Delaware and New Jersey for 

PM2.5 requirements, then the ozone 

25228 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

86For a discussion of the emission reduction 

requirements if States choose to control sources 

other than EGUs, see section VII of this preamble.

87Table IV–16 includes regionwide information 

for the 25 States and DC that will be required to 

make annual emission reductions if EPA finalizes 

its proposal to require annual reductions in 

Delaware and New Jersey under CAIR. The table 

does not include information for the 3 States 

(Arkansas, Connecticut, and Massachusetts) that 

would be affected by CAIR for ozone season 

reductions only.

season requirements would not change 

for States required to make ozone season 

reductions for CAIR. 

Based on EPA modeling with 

Delaware and New Jersey included in 

the PM2.5 region (and if all affected 

States choose to control EGUs), the EGU 

emissions caps and the ozone season 

NOX emissions and emission reductions 

associated with those caps, for the 25 

States and the District of Columbia that 

are required to make ozone season NOX

reductions, would be as shown in Table 

IV–15, above.86

TABLE IV–16.—SO2 AND NOX ANNUAL BASE CASE EMISSIONS, EMISSIONS CAPS, EMISSIONS AFTER CAIR AND EMISSION REDUCTIONS IN THE REGION REQUIRED TO MAKE ANNUAL SO2 AND NOX REDUCTIONS (25 STATES AND DC) 

FOR THE INITIAL PHASE (2010 FOR SO2 AND 2009 FOR NOX) AND FINAL PHASE (2015 FOR SO2 AND NOX) FOR

ELECTRIC GENERATION UNITS IF EPA FINALIZES ITS PROPOSAL TO INCLUDE DELAWARE AND NEW JERSEY FOR PM2.5

REQUIREMENTS

[Million tons] 87

First phase

(2010 for SO2 and 2009 for NOX) 

Base case 

emissions 

CAIR

emissions

caps 

Emissions 

after CAIR 

Emissions 

reduced 

SO2 .................................................................................................................................. 8.8 3.7 5.2 3.6 

NOX .................................................................................................................................. 2.8 1.5 1.5 1.2 

Sum .................................................................................................................................. 11.5 NA 6.7 4.8 

Second phase 

(2015 for SO2 and NOX) 

Base case 

emissions 

CAIR 

emissions 

caps 

Emissions 

after CAIR 

Emissions 

reduced 

SO2 .................................................................................................................................. 7.9 2.6 4.1 3.9 

NOX .................................................................................................................................. 2.8 1.3 1.3 1.5 

Sum .................................................................................................................................. 10.7 NA 5.3 5.4 

Note: Numbers may not add due to rounding. 1The emission caps that EPA used to make its determination of highly cost-effective controls and the emission reductions associated with 

those caps are shown in Table IV–16. For a discussion of the emission reduction requirements if States control source categories other than 

EGUs, see section VII in this preamble. Emissions shown here are for EGUs with capacity greater than 25 MW. 2The District of Columbia and the following 25 States would be affected by CAIR for annual SO2 and NOX controls if EPA finalizes its proposal 

to include DE and NJ: AL, DE, FL, GA, IA, IL, IN, KY, LA, MD, MI, MN, MO, MS, NJ, NY, NC, OH, PA, SC, TN, TX, VA, WV, WI. 3The 2010 SO2 emissions cap would apply to years 2010 through 2014. The 2009 NOX emissions cap would apply to years 2009 through 

2014. The 2015 caps would apply to 2015 and beyond. 4 Due to the use of the existing bank of SO2 allowances, the estimated SO2 emissions in the CAIR region in 2010 and 2015 would be higher 

than the emissions caps. 5Over time the banked SO2 emissions allowances would be consumed and the 2015 cap level would be reached. SO2 emissions levels can 

be thought of as on a flexible ‘‘glide path’’ to meet the 2015 CAIR cap with increasing reductions over time. The annual SO2 emissions levels in 

2020 with CAIR, within the region of States required to make annual reductions (including Delaware and New Jersey), are forecasted to be 3.3 

million tons, an annual reduction of 4.4 million tons from base case levels. 

The EPA apportioned the EGU caps—

and associated required regionwide 

emission reductions—on a State-byState basis. The affected States may 

determine the necessary controls on SO2

and NOX emissions to achieve the 

required reductions. The EPA’s 

apportionment method and the resulting 

State EGU emissions budgets are 

described in Section V in today’s 

preamble.

To achieve the required SO2 and NOX

reductions in the most cost-effective 

manner, EPA suggests that States 

implement these reductions by 

controlling EGUs under a cap and trade 

program that EPA would implement. 

However, the States have flexibility in 

choosing the sources that must reduce 

emissions. If the States choose to require 

EGUs to reduce their emissions, then 

States must impose a cap on EGU 

emissions, which would in effect be an 

annual emissions budget. Provisions for 

allocating SO2 and NOX allowances to 

individual EGUs—which apply if a 

State chooses to control EGUs and elects 

to allow them to participate in the 

interstate cap and trade program—are 

presented elsewhere in today’s 

preamble. If a State wants to control 

EGUs, but does not want to allow EGUs 

to participate in the interstate cap and 

trade program, the State has flexibility 

in allocating allowances, but it must cap 

EGUs. Sources that are subject to the 

emission reduction requirements under 

title IV continue to be subject to those 

requirements. 

If the States choose to control other 

sources, then they must employ 

methods to assure that those other 

sources implement controls that will 

yield the appropriate amount of annual 

emissions reduction. See section VII 

(SIP Criteria and Emissions Reporting 

Requirements) in today’s preamble. 

Implementation of the cap and trade 

program is discussed in section VIII in 

today’s preamble. 

For convenience, we use specific 

terminology to refer to certain concepts. 

‘‘State budget’’ refers to the statewide 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25229

emissions that may be used as an 

accounting technique to determine the 

amount of annual or ozone season 

emissions reductions that controls may 

yield. It does not imply that there is a 

legally enforceable statewide cap on 

emissions from all SO2 or NOX sources. 

‘‘Regionwide budget’’ refers to the 

amount of emissions, computed on a 

regionwide basis, which may be used to 

determine State-by-State requirements. 

It does not imply that there is a legally 

enforceable regionwide cap on 

emissions from all SO2 or NOX sources. 

‘‘State EGU budget’’ refers to the legally 

enforceable annual or ozone season 

emissions cap on EGUs a State would 

apply should it decide to control EGUs. 

V. Determination of State Emissions 

Budgets 

The EPA outlined in the NPR and 

SNPR its proposals regarding a 

methodology for setting both regional 

and State-level SO2 and NOX budgets. 

Section IV explains how the regionwide 

budgets were developed. This section V 

describes how EPA apportions the 

regionwide emissions reductions—and 

the associated EGU caps—on a State-byState basis, so that the affected States 

may determine the necessary controls of 

SO2 and NOX emissions. 

In the NPR and SNPR, EPA proposed 

annual SO2 and NOX caps for States 

contributing to fine particle 

nonattainment and separate ozoneseason only caps for States contributing 

to ozone—but not fine particle—

nonattainment. The EPA is finalizing an 

annual cap for both SO2 and NOX for 

States that contribute to fine particle 

nonattainment. In addition, EPA is 

finalizing an ozone-season only cap for 

NOX for all States that contribute to 

ozone nonattainment. 

States have several options for 

reducing emissions that significantly 

contribute to downwind nonattainment. 

They can adopt EPA’s approach of 

reducing the emissions in a costeffective manner through an interstate 

cap and trade program. This approach 

would, by definition, achieve the 

required cost-effective reductions. 

Alternately, States could achieve all of 

the necessary emissions reductions from 

EGUs, but choose not to use EPA’s 

interstate emissions trading program. In 

this case, a State would need to 

demonstrate that it is meeting the EGU 

budgets outlined in this section. Finally, 

States could obtain at least some of their 

required emissions reductions from 

sources other than EGUs. Additional 

detail on these options is provided in 

section VII. 

A. What Is the Approach for Setting 

State-by-State Annual Emissions 

Reductions Requirements and EGU 

Budgets? 

This section presents the final 

methodologies used for apportioning 

regionwide emission reduction 

requirements or budgets to the 

individual States. 

In the CAIR NPR, EPA proposed 

methods for determining the SO2 and 

NOX emission reduction requirements 

or budgets for each affected State. In the 

June 2004 SNPR, EPA proposed 

corrections and improvements to the 

proposals in the CAIR NPR. In the 

August 2004 NODA, EPA presented the 

corrected NOX budgets resulting from 

the improvements proposed in the 

SNPR.

1. SO2 Emissions Budgets 

a. State Annual SO2 Emission Budget 

Methodology 

As noted elsewhere in today’s preamble, 

the regionwide annual budget for 2015 

and beyond is based on a 65 percent 

reduction of title IV allowances 

allocated to units in the CAIR States for 

SO2 control. The regionwide annual SO2

budget for the years 2010–2014 is based 

on a 50 percent reduction from title IV 

allocations for all units in affected 

States. 

In the NPR and SNPR, EPA also 

proposed calculating annual State SO2

budgets based on each State’s 

allowances under title IV of the 1990 

CAA Amendments. We are finalizing 

this proposed approach for determining 

State annual SO2 budgets. 

State annual budgets for the years 

2010–2014 (Phase I) are based on a 50 

percent reduction from title IV 

allocations for all units in the affected 

State. The State annual budget for 2015 

and beyond (Phase II) is based on a 65 

percent reduction of title IV allowances 

allocated to units in the affected State 

for SO2 control. 

Some commenters criticized EPA’s 

basing State budgets on title IV 

allocations since these were based 

largely on 1985–1987 historic heat input 

data. Commenters argue that the initial 

allocation was not equitable and that in 

any event, the electric power sector has 

changed significantly. They conclude 

that State budgets should reflect those 

differences. Commenters have also 

commented that tying SO2 allocations to 

title IV also does not let States account 

for units that are exempt from title IV 

or for new units that have come online 

since 1990. 

While acknowledging these concerns, 

EPA believes, for a number of reasons, 

that setting State budgets according to 

title IV allowances represents a 

reasonable approach. 

The EPA believes that basing budgets 

on title IV allowances is necessary in 

order to ensure the preservation of a 

viable title IV program, which is 

important for reasons discussed in 

section IX of this preamble. Such 

reasons include the desire to maintain 

the trust and confidence that has 

developed in the functioning market for 

title IV allowances. The EPA believes it 

is important not to undermine such 

confidence (which is an essential 

underpinning to a viable market-based 

system) recognizing that it is a key to 

the success of a trading program under 

the CAIR. 

The title IV program represents a 

logical starting point for assessing 

emissions reductions for SO2, since it is 

the current effective cap on SO2

emissions for Acid Rain units, which 

make up the large majority of affected 

EGU CAIR units. It is from this starting 

emissions cap, that further CAIR 

reductions are required. Consequently, 

EPA proposes State-level reductions 

based on reductions from the initial 

allocations of title IV allowances to 

individual units at sources (power 

plants) in States covered by the CAIR. 

The setting of SO2 budgets differs 

from the setting of NOX budgets for the 

CAIR, in part, because of this difference 

in starting points—since there is no 

existing NOX regional annual cap, and 

no currency for emissions, on which 

sources rely. Furthermore, Congress, as 

part of title IV of the CAA, decided 

upon the allocations of title IV 

allowances specifically for the control of 

SO2, and not for NOX. 

Moreover, Congress decided to 

allocate title IV allowances in 

perpetuity, realizing that the electricity 

sector would not remain static over this 

time period. Congress clearly did not 

choose a policy to regularly revisit and 

revise these allocations, believing that 

its allocations methodology for title IV 

allowances would be appropriate for 

future time periods. 

The EPA realizes, putting aside 

concerns of linkage to title IV, that there 

are numerous potential methodologies 

of dividing up the regional budgets 

among the States. Also, EPA believes, 

that while initial allocations of State 

budgets are important for distributional 

reasons, under a cap and trade system, 

they would not impact the attainment of 

the environmental objectives or the 

overall cost of this rule.

Each of the alternate methods also has 

certain shortcomings, many of which 

have been identified by commenters. 

Basing allowances on historic 

emissions, for instance, would penalize 

25230 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

States that have already gone through 

significant efforts to clean up their 

sources. Basing allowances on heat 

input has advantages, but cannot 

accommodate States that have worked 

to improve their energy efficiency. 

Basing allowances on output would 

provide gas-fired units with many more 

allowances than they need, rather than 

giving them to the coal-fired units that 

will be incurring the greatest costs from 

the tighter caps. 

The EPA did look at a number of 

allowance outcomes using alternate 

potential methods for allocating SO2

allowances. These methods included 

allocating on the basis of historic 

emissions, heat input (with alternatives 

based on heat input from all fossil 

generation, and heat input from coaland oil-fired generation only) and 

output (with alternatives based on all 

generation and all fossil-fired 

generation). Allocating allowances 

based on title IV yields results that fall 

within a reasonable range of results 

obtained from using these alternate 

methodologies. In fact, calculating State 

budgets using title IV allowances yields 

budgets generally at or within the ranges 

of budgets calculated using the other 

methods in more than two-thirds of the 

States, which account for over 85 

percent of the total heat input in the 

region from 1999–2002. This analysis is 

discussed further in the response to 

comments document. 

b. Final SO2 State Emission Budget 

Methodology 

The EPA is finalizing the budgets as 

noted in the SNPR, adjusting for the 

proper inclusion of States covered 

under the final CAIR. The final State 

budgets are included in Table V–1 

below. Details of the data and 

methodology used to calculate these 

budgets are included in the 

accompanying ‘‘Regional and State SO2

and NOX Emissions Budgets’’ Technical 

Support Document.

TABLE V–1.—FINAL ANNUAL ELECTRIC

GENERATING UNITS SO2 BUDGETS

[Tons] 

State 

State SO2

budget 

2010*

State SO2

budget 

2015**

Alabama ............ 157,582 110,307 

District of Columbia ............ 708 495 

Florida ............... 253,450 177,415 

Georgia ............. 213,057 149,140 

Illinois ................ 192,671 134,869 

Indiana .............. 254,599 178,219 

Iowa .................. 64,095 44,866 

Kentucky ........... 188,773 132,141 

Louisiana .......... 59,948 41,963 

TABLE V–1.—FINAL ANNUAL ELECTRIC

GENERATING UNITS SO2 BUDGETS—Continued

[Tons] 

State 

State SO2

budget 

2010*

State SO2

budget 

2015**

Maryland ........... 70,697 49,488 

Michigan ........... 178,605 125,024 

Minnesota ......... 49,987 34,991 

Mississippi ........ 33,763 23,634 

Missouri ............ 137,214 96,050 

New York .......... 135,139 94,597 

North Carolina .. 137,342 96,139 

Ohio .................. 333,520 233,464 

Pennsylvania .... 275,990 193,193 

South Carolina .. 57,271 40,089 

Tennessee ........ 137,216 96,051 

Texas ................ 320,946 224,662 

Virginia .............. 63,478 44,435 

West Virginia .... 215,881 151,117 

Wisconsin ......... 87,264 61,085 

Total ........... 3,619,196 2,533,434 

*

Annual budget for SO2 tons covered by allowances for 2010–2014. **Annual budget for SO2 tons covered by allowances for 2015 and thereafter. 

c. Use of SO2 Budgets 

These specific levels of the proposed 

State budgets would actually provide 

binding statewide caps on EGU 

emissions for States that choose to 

control only EGUs but do not want to 

participate in the trading program. For 

States choosing to participate in the 

trading program, these State budgets 

would not be binding, instead, the 

States’ SO2 reductions would be 

achieved solely through the application 

of required retirement ratios as 

discussed in section VII of this 

preamble. For States controlling both 

EGUs and non-EGUs (or controlling 

only non-EGUs), these State budgets 

would be used to calculate the 

emissions reductions requirements for 

non-EGUs and the remaining reduction 

requirement for EGUs. This is described 

in more detail in the section VII 

discussion on SIP approvability.

2. NOX Annual Emissions Budgets 

a. Overview 

In this section, EPA discusses the 

apportioning of regionwide NOX annual 

emission reduction requirements or 

budgets to the individual States. In the 

January 2004 proposal, we proposed 

State EGU annual NOX budgets based on 

each State’s average share of recent 

historic heat input. In the SNPR, we 

proposed the same input-based 

methodology, but revised the budgets 

based on more complete heat input data. 

Also, EPA took comment on an 

alternative methodology that determines 

State budgets by multiplying heat input 

data by adjustment factors for different 

fuels. In the August NODA, EPA 

presented the corrected annual NOX

budgets resulting from the improved 

methodology proposed in the SNPR. 

b. State Annual NOX Emissions Budget 

Methodology 

Proposed and Discussed NOX Emission 

Budget Methodology 

As noted elsewhere in today’s 

preamble, EPA determined historical 

annual heat input data for Acid Rain 

Program units in the applicable States 

and multiplied by 0.15 lb/mmBtu (for 

2009) and 0.125 lb/mmBtu (for 2015) to 

determine total annual NOX regionwide 

budgets for the CAIR region. The EPA 

applied these rates to each individual 

State’s total highest annual heat input 

for any year from 1999 through 2002. 

Thus, EPA used the heat input total for 

the year in which a State’s total heat 

input was the highest. 

In the January 2004 proposal, we 

proposed annual NOX State budgets for 

a 28-State (and D.C.) region based on 

each jurisdiction’s average heat input—

using heat input data from Acid Rain 

Program units—over the years 1999 

through 2002. We summed the average 

heat input from each of the applicable 

jurisdictions to obtain a regional total 

average annual heat input. Then, each 

State received a pro rata share of the 

regional NOX emissions budget based on 

the ratio of its average annual heat input 

to the regional total average annual heat 

input. 

In the SNPR, EPA proposed to revise 

its determination of State NOX budgets 

by supplementing Acid Rain Program 

unit data with annual heat input data 

from the U.S. Energy Information 

Administration (EIA), for the non-Acid 

Rain unit data. A number of 

commenters had suggested that this 

would better reflect the heat input of the 

units that will be controlled under the 

CAIR, and EPA agrees. 

In the SNPR, EPA asked for, and 

subsequently received, comments on 

determining State budgets by 

multiplying heat input data by 

adjustment factors for different fuels. 

The factors would reflect the inherently 

higher emissions rate of coal-fired units, 

and consequently the greater burden on 

coal units to control emissions. 

Today’s Rule 

As noted earlier in the case of SO2, 

EPA recognizes that the choice of 

method in setting State budgets, with a 

given regionwide total annual budget, 

makes little difference in terms of the 

levels of resulting regionwide annual 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25231

88States receiving larger budgets under this 

approach are generally expected to be those having 

to make the most reductions.

89With a methodology similar to that used in the 

NOX SIP Call, annual State NOX budgets would be 

set by using a base heat input data, then adjusting 

it by a calculated growth rate for each jurisdiction’s 

annual EGU heat inputs.

SO2 and NOX emissions reductions. If 

States choose to control EGUs and 

participate in the cap and trade 

program, allowances could be freely 

traded, encouraging least-cost 

compliance over the entire region. In 

such a case, the least-cost outcome 

would not depend on the relative levels 

of individual State budgets. 

A number of commenters have stated, 

without supporting analysis or 

evidence, that budgets based on heat 

input, (and particularly those that 

would use different fuel factors) do not 

encourage efficiency. Economic theory 

indicates that neither a heat input, nor 

an output-based approach, if allocated 

once and based on a historical baseline, 

would provide any incentives for more 

or less efficient generation (changes in 

future behavior would have no impact 

on allocations). The cap and trade 

system itself, regardless of how the 

allowances are distributed, provides the 

primary incentive for more efficient, 

cleaner generation of electricity. 

The EPA is finalizing an approach of 

calculating State budgets through a fueladjusted heat-input basis. State budgets 

would be determined by multiplying 

historic heat input data (summed by 

fuel) by different adjustment factors for 

the different fuels. These factors reflect 

for each fuel (coal, gas and oil), the 

1999–2002 average emissions by State, 

summed for the CAIR region, divided by 

average heat input by fuel by State, 

summed for the CAIR region. The 

resulting adjustment factors from this 

calculation are 1.0 for coal, 0.4 for gas 

and 0.6 for oil. The factors would reflect 

the inherently higher emissions rate of 

coal-fired plants, and consequently the 

greater burden on coal plants to control 

emissions. 

Such an approach provides States 

with allowances more in proportion 

with their historical emissions. It 

provides for a more equitable budget 

distribution by recognizing that 

different States are facing the reduction 

requirements with different starting 

stocks of generation, with different 

starting emission profiles.88 The fuel 

burned is a key factor in differentiating 

the generation.

However, this approach is not 

equivalent to an approach based strictly 

on historical emissions (which would 

give fewer allowances to States which 

have already cleaned up their coal 

plants). Under the approach we are 

finalizing today, heat input from all 

coal, whether clean or uncontrolled, 

would be counted equally in 

determining State budgets. Likewise, all 

heat input from gas, whether clean or 

uncontrolled, from a steam-gas unit or 

from a combined-cycle plant, would be 

counted equally in determining State 

budgets. 

It is not expected that this decision 

would disadvantage States with 

significant gas-fired generation. One 

reason is that the calculation of the 

adjusted heat input for natural gas 

generation generally includes significant 

historic heat input and emissions from 

older, less efficient and dirtier steam gas 

units. These units’ capacity factors are 

declining and are expected to decline 

further over time as new, cleaner and 

more efficient combined-cycle gas units 

increase their generation.

It is important to note that the 

methodology by which the NOX State 

budgets are determined need not be 

used by individual States in 

determining allocations to specific 

sources. As discussed in section VIII of 

this document (Model Trading Rule), 

EPA is offering States the flexibility to 

allocate allowances from their budgets 

as they see fit. 

Finally, EPA discussed in the January 

2004 proposal, a methodology used in 

the NOX SIP Call (67 FR 21868) that 

applied State-specific growth rates for 

heat input in setting State budgets.89

The EPA, in the SNPR, noted that it is 

not proposing to use this method for the 

CAIR because we believe that other 

methods are reasonable, and that 

methods involving State-specific growth 

rates present certain challenges due to 

the inherent difficulties in predicting 

State-specific growth in heat input over 

a lengthy period, especially for 

jurisdictions that are only a part of a 

larger regional electric power dispatch 

region. Several commenters stated their 

support for incorporating growth, 

believing that not taking growth into 

account would penalize States with 

higher growth. However, a significant 

number of commenters stated their 

opposition to using growth in setting 

State budgets, noting the problems that 

arose in the NOX SIP Call. The EPA 

believes that setting budgets using a 

heat input approach, without a growth 

adjustment, is fair, would be simpler 

and would involve less risk of resulting 

litigation.

c. Final Annual State NOX Emission 

Budgets 

The final annual State NOX emission 

budgets following this method are 

included in Table V–2 below. Details of 

the numbers and methodology used to 

calculate these budgets are included in 

the ‘‘Regional and State SO2 and NOX

Emissions Budgets’’ Technical Support 

Document.

TABLE V–2.—FINAL ANNUAL ELECTRIC

GENERATING UNITS NOX BUDGETS

[Tons] 

State 

State NOX

budget 

2009*

State NOX

budget 

2015**

Alabama ............ 69,020 57,517

District of Columbia ............ 144 120

Florida ............... 99,445 82,871

Georgia ............. 66,321 55,268

Illinois ................ 76,230 63,525

Indiana .............. 108,935 90,779

Iowa .................. 32,692 27,243

Kentucky ........... 83,205 69,337

Louisiana .......... 35,512 29,593

Maryland ........... 27,724 23,104

Michigan ........... 65,304 54,420

Minnesota ......... 31,443 26,203

Mississippi ........ 17,807 14,839

Missouri ............ 59,871 49,892

New York .......... 45,617 38,014

North Carolina .. 62,183 51,819

Ohio .................. 108,667 90,556

Pennsylvania .... 99,049 82,541

South Carolina .. 32,662 27,219

Tennessee ........ 50,973 42,478

Texas ................ 181,014 150,845

Virginia .............. 36,074 30,062

West Virginia .... 74,220 61,850

Wisconsin ......... 40,759 33,966

Total ........... 1,504,871 1,254,061

*

Annual budget for NOX tons covered by allowances for 2009–2014. **Annual budget for NOX tons covered by allowances for 2015 and thereafter. 

d. Use of Annual NOX Budgets 

These proposed State budgets would 

serve as effective binding caps on State 

emissions, if States chose to control 

only EGUs, but did not want to 

participate in the trading program. For 

States controlling both EGUs and nonEGUs (or controlling only non-EGUs), 

these budgets would be compared to a 

baseline level of emissions to calculate 

the emissions reductions requirements 

for non-EGUs and the required caps for 

EGUs. This process is described in more 

detail in the section VII discussion on 

SIP approvability. 

e. NOX Compliance Supplement Pool 

As is discussed in section I, EPA is 

establishing a NOX compliance 

supplement pool of 198,494 tons, which 

would result in a total compliance 

supplement pool of approximately 

200,000 tons of NOX when combined 

with EPA’s proposed rulemaking to 

include Delaware and New Jersey. The 

25232 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

EPA is apportioning the compliance 

supplement pool to States based on the 

assumption that a State’s need for 

allowances from the pool is 

proportional to the magnitude of the 

State’s required emissions reductions 

(as calculated using the State’s base case 

emissions and annual NOX budget). The 

EPA is apportioning the 200,000 tons of 

NOX on a pro-rata basis, based on each 

State’s share of the total emissions 

reductions requirement for the region in 

2009. This is consistent with the 

methodology used in the NOX SIP Call. 

Table V–3 presents each State’s 

compliance supplement pool.

TABLE V–3.—STATE NOX COMPLIANCE SUPPLEMENT POOLS

[Tons] 

State 

Base case 

2009

emissions 

2009 State 

annual NOX

budget 

Reduction 

requirement 

Compliance 

supplement 

pool *

Alabama ........................................................................................................................... 132,019 69,020 62,999 10,166

District of Columbia ......................................................................................................... 0 144 0 0

Florida .............................................................................................................................. 151,094 99,445 51,649 8,335

Georgia ............................................................................................................................ 143,140 66,321 76,819 12,397

Illinois ............................................................................................................................... 146,248 76,230 70,018 11,299

Indiana ............................................................................................................................. 233,833 108,935 124,898 20,155

Iowa ................................................................................................................................. 75,934 32,692 43,242 6,978

Kentucky .......................................................................................................................... 175,754 83,205 92,549 14,935

Louisiana .......................................................................................................................... 49,460 35,512 13,948 2,251

Maryland .......................................................................................................................... 56,662 27,724 28,938 4,670

Michigan ........................................................................................................................... 117,031 65,304 51,727 8,347

Minnesota ........................................................................................................................ 71,896 31,443 40,453 6,528

Mississippi ........................................................................................................................ 36,807 17,807 19,000 3,066

Missouri ............................................................................................................................ 115,916 59,871 56,045 9,044

New York ......................................................................................................................... 45,145 45,617 0 0

North Carolina .................................................................................................................. 59,751 62,183 0 0

Ohio ................................................................................................................................. 263,814 108,667 155,147 25,037

Pennsylvania .................................................................................................................... 198,255 99,049 99,206 16,009

South Carolina ................................................................................................................. 48,776 32,662 16,114 2,600

Tennessee ....................................................................................................................... 106,398 50,973 55,425 8,944

Texas ............................................................................................................................... 185,798 181,014 4,784 772

Virginia ............................................................................................................................. 67,890 36,074 31,816 5,134

West Virginia .................................................................................................................... 179,125 74,220 104,905 16,929

Wisconsin ......................................................................................................................... 71,112 40,759 30,353 4,898

CAIR region subtotal ................................................................................................ .................... .................... .................... 198,494

Delaware .......................................................................................................................... 9,389 4,166 5,223 843

New Jersey ...................................................................................................................... 16,760 12,670 4,090 660

Total .......................................................................................................................... .................... .................... .................... 199,997

* Rounding to the nearest whole allowance results in a total compliance supplement pool of 199,997 tons. 

B. What Is the Approach for Setting 

State-by-State Emissions Reductions 

Requirements and EGU Budgets for 

States With NOX Ozone Season 

Reduction Requirements? 

1. States Subject to Ozone-Season 

Requirements 

In the NPR, EPA proposed that 

Connecticut contributes significantly to 

ozone nonattainment in another State, 

but not to fine particle nonattainment. 

As a result of subsequent air quality 

modeling, EPA has also found that 

Massachusetts, New Jersey, Delaware 

and Arkansas contribute significantly to 

ozone nonattainment in another State, 

but not to fine particle nonattainment. 

In this final rule, EPA is establishing a 

regionwide ozone-season budget for all 

States that contribute significantly to 

ozone nonattainment in another State, 

regardless of their contribution to fine 

particle nonattainment. The following 

25 States, plus the District of Columbia, 

are found to contribute significantly to 

ozone nonattainment: Alabama, 

Arkansas, Connecticut, Delaware, 

Florida, Illinois, Indiana, Iowa, 

Kentucky, Louisiana, Maryland, 

Massachusetts, Michigan, Mississippi, 

Missouri, New Jersey, New York, North 

Carolina, Ohio, Pennsylvania, South 

Carolina, Tennessee, Virginia, West 

Virginia, and Wisconsin. 

These States are subject to an ozone 

season NOX cap, which covers the 5 

months of May through September. The 

EPA is calculating the ozone season cap 

level for the 25 States plus the District 

of Columbia region by multiplying the 

region’s ozone season heat input by 0.15 

lb/mmBtu for 2009 and 0.125 lb/mmBtu 

for 2015. Heat input for the region was 

estimated by looking at reported ozone 

season Acid Rain heat inputs for each 

State for the years 1999 through 2002, 

and selecting the single year highest 

heat input for each State as a whole. 

As is the case for the annual NOX

State Budgets, EPA is finalizing an 

approach of calculating ozone season 

NOX State budgets through a fueladjusted heat input basis. State budgets 

would be determined by multiplying 

State-level average historic ozoneseason heat input data (summed by fuel) 

by different adjustment factors for the 

different fuels (1.0 for coal, 0.4 for gas, 

and 0.6 for oil). The total ozone season 

State budgets are then determined by 

calculating each State’s share of total 

fuel-adjusted heat input, and 

multiplying this share by the 

regionwide budget. 

The budgets for these States in 2009 

and 2015 are included in Table V–4 

below.

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25233

TABLE V–4.—FINAL SEASONAL ELECTRICITY GENERATING UNIT NOX

BUDGETS

[Tons] 

State 

State NOX

budget 

2009 *

State NOX

budget 

2015 **

Alabama ............ 32,182 26,818

Arkansas ........... 11,515 9,596

Connecticut ....... 2,559 2,559

Delaware ........... 2,226 1,855

District of Columbia ............ 112 94

Florida ............... 47,912 39,926

Illinois ................ 30,701 28,981

Indiana .............. 45,952 39,273

Iowa .................. 14,263 11,886

Kentucky ........... 36,045 30,587

Louisiana .......... 17,085 14,238

Maryland ........... 12,834 10,695

Massachusetts .. 7,551 6,293

Michigan ........... 28,971 24,142

Mississippi ........ 8,714 7,262

Missouri ............ 26,678 22,231

New Jersey ....... 6,654 5,545

New York .......... 20,632 17,193

North Carolina .. 28,392 23,660

Ohio .................. 45,664 39,945

Pennsylvania .... 42,171 35,143

South Carolina .. 15,249 12,707

Tennessee ........ 22,842 19,035

Virginia .............. 15,994 13,328

West Virginia .... 26,859 26,525

Wisconsin ......... 17,987 14,989

Total ........... 567,744 484,506

* Seasonal budget for NOX tons covered by 

allowances for 2009–2014. For States that 

have lower EGU budgets under the NOX SIP 

Call than their 2009 CAIR budget, table V–4 

includes their SIP Call budget. For Connecticut, the NOX SIP Call budget is also used 

for 2015 and beyond. 

** Seasonal budget for NOX tons covered by 

allowances for 2015 and thereafter. 

VI. Air Quality Modeling Approach and 

Results 

Overview 

In this section we summarize the air 

quality modeling approach used for the 

proposed rule, we address major 

comments on the fundamental aspects 

of EPA’s proposed approach, and we 

describe the updated and improved 

approach, based on those comments, 

that we are finalizing today. This 

section also contains the results of 

EPA’s final air quality modeling, 

including: (1) Identifying the future 

baseline PM2.5 and 8-hour ozone 

nonattainment counties in the East; (2) 

quantifying the contribution from 

emissions in upwind States to 

nonattainment in these counties; (3) 

quantifying the air quality impacts of 

the CAIR reductions on PM2.5 and 8-

hour ozone; and (4) describing the 

impacts on visibility in Class I areas of 

implementing CAIR compared to 

implementing the regional haze 

requirement for best available retrofit 

technology (BART). 

We present the air quality models, 

model configuration, and evaluation; 

and then the emissions inventories and 

meteorological data used as inputs to 

the air quality models. Next, we provide 

the updated interstate contributions for 

PM2.5 and 8-hour ozone and those States 

that make a significant contribution to 

downwind nonattainment, before 

considering cost. Finally, we present the 

estimated impacts of the CAIR 

emissions reductions on air quality and 

visibility. As described below, our air 

quality modeling for today’s rule 

utilizes the Community Multiscale Air 

Quality (CMAQ) model in conjunction 

with 2001 meteorological data for 

simulating PM2.5 concentrations and 

associated visibility effects and the 

Comprehensive Air Quality Model with 

Extensions (CAMx) with meteorological 

data for three episodes in 1995 for 

simulating 8-hour ozone concentrations. 

Our approach to modeling both PM2.5

and 8-hour ozone involves applying 

these tools (i.e., CMAQ for PM2.5 and 

CAMx for 8-hour ozone) using updated 

emissions inventory data for 2001, 2010, 

and 2015 to project future baseline 

concentrations, interstate transport, and 

the impacts of CAIR on projected 

nonattainment of PM2.5 and 8-hour 

ozone. We provide additional 

information on the development of our 

updated CAIR air quality modeling 

platform, the modeling analysis 

techniques, model evaluation, and 

results for PM2.5 and 8-hour ozone 

modeling in the CAIR Notice of Final 

Rulemaking Emissions Inventory 

Technical Support Document (NFR 

EITSD) and the Air Quality Modeling 

Technical Support Document (NFR 

AQMTSD). 

A. What Air Quality Modeling Platform 

Did EPA Use? 

1. Air Quality Models 

a. The PM2.5 Air Quality Model and 

Evaluation 

Overview 

In the NPR, we used the Regional 

Model for Simulating Aerosols and 

Deposition (REMSAD) as the tool for 

simulating base year and future 

concentrations of PM2.5. Like most 

photochemical grid models, the 

predictions of REMSAD are based on a 

set of atmospheric specie mass 

continuity equations. This set of 

equations represents a mass balance in 

which all of the relevant emissions, 

transport, diffusion, chemical reactions, 

and removal processes are expressed in 

mathematical terms. The modeling 

domain used for this analysis covers the 

entire continental United States and 

adjacent portions of Canada and 

Mexico. 

The EPA applied REMSAD for an 

annual simulation using meteorology 

and emissions for 1996. We used the 

results of this 1996 Base Year model run 

to evaluate how well the modeling 

system (i.e., the air quality model and 

input data sets) replicated measured 

data over the time period and domain 

simulated. We performed a model 

evaluation for PM2.5 and speciated 

components (e.g., sulfate, nitrate, 

elemental carbon, organic carbon, etc.) 

as well as nitrate, sulfate and 

ammonium wet deposition, and 

visibility. The evaluation used available 

1996 ambient measurements paired 

with REMSAD predictions 

corresponding to the location and time 

periods of the measured data. We 

quantified model performance using 

various statistical and graphical 

techniques. Additional information on 

the model evaluation procedures and 

results are included in the Notice of 

Proposed Rulemaking Air Quality 

Modeling Technical Support Document 

(NPR AQMTSD).

The EPA received numerous 

comments on various elements of the 

proposed PM2.5 air quality modeling 

approach. The major comments are 

responded to below. Other comments 

are addressed the Response to Comment 

(RTC) document. Regarding REMSAD, 

commenters argued that: (1) The 

REMSAD model is an inappropriate tool 

for modeling PM2.5; (2) the scientific 

formulation of the model is simplistic 

and outdated and that other models 

with better science are available and 

should be used; and (3) results from 

REMSAD are directionally correct but 

better tools should be used as the basis 

for the final determinations on transport 

and projected nonattainment. 

We agree that models with more 

refined science are available for PM2.5

modeling and we have selected one of 

these models, the CMAQ as the tool for 

PM2.5 modeling for the final CAIR. The 

CMAQ model is a publicly available, 

peer-reviewed, state-of-the-science 

model with a number of science 

attributes that are critical for accurately 

simulating the oxidant precursors and 

non-linear organic and inorganic 

chemical relationships associated with 

the formation of sulfate, nitrate, and 

organic aerosols. Several of the 

important science aspects of CMAQ that 

are superior to REMSAD include: (1) 

Updated gaseous/heterogeneous 

chemistry that provides the basis for the 

formation of nitrates and includes a 

25234 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

90Even so, EPA acknowledges that REMSAD has 

certain limitations not found in CMAQ.

91Whitten, G. memorandum: Comparison of 

REMSAD Reduced Chemistry to Full CB–4. 

February 19, 2001.

current inorganic nitrate partitioning 

module; (2) in-cloud sulfate chemistry, 

which accounts for the non-linear 

sensitivity of sulfate formation to 

varying pH; (3) a state-of-the-science 

secondary organic aerosol module that 

includes a more comprehensive gasparticle partitioning algorithm from 

both anthropogenic and biogenic 

secondary organic aerosol; and (4) the 

full CB–IV chemistry mechanism, which 

provides a complete simulation of 

aerosol precursor oxidants. 

However, even though REMSAD does 

not have all the scientific refinements of 

CMAQ, we believe that REMSAD treats 

the key physical and chemical processes 

associated with secondary aerosol 

formation and transport. Thus, we 

believe that the conclusions based on 

the proposal modeling using REMSAD 

are valid and therefore support today’s 

findings based only on CMAQ that: (1) 

There will be widespread PM2.5

nonattainment in the eastern U.S. in 

2010 and 2015 absent the reductions 

from CAIR; (2) upwind States in the 

eastern part of the United States 

contribute to the PM2.5 nonattainment 

problems in other downwind States; (3) 

States with high emissions tend to 

contribute more than States with low 

emissions; (4) States close to 

nonattainment areas tend to contribute 

more than other States farther upwind; 

and (5) the CAIR controls will produce 

major benefits in terms of bringing areas 

into or closer to attainment. 

Comments and Responses

(i) REMSAD Science and Evaluation 

Comment: Some commenters stated 

that REMSAD is an inappropriate model 

for use in simulating PM2.5. Other 

commenters said, more specifically, that 

the chemical mechanism in REMSAD 

(i.e., micro CB–IV) is simplified and not 

validated, and that the model has not 

been scientifically peer-reviewed. 

Response: The EPA disagrees with 

comments claiming that REMSAD is an 

inappropriate tool for modeling PM2.5. 

The EPA believes that REMSAD is 

appropriate for regional and national 

modeling applications because the 

model does include the key physical 

and chemical processes associated with 

secondary aerosol formation and 

transport.90

Specifically, REMSAD simulates both 

gas phase and aerosol chemistry. The 

gas phase chemistry uses a reducedform version of Carbon Bond chemical 

mechanism (micro-CB–IV). Formation of 

inorganic secondary particulate species, 

such as sulfate and nitrate, are 

simulated through chemical reactions 

within the model. Aerosol sulfate is 

formed in both the gas phase and the 

aqueous phase. The REMSAD model 

also accounts for the production of 

secondary organic aerosols through 

chemistry processes involving volatile 

organic compounds (VOC) and directly 

emitted organic particles. Emissions of 

non-reactive particles (e.g., elemental 

carbon) are treated as inert species 

which are advected and deposited 

during the simulation. 

With regard to comments on the 

micro CB–IV chemical mechanism, 

although this mechanism treats fewer 

organic carbon species compared to the 

full CB–IV, the inorganic portion of the 

reduced mechanism is identical to the 

full chemical mechanism. The intent of 

the CB–IV mechanism is to: (a) Provide 

a faithful representation of the linkages 

between emissions of ozone precursor 

species and secondary aerosol precursor 

species; (b) treat the oxidizing capacity 

of the troposphere, represented 

primarily by the concentrations of 

radicals and hydrogen peroxide; and (c) 

simulate the rate of oxidation of the 

nitrogen oxide (NOX) and sulfur dioxide 

(SO2), which are precursors to 

secondary aerosols. The EPA agrees that 

micro CB–IV is simplified compared to 

the full CB–IV mechanism. However, 

performance testing of micro CB–IV 

indicates that this simplified 

mechanism is similar to the full CB–IV 

chemical mechanism in simulating 

ozone formation and approximates other 

species reasonably well (e.g., hydroxyl 

radical, hydroperoxy radical, the 

operator radical, hydrogen peroxide, 

nitric acid, and peroxyacetyl nitrate).91

The REMSAD model was subjected to 

a scientific peer-review (Seigneur et al., 

1999) and EPA has incorporated the 

major science improvements that were 

recommended by the peer-review panel. 

These improvements were included in 

the version of REMSAD used for the 

NPR modeling. Specifically, the 

following updates have been 

implemented into REMSAD Version 

7.06, which was used for the proposed 

CAIR control strategy simulations: (1) 

The nighttime chemistry treatment was 

updated to improve the treatment of the 

gas phase species NO3 and N2O5; (2) the 

effects of temperature and pressure 

dependence on chemical rates were 

added; (3) the MARS–A aerosol 

partitioning module was added for 

calculating particle and gas phase 

fractions of nitrate; (4) aqueous phase 

formation of sulfate was updated by 

including reactions for oxidation of SO2

by ozone and oxygen, (5) peroxynitric 

acid (PNA) chemistry was added; and 

(6) a module for calculating biogenic 

and anthropogenic secondary organic 

aerosols was developed and integrated 

into REMSAD. We believe that these 

changes adequately respond to the peer 

review comments and have bolstered 

the scientific credibility of this model.

(ii) Use of CMAQ Instead of REMSAD 

for PM2.5 Modeling 

Comment: Some commenters claimed 

that REMSAD is outdated and that other 

models with more sophisticated science 

are available. Commenters said that EPA 

should utilize the best available science 

through use of the most comprehensive 

photochemical model for simulating 

aerosols. Commenters specifically stated 

that EPA should use more recently 

developed models such as the CMAQ 

model or the aerosol version of the 

Comprehensive Air Quality Model with 

Extensions (CAMX–PM). 

Response: The EPA agrees that 

photochemical models are now 

available that are more scientifically 

sophisticated than REMSAD. In this 

regard, and in response to commenters’

recommendations on specific models, 

EPA has selected CMAQ as the 

modeling tool for the final CAIR 

modeling analysis. As stated above, the 

CMAQ model is a publicaly available, 

peer-reviewed, state-of-the-science 

model with a number of science 

attributes that are critical for accurately 

simulating the oxidant precursors and 

non-linear organic and inorganic 

chemical relationships associated with 

the formation of sulfate, nitrate, and 

organic aerosols. As listed above, the 

important science aspects of CMAQ that 

are superior to REMSAD include: (1) 

Updated gaseous/heterogeneous 

chemistry that provides the basis for the 

formation of nitrates and includes a 

current inorganic nitrate partitioning 

module; (2) in-cloud sulfate chemistry, 

which accounts for the non-linear 

sensitivity of sulfate formation to 

varying pH; (3) a state-of-the-science 

secondary organic aerosol module that 

includes a more comprehensive gasparticle partitioning algorithm from 

both anthropogenic and biogenic 

secondary organic aerosol; and (4) the 

full CB–IV chemistry mechanism, which 

provides a complete simulation of 

aerosol precursor oxidants. 

(iii) Model Evaluation 

Comment: A number of commenters 

claimed that EPA’s air quality model 

evaluation for 1996 was deficient 

because it lacked sufficient ambient 

measurements, especially in urban 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25235

92The 2001 modeling platform is described in full 

in the NFR EITSD and NFR AQMTSD. 93For the purposes of this analysis, we have 

defined ‘‘East’’ as the area to the east of 100 degrees 

longitude, which runs from approximately the 

eastern half of Texas through the eastern half of 

North Dakota. 94These other modeling studies represent a wide 

range of modeling analyses which cover various 

models, model configurations, domains, years and/

or episodes, chemical mechanisms, and aerosol 

modules.

areas, to judge model performance. 

Commenters said that EPA should: (1) 

Update the evaluation to a more recent 

time period in order to take advantage 

of greatly expanded ambient PM2.5

species measurements, especially in 

urban areas; and (2) calculate model 

performance statistics over monthly 

and/or seasonal time periods using 

daily/weekly observed/model-predicted 

data pairs. 

Some commenters said that the 1996 

data were so limited that it is not 

possible to determine whether REMSAD 

could be used with confidence to assess 

the effects of emissions changes. Still, 

other commenters said that the 

performance of REMSAD for the 1996 

modeling platform was poor. 

Commenters acknowledged that there 

are no universally accepted or EPArecommended quantitative criteria for 

judging the acceptability of PM2.5 model 

performance. In the absence of such 

model performance acceptance criteria, 

some commenters said that performance 

should be judged by comparing EPA’s 

model performance results to the range 

of results obtained by other groups in 

the air quality modeling community 

who conducted other recent regional 

PM2.5 model applications. A few 

commenters also identified specific 

model performance ranges and criteria 

that they said should be achievable for 

sulfate and PM2.5, given the current 

state-of-science for aerosol modeling 

and measurement uncertainty. The 

specific values cited by these 

commenters are ±30 percent to ±50 

percent for fractional bias, 50 percent to 

75 percent for fractional error, and 50 

percent for normalized error. 

Response: The EPA agrees that the 

limited amount of ambient PM2.5 species 

data available in 1996 affected our 

ability to evaluate model performance, 

especially in urban areas, and there 

were deficiencies in the performance of 

REMSAD using the 1996 model inputs. 

Also, EPA agrees that a model 

evaluation should be performed for a 

more recent time period in order to 

address these concerns. Thus, we 

conclude that the 1996 modeling 

platform which includes 1996 

emissions, 1996 meteorology, and 1996 

ambient data should be updated and 

improved, as recommended by 

commenters. 

The EPA has developed a new 

modeling platform which includes 

emissions, meteorological data, and 

other model inputs for 2001. This 

platform was used to confirm the ability 

of our modeling system to replicate 

ambient PM2.5 and component species 

in both urban and rural areas and, thus, 

establish the credibility of this platform 

for PM2.5 modeling as part of CAIR.92 In 

2001, there was an extensive set of 

ambient PM2.5 measurements including 

133 urban Speciation Trends Network 

(STN) monitoring sites across the 

nation, with 105 of these in the East. 

This network did not exist in 1996. 

Also, the number of mainly suburban 

and rural monitoring sites in the Clean 

Air Status and Trends Network 

(CASTNET) and Interagency Monitoring 

of Protected Visual Environments 

(IMPROVE) network has increased to 

over 200 in 2001, compared to 

approximately 120 operating in 1996.

The EPA evaluated CMAQ for the 

2001 modeling platform using the 

extensive set of 2001 monitoring data 

for PM2.5 species. The evaluation 

included a statistical analysis in which 

the model predictions and 

measurements were paired in space and 

in time (i.e., daily or weekly to be 

consistent with the sampling protocol of 

the monitoring network). Model 

performance statistics were calculated 

for each network with separate statistics 

for sites in the West and the East.93 In 

response to comments that performance 

statistics should be calculated over 

monthly and/or seasonal time periods, 

we elected to use seasonal time periods 

in order to be consistent with our use 

of quarterly average PM2.5 species as 

part of the procedure for projecting 

future concentrations, as described 

below in section VI.B.1. In addition, the 

sampling frequency at the CASTNET, 

IMPROVE, and STN sites may not 

provide sufficient samples in a 1-month 

period to provide a robust calculation of 

model performance statistics. Details of 

EPA’s model evaluation for CMAQ 

using the 2001 modeling platform are in 

the report ‘‘Updated CMAQ Model 

Performance Evaluation for 2001’’

which can be found in the docket for 

today’s rule.

The EPA agrees that there are no 

universally accepted performance 

criteria for PM2.5 modeling and that 

performance should be judged by 

comparison to the performance found 

by other groups in the air quality 

modeling community. In this respect, 

we have compared our CMAQ 2001 

model performance results to the range 

of performance found in other recent 

regional PM2.5 model applications by 

other groups.94 Details of this 

comparison can be found in the CMAQ 

evaluation report. Below is a summary 

of performance results from other, nonEPA modeling studies, for summer 

sulfate and winter nitrate. It CAIR. 

Overall, the general range of fractional 

bias (FB) and fractional error (FE) 

statistics for the better performing 

model applications are as follows:

—Summer sulfate is in the range of ¥10 

percent to +30 percent for FB and 35 

percent to 50 percent for FE; and 

—Winter nitrate is in the range of +50 

percent to +70 percent for FB and 85 

percent to 105 percent for FE.

The corresponding performance 

statistics for EPA’s 2001 CMAQ 

application as well as the 1996 

REMSAD application used for the 

proposal modeling are provided in 

Table VI–1.

TABLE VI–1.—SELECTED PERFORMANCE EVALUATION STATISTICS FROM THE CMAQ 2001 SIMULATION AND THE

REMSAD 1996 SIMULATION

Eastern U.S. 

CMAQ 2001 REMSAD 1996 

FB(%) FE(%) FB(%) FE(%) 

Sulfate (Summer): 

STN ........................................................................................................................... 14 44 .................... ....................

Improve ..................................................................................................................... 10 42 ¥20 51 

CASTNet ................................................................................................................... 3 22 ¥21 59 

Nitrate (Winter) 

STN ........................................................................................................................... 15 73 .................... ....................

25236 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

95U.S. EPA, 2000: Draft Guidance for 

Demonstrating Attainment of the Air Quality Goals 

for PM2.5 and Regional Haze; Draft 1.1, Office of Air 

Quality Planning and Standards, Research Triangle 

Park, NC.

96U.S. EPA, 1999: Draft Guidance on the Use of 

Models and Other Analyses in Attainment 

Demonstrations for the 8-Hour Ozone NAAQS, 

Office of Air Quality Planning and Standards, 

Research Triangle Park, NC.

97 VISTAS Emissions and Air Quality Modeling—

Phase I Task 4cd Report: Model Performance 

Evaluation and Model Sensitivity Tests for Three 

Phase I Episodes. ENVIRON International 

Corporation, Alpine Geophysics, and University of 

California at Riverside, September 7, 2004.

TABLE VI–1.—SELECTED PERFORMANCE EVALUATION STATISTICS FROM THE CMAQ 2001 SIMULATION AND THE

REMSAD 1996 SIMULATION—Continued

Eastern U.S. 

CMAQ 2001 REMSAD 1996 

FB(%) FE(%) FB(%) FE(%) 

Improve ..................................................................................................................... 21 92 67 103 

The results indicate that the 

performance for CMAQ in 2001 is 

within the range or better than that 

found by other groups in recent 

applications. The performance also 

meets the benchmark goals suggested by 

several commenters. In addition, the 

CMAQ performance is considerably 

improved over that of the REMSAD 

1996 performance for summer sulfate 

and winter nitrate, which were near the 

bounds or outside the range of other 

recent applications. 

The CMAQ model performance 

results give us confidence that our 

applications of CMAQ using the new 

modeling platform provide a 

scientifically credible approach for 

assessing PM2.5 concentrations for the 

purposes of CAIR. 

b. Ozone Air Quality Modeling Platform 

and Model Evaluation

Overview 

The EPA used the CAMX, version 3.10 

in the NPR to assess 8-hour ozone 

concentrations and the impacts of ozone 

and ozone precursor transport on 

elevated levels of ozone across the 

eastern U.S. The CAMX is a publicly 

available Eulerian model that accounts 

for the processes that are involved in the 

production, transport, and destruction 

of ozone over a specified threedimensional domain and time period. 

The CAMX model was run with 1995/

96 base year emissions to evaluate the 

performance of the modeling platform to 

replicate observed concentrations 

during the three 1995 episodes. This 

evaluation was comprised principally of 

statistical assessments of hourly, 1-hour 

daily maximum, and 8-hour daily 

maximum ozone predictions. As 

described in the NPR AQMTSD, model 

performance of CAMX for ozone was 

judged against the results from previous 

regional ozone model applications. This 

analysis indicates that model 

performance was comparable to or 

better than that found in previous 

applications and is, therefore, 

acceptable for the purposes of CAIR 

ozone modeling. 

The EPA did not receive comments on 

the CAMX model or the model 

performance for ozone. The EPA did 

receive comments on the choice of 

episodes for ozone modeling, the 

meteorological data for these episodes, 

the spatial resolution of our modeling, 

and consistency between ozone and 

PM2.5 modeling in terms of methods for 

projecting future air quality 

concentrations. As described below and 

in the RTC document and NFR 

AQMTSD, we continue to believe that: 

(1) The three 1995 episodes are 

representative episodes for regional 

modeling of 8-hour ozone; and (2) the 

meteorological data for these episodes 

and spatial resolution are adequate for 

use in our modeling for CAIR. Thus, the 

ozone air quality assessments in today’s 

rule rely on CAMX modeling of 

meteorological data for the three 1995 

episodes for the domain and spatial 

resolution used for the NPR. As 

discussed below, we ran CAMX for the 

updated 2001 emissions inventory and 

the updated 2010 and 2015 base case 

inventories as part of the process to 

project 8-hour ozone for these future 

year scenarios. We revised our method 

of projecting future ozone 

concentrations to be consistent with the 

method we are using for PM2.5. 

c. Model Grid Cell Configuration 

As described in the NPR AQMTSD, 

the PM2.5 modeling for the proposal was 

performed for a domain (i.e., area) 

covering the 48 States and adjacent 

portions of Canada and Mexico. Within 

this domain, the model predictions were 

calculated for a grid network with a 

spatial resolution of approximately 36 

km. Our 8-hour ozone modeling for 

proposal was performed using a nested 

grid network. The outer portion of this 

grid has a spatial resolution of 

approximately 36 km. The inner 

‘‘nested’’ area, which covers a large 

portion of the eastern U.S., has a 

resolution of approximately 12 km. 

Comment: Some commenters said that 

the 36 km grid cell size used by EPA in 

modeling PM2.5 and the 36 km/12 km 

grid resolution used for ozone modeling 

are too coarse and are inconsistent with 

EPA’s draft modeling guidance. 

Response: We disagree with these 

comments and continue to believe that 

the grid dimensions for our PM2.5

modeling and our 8-hour ozone 

modeling are not too coarse nor are they 

inconsistent with our draft guidance 

documents for PM2.5 modeling 95 and 

ozone modeling.96 The draft guidance 

for PM2.5 modeling states that 36 km 

resolution is acceptable for regional 

scale applications in portions of the 

domain outside of nonattainment areas. 

For portions of the domain which cover 

nonattainment areas, 12 km resolution 

or less is recommended by the guidance. 

However, as stated in the guidance 

document, these recommendations were 

based on guidance for 8-hour ozone 

modeling because there was a lack of 

PM2.5 modeling at different grid 

resolutions at the time the guidance was 

drafted. In addition, the PM2.5 guidance 

states that exceptions to these 

recommendations can be made on a 

case-by-case basis.

For several reasons, we believe that 36 

km resolution is sufficient for PM2.5

modeling for the purposes of CAIR. 

First, recent analyses that compare 36 

km to 12 km modeling of PM2.5 97

indicate that spatial mean 

concentrations of gas phase and aerosol 

species at 36 km and 12 km are quite 

similar. A comparison of model 

predictions versus observations 

indicates that the model performance is 

similar at 12 km and 36 km in both rural 

and urban areas. Thus, using 12 km 

resolution does not necessarily provide 

any additional confidence in the results. 

Second, ambient measurements of 

sulfate and to a significant extent 

nitrate, which are the pollutants of most 

importance for CAIR, do not exhibit 

large spatial differences between rural 

and urban areas, as described elsewhere 

in today’s rule. This implies that it is 

not necessary to use fine resolution 

modeling in order to properly capture 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25237

98 Irwin, J. et al. ‘‘Examination of model 

predictions at different horizontal grid resolutions.’’

Submitted for Publication to Environmental Fluid 

Mechanics.

the regional concentration patterns of 

these pollutants.

Our draft 8-hour ozone modeling 

guidance recommends using 36 km 

resolution for regional modeling with 

nested grid cells not exceeding 12 km 

over urban portions of the modeling 

domain. The guidance states that 4 to 5 

km resolution for urban areas is 

preferred, if feasible. In addition, if 12 

km modeling is used then plume-in-grid 

treatment for large point sources of NOX

should be considered. 

Our modeling for CAIR is consistent 

with this guidance in that we use 36 km 

resolution for the outer portions of the 

region; 12 km resolution covering nearly 

all urban areas in the domain; and a 

plume-in-grid algorithm for major NOX

point sources in the region. In addition, 

analyses that compare model 12 km 

resolution to 4 km resolution for 

portions of our 1995 episodes indicate 

that the spatial fields predicted at both 

12 km and 4 km have many common 

features in terms of the areas of high and 

low ozone.98 In a comparison of model 

predictions to observation, the 12 km 

modeling was found to be somewhat 

more accurate than the finer 4 km 

modeling.

2. Emissions Inventory Data 

For the proposed rule, emissions 

inventories were created for the 48 

contiguous States and the District of 

Columbia. These inventories were 

estimated for a 2001 base year to reflect 

current emissions and for 2010 and 

2015 future baseline scenarios. The 

inventories were prepared for electric 

generating units (EGUs), industrial and 

commercial sources (non-EGUs), 

stationary area sources, on-road 

vehicles, and non-road engines. The 

inventories contained both annual and 

typical summer season day emissions 

for the following pollutants: oxides of 

nitrogen (NOX); volatile organic 

compounds (VOC); carbon monoxide 

(CO); sulfur dioxide (SO2); direct 

particulate matter with an aerodynamic 

diameter less than 10 micrometers 

(PM10) and less than 2.5 micrometers 

(PM2.5); and ammonia (NH3). A 

summary of the development of these 

inventories is provided below. 

Additional information on the 

emissions inventory used for proposal 

can be found in the NPR AQMTSD. 

Because the complete 2001 National 

Emission Inventory (NEI) and futureyear projections consistent with that 

NEI were not available in a form 

suitable for air quality modeling when 

needed for the proposal, we developed 

a reasonably representative ‘‘proxy’’

inventory for 2001. For the EGU, 

mobile, and non-road emissions sectors, 

1996-to-2001 adjustment ratios were 

created by dividing State-level total 

emissions for each pollutant for 2001 by 

the corresponding consistent 1996 

emissions. These adjustment ratios were 

then multiplied by the REMSAD-ready 

1996 emissions for these two sectors to 

produce REMSAD-ready files for the 

2001 proxy. For non-EGUs and 

stationary area sources, linear 

interpolations were performed between 

the REMSAD-ready 1996 emissions and 

the REMSAD-ready 2010 base case 

emissions to produce 2001 proxy 

emissions for these two sectors. Details 

on the creation of the 2001 proxy 

inventory used for proposal are 

provided in the NPR AQMTSD. 

The NPR future 2010 and 2015 base 

case emissions reflect projected 

economic growth and control programs 

that are to be implemented by 2010 and 

2015, respectively. Control programs 

included in these future base cases 

include those State, local, and Federal 

measures already promulgated and 

other significant measures expected to 

be promulgated before the final rule is 

implemented. Future year 2010 and 

2015 base case EGU emissions were 

obtained from versions 2.1 and 2.1.6 of 

the Integrated Planning Model (IPM). 

Comment: Several commenters stated 

that the emission inventory used for the 

‘‘proxy’’ 2001 base year was not 

sufficient for the rulemaking, primarily 

because it was developed from a 1996 

modeling inventory by applying various 

adjustment factors. Commenters 

suggested that: (1) More up-to-date 

inventories were now available and 

should be used; (2) the most recent 

Continuous Emissions Monitoring 

(CEM) data or throughput information 

should be used to derive a 2001 EGU 

inventory; and (3) EPA should use the 

2001 MOBILE6 and NONROAD2002 

models for estimating on-road mobile 

and non-road engine emissions, 

respectively. 

Response: The EPA believes that the 

base year for modeling should be as 

recent as possible, given the availability 

of nationally complete emissions 

estimates and ambient monitoring data. 

For the analyses of the final rule, EPA 

has used a base year inventory 

developed specifically for 2001. The 

base year inventory for the electric 

utility sector now uses measured CEM 

emissions data for 2001. The non-EGU 

point source and stationary-area source 

sectors are based on the final 1999 NEI 

data submittals from State, local, and 

Tribal air agencies. This inventory is the 

latest available quality-assured and 

reviewed national emission data set for 

these sectors. The 1999 data for nonEGU point and stationary-area sources 

were projected to represent a 2001 

inventory using State/county-specific 

and sector-specific growth rates. The onroad mobile inventory uses MOBILE 

version 6.2 and the non-road engines 

inventory uses the NONROAD2004 

model, both with updated input 

parameters to calculate emissions for 

2001. More detailed information on the 

development of the emissions 

inventories can be found in the NFR 

EITSD. 

Comment: Commenters stated that 

EPA failed to develop an accurate and 

comprehensive ammonia emission 

inventory from soil, fertilizer, and 

animal husbandry sources. 

Response: The 2001 inventory used 

for the analyses for the final rule 

includes a new national county-level 

ammonia inventory developed by EPA 

using the latest emission rates selected 

based on a comprehensive literature 

review, and activity levels as provided 

by the U.S. Census of Agriculture for 

animal husbandry. The 2001 inventory 

from fertilizer application sources was 

compiled from State and local 

submissions to EPA for 1999, 

augmented as necessary with EPA 

estimates, and grown to 2001 using 

State/county-specific and categoryspecific growth rates. With regard to 

background soil emissions of NH3, EPA 

believes that the current state of 

understanding of background soil 

ammonia releases and sinks is 

insufficient to warrant including these 

emission sources in modeling 

inventories at this time. 

Comment: Two commenters indicated 

that EPA should revise 2010 and 2015 

base case emissions by improving the 

methods for estimating economic 

growth and not rely on the Bureau of 

Economic Analysis (BEA) data used for 

proposal.

Response: In response to these 

comments, EPA has refined its 

economic growth projections. In 

addition to updated versions of the 

MOBILE6, NONROAD, and IPM models, 

EPA developed new economic growth 

rates for stationary, area, and non-EGU 

point sources. For these two sectors, the 

final approach uses a combination of: 

(1) Regional or national fuel-use forecast 

data from the U.S. Department of Energy 

for source types that map to fuel use 

sectors (e.g., commercial coal, industrial 

natural gas); (2) State-specific growth 

rates from the Regional Economic 

Model, Inc. (REMI) Policy Insight

model, version 5.5; and (3) forecasts by 

25238 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

99Environ, Enhanced Meteorological Modeling 

and Performance Evaluation for Two Texas Ozone 

Episodes. August 2001.

100Hogrefe, C. et al. ‘‘Evaluating the performance 

of regional-scale photochemical modeling systems: 

Part 1-meteorological predictions.’’ Atmospherics 

Environment, vol. 35 (2001), pp. 4159–4174.

specific industry organizations and 

Federal agencies. For more detail on the 

growth methodologies, please refer to 

the NFR EITSD. 

3. Meteorological Data 

In order to solve for the change in 

pollutant concentrations over time and 

space, the air quality model requires 

certain meteorological inputs that, in 

part, govern the formation, transport, 

and destruction of pollutant material. 

Two separate sets of meteorological 

inputs were used in the air quality 

modeling completed as part of the NPR. 

The meteorological input files for the 

proposal PM2.5 modeling were 

developed from a Fifth-Generation 

NCAR/Pennsylvania State Mesoscale 

Model (MM5) model simulation for the 

entire year of 1996. The gridded 

meteorological data for the three 1995 

ozone episodes were developed using 

the Regional Atmospheric Modeling 

System (RAMS). Both of these models 

are publicly-available, widely-used, 

prognostic meteorological models that 

solve the full set of physical and 

thermodynamic equations which govern 

atmospheric motions. Further, each of 

these specific meteorological data sets 

has been utilized in past EPA 

rulemaking modeling analyses (e.g., the 

Nonroad Land-based Diesel Engines 

Standards). 

Comment: Several commenters 

claimed that the 1996 meteorological 

modeling data used to support the fine 

particulate modeling were outdated and 

non-representative. We also received 

recommendations from commenters on 

benchmarks to be used as goals for 

judging the adequacy of meteorological 

modeling. 

Response: The EPA draft PM2.5

modeling guidance which provides 

general recommendations on 

meteorological periods to model for 

PM2.5 purposes lists three primary 

general criteria for consideration: (a) 

Variety of meteorological conditions; (b) 

existence of an extensive air quality/

meteorological data bases; and (c) 

sufficient number of days. The approach 

recommended in the guidance for 

modeling annual PM2.5 is to use a single, 

representative year. Based on the 

comments received and the criteria 

outlined in the guidance, EPA 

developed meteorological data for the 

entire calendar year of 2001. This year 

was chosen for the PM2.5 modeling 

platform based on several factors, 

specifically: (a) It corresponds to the 

most recent set of emissions data; (b) 

there are considerable ambient PM2.5

species data for use in model evaluation 

(as described in section VI.A.1., above); 

and (c) Federal Reference Method (FRM) 

PM2.5 data for this year are included in 

the calculation of the most recent PM2.5

design values used for designating PM2.5

nonattainment areas. In view of these 

factors, EPA believes that 2001 

meteorology are representative for PM2.5

modeling for the purposes of this rule. 

The new 2001 meteorological data 

used for PM2.5 modeling were derived 

from an updated version of the MM5 

model used for the 1996 meteorology 

used for proposal. The version of MM5 

used for the 2001 simulation contains 

more sophisticated physics options with 

respect to features like cloud 

microphysics and land-surface 

interactions, and more refined vertical 

resolution of the atmosphere compared 

to the version used for modeling 1996 

meteorology. While there are currently 

no universally accepted criteria for 

judging the adequacy of meteorological 

model performance, EPA compared the 

2001 MM5 model performance against 

the benchmark goals 99 recommended 

by some commenters. The benchmark 

goals suggest that temperature bias 

should be within the range of 

approximately ± 0.5 degrees C and 

errors less than or equal to 2.0 degrees 

C are typical.

In general, the model performance 

statistics for our 2001 meteorological 

modeling are in line with the above 

benchmark goals. Specfically, the mean 

temperature bias of our 2001 

meteorological modeling was 

approximately 0.6 degrees C and the 

mean error was approximately 2.0 

degrees C. The evaluation of the 2001 

MM5 for humidity (water vapor mixing 

ratio) shows biases of less than 0.5 g/kg 

and errors of approximately 1 g/kg, 

which compare favorably to the goals of 

± 1 g/kg for bias and 2 g/kg or less error. 

Model performance for winds in our 

2001 simulation was also improved 

compared to what has historically been 

found in MM5 modeling studies. The 

index of agreement for surface winds in 

the 2001 case equaled 0.86, which is far 

better than the benchmark goal of 0.60. 

The precipitation evaluation results 

show that the model generally replicates 

the observed data, but is overestimating 

precipitation in the summer months. 

More information about the model 

performance evaluation and the MM5 

configuration is provided in the NFR 

AQMTSD. 

Comment: Several groups criticized 

the lack of quantitative meteorological 

model evaluation data for the 1995 

RAMS meteorological modeling used for 

episodic ozone modeling. 

Response: A peer-reviewed, 

quantitative evaluation of the RAMS 

model performance for this 

meteorological period is provided by 

Hogrefe, et al.100 This analysis was 

performed using RAMS predictions for 

June through August of 1995. The 

results show that the RAMS biases and 

errors are generally in line with past 

meteorological model simulations by 

other groups outside EPA. The EPA 

remains satisfied that the 1995 RAMS 

meteorological inputs for the three 

CAMX ozone modeling episodes are of 

sufficient quality and we have 

continued to use these inputs for the 

ozone analyses for the final rule.

Comment: The EPA received several 

comments on the episodes selected for 

ozone modeling. There was general 

criticism that the ozone modeling did 

not follow EPA’s own guidance for the 

selection of episodes. Additionally, 

there was specific criticism that the 

episodes did not provide for a 

reasonable test of the 8-hour ozone 

NAAQS in some areas.

Response: The draft 8-hour ozone 

guidance recommends, at a minimum, 

that four criteria be used to select 

episodes which are appropriate to 

model. This guidance is generally 

intended for local attainment 

demonstrations, as opposed to regional 

transport analyses, but it does 

recommend that in applying a regional 

model one should choose episodes 

meeting as many of the criteria as 

possible, though it acknowledges there 

may be tradeoffs. Given the large 

number of nonattainment areas within 

the ozone domain, it would be 

extremely difficult to assess the criteria 

on a area-by-area basis. However, from 

a general perspective, the 1995 episodes 

address all of the primary criteria, 

which include: (1) A variety of 

meteorological conditions; (2) measured 

ozone values that are close to current air 

quality; (3) extensive meteorological and 

air quality data; and (4) a sufficient 

number of days. More detail is provided 

in the NFR AQMTSD, but here is a brief 

description of how each of the four 

primary criteria are met by the 1995 

cases. 

With regard to the criteria of 

meteorological variations, we have 

completed inert tracer simulations for 

each of the three 1995 episodes that 

show different transport patterns in all 

three cases. For example the June case 

involves east-to-west transport; the July 

case involves west-to-east transport; and 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25239

the August case involves south-to-north 

transport. In a separate analysis to 

determine whether the 1995 modeling 

days correspond to commonly occurring 

and ozone-conducive meteorology, EPA 

has applied a multi-variate statistical 

approach for characterizing daily 

meteorological patterns and 

investigating their relationship to 8-hour 

ozone concentrations in the eastern U.S. 

Across the 16 sites for which the 

analysis was completed, there were five 

to six distinct sets of meteorological 

conditions, called regimes, that 

occurred during the ozone seasons 

studied. An analysis of the 8-hour daily 

maximum ozone concentrations for each 

of the meteorological regimes was 

undertaken to determine the 

distribution of ozone concentrations and 

the frequency of occurrence of each 

regimes. The EPA determined that 

between 60 and 70 percent of the 

episode days we modeled are associated 

with the most frequently occurring, high 

ozone potential, meteorological regimes. 

These results also provide support that 

the episodes being modeled are 

representative of conditions present 

when high ozone concentrations are 

measured throughout the modeling 

domain. For the second criteria, EPA 

has completed an analysis which shows 

that the 1995 episodes contain observed 

8-hour daily maximum ozone values 

that approximate recent ambient 

concentrations over the eastern U.S. 

Additional analyses performed by EPA 

and others have concluded that each of 

the three episodes involves widespread 

areas of elevated ozone concentrations. 

The synoptic meteorological pattern of 

the July 1995 episode has been 

identified by one of the commenters as 

representing a classic set of conditions 

necessary for high ozone over the 

eastern U.S. While the ozone was not 

quite as widespread in the June and 

August 1995 episodes, these periods 

also contained exceedances of the 8-

hour ozone NAAQS in most portions of 

the region. 

We believe that there is ample 

meteorological and air quality data 

available to support an evaluation of the 

modeling for these episodes. 

Specifically, there were over 700 ozone 

monitors reporting across the domain 

for use in model evaluation. As noted 

above, the model performance for these 

episodes compares favorably to the 

recommendations in EPA’s urban 

modeling guidance. In addition, the 

modeling period is comprised of 30 

days, not including model ramp-up 

periods which is considerably more 

than is typically used in an attainment 

demonstration modeling submitted to 

EPA by a State. Finally, EPA’s draft 

ozone guidance also indicates as one of 

four secondary criteria that extra weight 

can be assigned to modeling episodes 

for which there is prior experience in 

modeling. The 1995 CAIR ozone 

episodes have been successfully used to 

drive the air quality modeling 

completed for several recent notice-andcomment rulemakings (Tier-2, Heavy 

Duty Engine, and NonRoad). Based on 

the analyses discussed above and the 

adherence to the modeling guidance, 

EPA is satisfied that the 1995 CAMX

episodes are appropriate for continued 

use. 

B. How Did EPA Project Future 

Nonattainment for PM2.5 and 8-Hour 

Ozone? 

1. Projection of Future PM2.5

Nonattainment 

a. Methodology for Projecting Future 

PM2.5 Nonattainment 

In the NPR, we assessed the prospects 

for future attainment and nonattainment 

in 2010 and 2015 of the PM2.5 annual 

NAAQS. The approach for identifying 

areas expected to be nonattainment for 

PM2.5 in the future involved using the 

model predictions in a relative way to 

forecast current PM2.5 design values to 

2010 and 2015. The modeling portion of 

this approach included annual 

simulations for 2001 proxy emissions 

and for 2010 and 2015 base case 

emissions scenarios. As described 

below, the predictions from these runs 

were used to calculate relative reduction 

factors (RRFs) which were then applied 

to current PM2.5 design values from 

FRM sites in the East. This approach is 

consistent with the procedures in the 

draft of EPA’s PM2.5 modeling guidance.

To determine the current PM2.5 air 

quality for use in projecting design 

values to the future, we selected the 

higher of the 1999–2001 or 2000–2002 

design value (the most recent ambient 

data at the time of the proposal) for each 

monitor that measured nonattainment in 

2000–2002. For those sites that were 

attaining the PM2.5 standard based on 

their 2000–2002 design value, we used 

the value from this period as the starting 

point for projecting 2010 and 2015 air 

quality at these sites. 

The procedure for calculating future 

year PM2.5 design values is called the 

Speciated Modeled Attainment Test 

(SMAT). The test uses model 

predictions in a relative sense to 

estimate changes expected to occur in 

each major PM2.5 species. These species 

are sulfate, nitrate, organic carbon, 

elemental carbon, crustal, and unattributed mass. The relative change in 

model-predicted species concentrations 

were applied to ambient species 

measurements in order to project each 

species for the future year scenarios. We 

applied a spatial interpolation to the 

IMPROVE and STN speciation data as a 

means for estimating species 

composition fractions for the FRM 

monitoring sites. Future year PM2.5 was 

calculated by summing the projected 

concentrations of each species. The 

SMAT technical procedures, as applied 

for the NPR, are contained in the NPR 

and NPR AQMTSD. 

As noted above, the procedures for 

determining future year PM2.5

concentrations were applied for each 

FRM site. For counties with only one 

FRM site, the forecast design value for 

that site was used to determine whether 

or not the county was predicted to be 

nonattainment in the future. For 

counties with multiple monitoring sites, 

the site with the highest future 

concentration was selected for that 

county. Those counties with future year 

concentrations of 15.1 μg/m3 (as 

rounded up from 15.05 μg/m3) or more 

were predicted to be nonattainment. 

Based on the modeling performed for 

the NPR, 61 counties in the East were 

forecast to be nonattainment for the 

2010 base case. Of these, 41 were 

forecast to remain nonattainment for the 

2015 base case. 

Comment: Some commenters said that 

EPA has not established the credibility 

of using models in a relative sense to 

estimate future PM2.5 concentrations 

and that poor performance of REMSAD 

for 1996 calls into question the use of 

models to adequately determine the 

effects of changes in emissions. One 

commenter said that a mechanistic 

model evaluation, in which model 

predictions of PM2.5 precursor 

photochemical oxidants are compared 

to corresponding measurements, is an 

approach for gaining confidence in the 

ability of a model to provide a credible 

response to emission changes. 

Response: The EPA believes the 

future year nonattainment projections 

should be based on using model 

predictions in a relative sense. By 

applying the model in a relative way, 

each measured component of PM2.5 is 

adjusted upward or downward based on 

the percent change in that component, 

as determined by the ratio of future year 

to base year model predictions. The EPA 

feels that by using this approach, we are 

able to reduce the risk that 

overprediction or underprediction of 

PM2.5 component species may unduly 

affect our projection of future year 

nonattainment. 

The EPA agrees with commenters that 

one way to establish confidence in the 

credibility of this approach is to 

25240 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

101Procedures for Estimating Future PM2.5 Values 

for the CAIR Final Rule by Application of the 

(Revised) Speciated Modeled Attainment Test 

(SMAT), docket number OAR–2003–0053–1907.

determine whether model predictions of 

PM2.5 precursors are generally 

comparable to corresponding measured 

data. In this regard, we compared the 

CMAQ predictions to observations for 

several precursor gases for which 

measurements were available in 2001. 

These gases include sulfur dioxide, 

nitric acid, and ozone. 

The results for the East are 

summarized in Table VI–2. Additional 

details on this analysis can be found in 

the CMAQ evaluation report. The 

results indicate that for both summer 

and winter ozone, the fractional bias 

and error is within the recommended 

range for urban scale ozone modeling 

included in EPA’s draft guidance for 8-

hour ozone modeling. For the other 

species examined, there are limited 

ambient data and few other studies 

against which to compare our findings. 

Still, our performance results for these 

species are within the range suggested 

as acceptable by commenters for sulfate 

(i.e., ±30 percent to ±60 percent for 

fractional bias and 50 percent to 75 

percent for fractional error). Thus, 

CMAQ is considered appropriate and 

credible for use in projecting changes in 

future year PM2.5 concentrations and the 

resultant health/economic benefits due 

to the emissions reductions.

TABLE VI–2.—CMAQ MODEL PERFORMANCE STATISTICS FOR OZONE, TOTAL NITRATE, AND NITRIC ACID IN THE EAST

Eastern U.S. 

CMAQ 2001 

FB (%) FE (%) 

Ozone: 

AIRS (Summer) ........................................................................................................................................................ 13 21 

AIRS (Winter) ........................................................................................................................................................... ¥9 31 

Sulfur Dioxide: 

CASTNet (Summer) ................................................................................................................................................. 31 48 

CASTNet (Winter) ..................................................................................................................................................... 39 43 

Nitric Acid: 

CASTNet (Summer) ................................................................................................................................................. 29 39 

CASTNet (Winter) ..................................................................................................................................................... ¥21 55 

Comment: Several commenters said 

that EPA’s SMAT approach is flawed 

and suggested alternative methods for 

attributing individual species mass to 

the FRM measured PM2.5 mass. One 

commenter detailed several different 

methods to apportion the FRM mass to 

individual PM2.5 species. They refer to 

two different estimation methods as the 

‘‘FRM equivalent’’ approach and the 

‘‘best estimate’’ approach.

Response: The EPA agrees that 

alternative methodologies can be used 

to apportion PM2.5 species fractions to 

the FRM data. We believe that revising 

SMAT to use a methodology similar to 

an ‘‘FRM equivalent’’ methodology, as 

described in the Notice of Data 

Availability (69 FR 47828; August 6, 

2004), is warranted. Since 

nonattainment designation 

determinations and future year 

nonattainment projections are based on 

measured FRM data, we believe that the 

PM2.5 species data should be adjusted to 

best conform to what is measured on the 

FRM filters. Based on comments, EPA 

has revised our technique for projecting 

current PM2.5 data to incorporate some 

aspects of the commenter’s ‘‘FRM 

equivalent’’ methodology. As described 

in more detail in the NFR AQMTSD, we 

believe our revised methodology to be 

the most technically appropriate way of 

estimating what is measured on the 

FRM filters. 

Full documentation of the revised 

EPA SMAT methodology is contained in 

the updated SMAT report 101. In brief, 

we revised the SMAT methodology to 

take into account several known 

differences between what is measured 

by speciation monitors and what is 

measured on FRM filters. Among the 

revisions were calculations to account 

for nitrate, ammonium, and organic 

carbon volatilization, blank PM2.5 mass, 

particle bound water, the degree of 

neutralization of sulfate, and the 

uncertainty in estimating organic carbon 

mass.

Comment: Several commenters noted 

that the future year design values were 

based on projections of the 1999–2001 

and/or 2000–2002 FRM monitoring data 

and that there are more recent design 

value data available for the 2001–2003 

design value period. Commenters also 

noted that the 2001–2003 data shows 

lower PM2.5 concentrations at the 

majority of sites and therefore, by 

projecting the highest design value, we 

are overestimating the future year PM2.5

values. 

Response: As stated above, the PM2.5

projection methodology in the NPR used 

the higher of the 1999–2001 or 2000–

2002 PM2.5 design value data. The draft 

modeling guidance for PM2.5 specifies 

the use of the higher of the three design 

value periods which straddle the 

emissions year. The emissions year is 

2001 and therefore the three periods 

would be 1999–2001, 2000–2002, and 

2001–2003. Since the 2001–2003 data is 

now available, we are using it as part of 

the current year PM2.5 calculations for 

the final rule. 

The observation by a commenter that 

the 2001–2003 data are generally lower 

than in the previous two design value 

periods (i.e., 1999–2001 and 2000–2002) 

leads to the issue of how to reduce the 

influence of year-to-year variability in 

meteorology and emissions on our 

estimate of current air quality. As a 

consequence of this year-to-year 

variability in concentrations, relying on 

design values from any single period, as 

in the approach used for proposal, may 

not provide a robust representation of 

current air quality for use in forecasting 

the future. Specifically, the lower PM2.5

values in 2001–2003 may not be 

representative of the current modeling 

period. To address the issue of year-toyear variability in the ambient data we 

have modified our methodology to use 

an average of the three design value 

periods that straddle the base year 

emissions year (i.e., 2001). In this case 

it is the average of the 1999–2001, 2000–

2002, and 2001–2003 design values. The 

average of the three design values is not 

a straight 5-year average. Rather, it is a 

weighted average of the 1999–2003 

period. That is, by averaging 1999–2001, 

2000–2002, and 2001–2003, the value 

from 2001 is weighted three times; 2000 

and 2002 are each weighted twice and 

1999 and 2003 are each weighted once. 

This approach has the desired benefits 

of: (1) weighting the PM2.5 values 

towards the middle year of the 5-year 

period, which is the 2001 base year for 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25241

our emissions projections; and (2) 

smoothing out the effects of year-to-year 

variability in emissions and 

meteorology that occurs over the full 5-

year period. We have adopted this 

method for use in projecting future 

PM2.5 nonattainment for the final rule 

analysis. We plan to incorporate this 

new methodology into the next draft 

version of our PM2.5 modeling guidance. 

b. Projected 2010 and 2015 Base Case 

PM2.5 Nonattainment Counties 

For the final rule, we have revised the 

projected PM2.5 nonattainment counties 

for 2010 and 2015 by applying CMAQ 

for the entire year (i.e., January through 

December) of 2001 using 2001 Base Year 

and 2010 and 2015 future base case 

emissions from the new modeling 

platform, as described in section VI.A.2. 

The 2010 and 2015 base case PM2.5

nonattainment counties were 

determined applying the updated SMAT 

method using current 1999–2003 PM2.5

air quality coupled with the PM2.5

species from the 2001 Base Year and 

2010 and 2015 base case CMAQ model 

runs. For counties with multiple 

monitoring sites, the site with the 

highest future concentration was 

selected for that county. Those counties 

with future year design values of 15.05 

μg/m3 or higher were predicted to be 

nonattainment. The result is that, 

without controls beyond those included 

in the base case, 79 counties in the East 

are projected to be nonattainment for 

the 2010 base case. For the 2015 base 

case, 74 counties in the East are 

projected to be nonattainment for PM2.5. 

In light of the uncertainties inherent 

in regionwide modeling many years into 

the future, of the 79 nonattainment 

counties projected for the 2010 base 

case, we have the most confidence in 

our projection of nonattainment for 

those counties that are not only forecast 

to be nonattainment in 2010, based on 

the SMAT method, but that also 

measure nonattainment for the most 

recent period of available ambient data 

(i.e., 2001–2003). In our analysis for the 

2010 base case, there are 62 such 

counties in the East that are both 

‘‘modeled’’ nonattainment and currently 

have ‘‘monitored’’ nonattainment. We 

refer to these counties as having 

‘‘modeled plus monitored’’

nonattainment. Out of an abundance of 

caution, we are using only these 62 

‘‘modeled plus monitored’’ counties as 

the downwind receptors in determining 

which upwind States make a significant 

contribution to PM2.5 in downwind 

States.

The 79 counties in the East that we 

project will be nonattainment for PM2.5

in 2010 and the subset of 62 counties 

that are also ‘‘monitored’’

nonattainment in 2001–2003, are 

identified in Table VI–3. The 2015 base 

case PM2.5 nonattainment counties are 

provided in Table VI–4.

TABLE VI–3.—PROJECTED PM2.5 CONCENTRATIONS (μG/M3) FOR NONATTAINMENT COUNTIES IN THE 2010 BASE CASE

State County 2010 Base ‘‘Modeled + Monitored’’

Alabama ............................................................. DeKalb Co ......................................................... 15.23 No. 

Alabama ............................................................. Jefferson Co ...................................................... 18.57 Yes. 

Alabama ............................................................. Montgomery Co ................................................. 15.12 No. 

Alabama ............................................................. Morgan Co ......................................................... 15.29 No. 

Alabama ............................................................. Russell Co ......................................................... 16.17 Yes. 

Alabama ............................................................. Talladega Co ..................................................... 15.34 No. 

Delaware ............................................................ New Castle Co ................................................... 16.56 Yes. 

District of Columbia ............................................ ............................................................................ 15.84 Yes. 

Georgia ............................................................... Bibb Co .............................................................. 16.27 Yes. 

Georgia ............................................................... Clarke Co ........................................................... 16.39 Yes. 

Georgia ............................................................... Clayton Co ......................................................... 17.39 Yes. 

Georgia ............................................................... Cobb Co ............................................................. 16.57 Yes. 

Georgia ............................................................... DeKalb Co ......................................................... 16.75 Yes. 

Georgia ............................................................... Floyd Co ............................................................ 16.87 Yes. 

Georgia ............................................................... Fulton Co ........................................................... 18.02 Yes. 

Georgia ............................................................... Hall Co ............................................................... 15.60 No. 

Georgia ............................................................... Muscogee Co ..................................................... 15.65 No. 

Georgia ............................................................... Richmond Co ..................................................... 15.68 No. 

Georgia ............................................................... Walker Co .......................................................... 15.43 Yes. 

Georgia ............................................................... Washington Co .................................................. 15.31 No. 

Georgia ............................................................... Wilkinson Co ...................................................... 16.27 No. 

Illinois .................................................................. Cook Co ............................................................. 17.52 Yes. 

Illinois .................................................................. Madison Co ........................................................ 16.66 Yes. 

Illinois .................................................................. St. Clair Co ........................................................ 16.24 Yes. 

Indiana ................................................................ Clark Co ............................................................. 16.51 Yes. 

Indiana ................................................................ Dubois Co .......................................................... 15.73 Yes. 

Indiana ................................................................ Lake Co ............................................................. 17.26 Yes. 

Indiana ................................................................ Marion Co .......................................................... 16.83 Yes. 

Indiana ................................................................ Vanderburgh Co ................................................ 15.54 Yes. 

Kentucky ............................................................. Boyd Co ............................................................. 15.23 No. 

Kentucky ............................................................. Bullitt Co ............................................................ 15.10 No. 

Kentucky ............................................................. Fayette Co ......................................................... 15.95 Yes. 

Kentucky ............................................................. Jefferson Co ...................................................... 16.71 Yes. 

Kentucky ............................................................. Kenton Co .......................................................... 15.30 No. 

Maryland ............................................................. Anne Arundel Co ............................................... 15.26 Yes. 

Maryland ............................................................. Baltimore City .................................................... 16.96 Yes. 

Michigan ............................................................. Wayne Co .......................................................... 19.41 Yes. 

Missouri .............................................................. St. Louis City ..................................................... 15.10 No. 

New Jersey ......................................................... Union Co ............................................................ 15.05 Yes. 

New York ............................................................ New York Co ..................................................... 16.19 Yes. 

North Carolina .................................................... Catawba Co ....................................................... 15.48 Yes. 

North Carolina .................................................... Davidson Co ...................................................... 15.76 Yes. 

North Carolina .................................................... Mecklenburg Co ................................................. 15.22 No. 

Ohio .................................................................... Butler Co ............................................................ 16.45 Yes. 

25242 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

TABLE VI–3.—PROJECTED PM2.5 CONCENTRATIONS (μG/M3) FOR NONATTAINMENT COUNTIES IN THE 2010 BASE CASE—

Continued

State County 2010 Base ‘‘Modeled + Monitored’’

Ohio .................................................................... Cuyahoga Co ..................................................... 18.84 Yes. 

Ohio .................................................................... Franklin Co ........................................................ 16.98 Yes. 

Ohio .................................................................... Hamilton Co ....................................................... 18.23 Yes. 

Ohio .................................................................... Jefferson Co ...................................................... 17.94 Yes. 

Ohio .................................................................... Lawrence Co ...................................................... 16.10 Yes. 

Ohio .................................................................... Mahoning Co ..................................................... 15.39 Yes. 

Ohio .................................................................... Montgomery Co ................................................. 15.41 Yes. 

Ohio .................................................................... Scioto Co ........................................................... 18.13 Yes. 

Ohio .................................................................... Stark Co ............................................................. 17.14 Yes. 

Ohio .................................................................... Summit Co ......................................................... 16.47 Yes. 

Ohio .................................................................... Trumbull Co ....................................................... 15.28 No. 

Pennsylvania ...................................................... Allegheny Co ..................................................... 20.55 Yes. 

Pennsylvania ...................................................... Beaver Co .......................................................... 15.78 Yes. 

Pennsylvania ...................................................... Berks Co ............................................................ 15.89 Yes. 

Pennsylvania ...................................................... Cambria Co ........................................................ 15.14 Yes. 

Pennsylvania ...................................................... Dauphin Co ........................................................ 15.17 Yes. 

Pennsylvania ...................................................... Delaware Co ...................................................... 15.61 Yes. 

Pennsylvania ...................................................... Lancaster Co ..................................................... 16.55 Yes. 

Pennsylvania ...................................................... Philadelphia Co .................................................. 16.65 Yes. 

Pennsylvania ...................................................... Washington Co .................................................. 15.23 Yes. 

Pennsylvania ...................................................... Westmoreland Co .............................................. 15.16 Yes. 

Pennsylvania ...................................................... York Co .............................................................. 16.49 Yes. 

Tennessee .......................................................... Davidson Co ...................................................... 15.36 No. 

Tennessee .......................................................... Hamilton Co ....................................................... 16.89 Yes. 

Tennessee .......................................................... Knox Co ............................................................. 17.44 Yes. 

Tennessee .......................................................... Sullivan Co ......................................................... 15.32 No. 

West Virginia ...................................................... Berkeley Co ....................................................... 15.69 Yes. 

West Virginia ...................................................... Brooke Co .......................................................... 16.63 Yes. 

West Virginia ...................................................... Cabell Co ........................................................... 17.03 Yes. 

West Virginia ...................................................... Hancock Co ....................................................... 17.06 Yes. 

West Virginia ...................................................... Kanawha Co ...................................................... 17.56 Yes. 

West Virginia ...................................................... Marion Co .......................................................... 15.32 Yes. 

West Virginia ...................................................... Marshall Co ........................................................ 15.81 Yes. 

West Virginia ...................................................... Ohio Co .............................................................. 15.14 Yes. 

West Virginia ...................................................... Wood Co ............................................................ 16.66 Yes. 

TABLE VI–4.—PROJECTED PM2.5 CONCENTRATIONS (μG/M<>3) FOR NONATTAINMENT COUNTIES IN THE 2015 BASE CASE

State County 2015 Base 

Alabama ...................................................................................... DeKalb Co .................................................................................. 15.24 

Alabama ...................................................................................... Jefferson Co ............................................................................... 18.85 

Alabama ...................................................................................... Montgomery Co ......................................................................... 15.24 

Alabama ...................................................................................... Morgan Co ................................................................................. 15.26 

Alabama ...................................................................................... Russell Co .................................................................................. 16.10 

Alabama ...................................................................................... Talladega Co .............................................................................. 15.22 

Delaware ..................................................................................... New Castle Co ........................................................................... 16.47 

District of Columbia ..................................................................... .................................................................................................... 15.57 

Georgia ....................................................................................... Bibb Co ...................................................................................... 16.41 

Georgia ....................................................................................... Chatham Co ............................................................................... 15.06 

Georgia ....................................................................................... Clarke Co ................................................................................... 16.15 

Georgia ....................................................................................... Clayton Co ................................................................................. 17.46 

Georgia ....................................................................................... Cobb Co ..................................................................................... 16.51 

Georgia ....................................................................................... DeKalb Co .................................................................................. 16.82 

Georgia ....................................................................................... Floyd Co ..................................................................................... 17.33 

Georgia ....................................................................................... Fulton Co ................................................................................... 18.00 

Georgia ....................................................................................... Hall Co ....................................................................................... 15.36 

Georgia ....................................................................................... Muscogee Co ............................................................................. 15.58 

Georgia ....................................................................................... Richmond Co ............................................................................. 15.76 

Georgia ....................................................................................... Walker Co .................................................................................. 15.37 

Georgia ....................................................................................... Washington Co .......................................................................... 15.34 

Georgia ....................................................................................... Wilkinson Co .............................................................................. 16.54 

Illinois .......................................................................................... Cook Co ..................................................................................... 17.71 

Illinois .......................................................................................... Madison Co ................................................................................ 16.90 

Illinois .......................................................................................... St. Clair Co ................................................................................ 16.49 

Illinois .......................................................................................... Will Co ........................................................................................ 15.12 

Indiana ........................................................................................ Clark Co ..................................................................................... 16.37 

Indiana ........................................................................................ Dubois Co .................................................................................. 15.66 

Indiana ........................................................................................ Lake Co ...................................................................................... 17.27 

Indiana ........................................................................................ Marion Co .................................................................................. 16.77 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25243

TABLE VI–4.—PROJECTED PM2.5 CONCENTRATIONS (μG/M<>3) FOR NONATTAINMENT COUNTIES IN THE 2015 BASE

CASE—Continued

State County 2015 Base 

Indiana ........................................................................................ Vanderburgh Co ......................................................................... 15.56 

Kentucky ..................................................................................... Boyd Co ..................................................................................... 15.06 

Kentucky ..................................................................................... Fayette Co ................................................................................. 15.62 

Kentucky ..................................................................................... Jefferson Co ............................................................................... 16.61 

Kentucky ..................................................................................... Kenton Co .................................................................................. 15.09 

Maryland ..................................................................................... Baltimore City ............................................................................. 17.04 

Maryland ..................................................................................... Baltimore Co .............................................................................. 15.08 

Michigan ...................................................................................... Wayne Co .................................................................................. 19.28 

Mississippi ................................................................................... Jones Co .................................................................................... 15.18 

Missouri ....................................................................................... St. Louis City .............................................................................. 15.34 

New York .................................................................................... New York Co .............................................................................. 15.76 

North Carolina ............................................................................. Catawba Co ............................................................................... 15.19 

North Carolina ............................................................................. Davidson Co .............................................................................. 15.34 

Ohio ............................................................................................. Butler Co .................................................................................... 16.32 

Ohio ............................................................................................. Cuyahoga Co ............................................................................. 18.60 

Ohio ............................................................................................. Franklin Co ................................................................................. 16.64 

Ohio ............................................................................................. Hamilton Co ............................................................................... 18.03 

Ohio ............................................................................................. Jefferson Co ............................................................................... 17.83 

Ohio ............................................................................................. Lawrence Co .............................................................................. 15.92 

Ohio ............................................................................................. Mahoning Co .............................................................................. 15.13 

Ohio ............................................................................................. Montgomery Co ......................................................................... 15.16 

Ohio ............................................................................................. Scioto Co ................................................................................... 17.92 

Ohio ............................................................................................. Stark Co ..................................................................................... 16.86 

Ohio ............................................................................................. Summit Co ................................................................................. 16.14 

Ohio ............................................................................................. Trumbull Co ............................................................................... 15.05 

Pennsylvania ............................................................................... Allegheny Co .............................................................................. 20.33 

Pennsylvania ............................................................................... Beaver Co .................................................................................. 15.54 

Pennsylvania ............................................................................... Berks Co .................................................................................... 15.66 

Pennsylvania ............................................................................... Delaware Co .............................................................................. 15.52 

Pennsylvania ............................................................................... Lancaster Co .............................................................................. 16.28 

Pennsylvania ............................................................................... Philadelphia Co .......................................................................... 16.53 

Pennsylvania ............................................................................... York Co ...................................................................................... 16.22 

Tennessee .................................................................................. Davidson Co .............................................................................. 15.36 

Tennessee .................................................................................. Hamilton Co ............................................................................... 16.82 

Tennessee .................................................................................. Knox Co ..................................................................................... 17.34 

Tennessee .................................................................................. Shelby Co .................................................................................. 15.17 

Tennessee .................................................................................. Sullivan Co ................................................................................. 15.37 

West Virginia ............................................................................... Berkeley Co ............................................................................... 15.32 

West Virginia ............................................................................... Brooke Co .................................................................................. 16.51 

West Virginia ............................................................................... Cabell Co ................................................................................... 16.86 

West Virginia ............................................................................... Hancock Co ............................................................................... 16.97 

West Virginia ............................................................................... Kanawha Co .............................................................................. 17.17 

West Virginia ............................................................................... Marshall Co ................................................................................ 15.52 

West Virginia ............................................................................... Wood Co .................................................................................... 16.69 

2. Projection of Future 8-Hour Ozone 

Nonattainment 

a. Methodology for Projecting Future 8-

Hour Ozone Nonattainment

The approach for projecting future 8-

hour ozone concentrations used by EPA 

in the NPR was based on applying the 

model in a relative sense to estimate the 

change in ozone between the base year 

(2001) and each future scenario. 

Projected 8-hour ozone design values in 

2010 and 2015 were estimated by 

combining the relative change in model 

predicted ozone from 2001 to the future 

scenario with an estimate of the base 

year ambient 8-hour ozone design value. 

These procedures for calculating future 

case ozone design values are consistent 

with EPA’s draft modeling guidance for 

8-hour ozone attainment 

demonstrations. The draft guidance 

specifies the use of the higher of the 

design values from (a) the period that 

straddles the emissions inventory base 

year or (b) the design value period 

which was used to designate the area 

under the ozone NAAQS. At the time of 

the proposal, 2000–2002 was the design 

value period which both straddled the 

2001 base year inventory and was also 

the latest period available. 

Comment: Commenters noted that the 

procedures used by EPA for projecting 

future 8-hour ozone concentrations 

differ from the procedures used for 

projecting PM2.5. These commenters said 

that EPA should harmonize the two 

approaches. 

Response: In response to comments, 

we have made several changes in the 

approach to projecting future 8-hour 

ozone nonattainment in order to follow 

an approach that is consistent with the 

manner in which PM2.5 projections are 

determined. The approach we are using 

to project PM2.5 for the final rule 

analysis is described in section VI.B.1, 

above. In order to harmonize the ozone 

approach with the approach used for 

PM2.5, we are using the weighted 

average of the design values for the 

periods that straddle the emission base 

year (i.e., 2001). These periods are 

1999–2001, 2000–2002, and 2001–2003. 

In this approach, the fourth-high ozone 

value from 2001 is weighted three times, 

2000 and 2002 are weighted twice, and 

1999 and 2003 are weighted once. This 

has the desired effect of weighting the 

projected ozone values towards the 

middle year of the 5-year period, which 

is the emissions year (2001), while 

25244 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

accounting for the emissions and 

meteorological variability that occurs 

over the full 5-year period. The average 

weighted concentration is expected to 

be more representative as a starting 

point for future year projections than 

choosing (a) the single design value 

period that straddles the base year or (b) 

the design value used for designations. 

We plan to incorporate this new 

methodology into the next draft version 

of our ozone modeling guidance. 

Comment: One commenter claimed 

that the 2010 and 2015 ozone 

projections in the proposal base cases 

were too optimistic, that is, that the 

modeling was underestimating the 

number of areas that may be in 

nonattainment in the future. The 

commenter urged a more conservative 

approach to assessing the future 

attainment status of areas. 

Response: The technical basis for the 

comment stemmed from the assertion 

that the regional ozone modeling that 

EPA performed for the proposal was not 

of ‘‘SIP-quality.’’ The EPA response to 

the specific technical issues with regard 

to episode selection and grid resolution 

can be found in section VI.A as well as 

in the response to comments document. 

The EPA remains confident that the 

CAIR 8-hour ozone modeling platform is 

appropriate for assessing potential 

levels of future nonattainment. 

b. Projected 2010 and 2015 Base Case 8-

Hour Ozone Nonattainment Counties 

For the final rule, we have revised our 

projections of ozone nonattainment for 

the 2010 and 2015 base cases by 

applying CAMx for the three 1995 ozone 

episodes using 2001 Base Year and 2010 

and 2015 future base case emissions 

from the new modeling platform, as 

described in section VI.A.2. The revised 

2010 and 2015 base case 8-hour ozone 

nonattainment counties were 

determined by applying the relative 

change in 8-hour ozone predicted by 

these CAMx model runs to the weighted 

average 1999–2003 8-hour ozone 

concentrations as described above and, 

in more detail, in the NFR AQMTSD. 

For counties with multiple monitoring 

sites, the site with the highest future 

concentration was selected for that 

county. Those counties with future year 

design values of 85 parts per billion 

(ppb) or higher were predicted to be 

nonattainment. 

As a result of our updated modeling 

we project that, without controls beyond 

those in the base case, there will be 40 

8-hour ozone nonattainnment counties 

in 2010 and 22 nonattainment counties 

in 2015. All of the 40 counties that we 

are projecting to be nonattainment for 

the 2010 base case are also measuring 

nonattainment based on the most recent 

design value period (i.e., 2001–2003). 

We refer to these counties as ‘‘modeled 

plus monitored’’ nonattainment, as 

described above in section IV.B.1 for 

PM2.5. We are using these 40 counties as 

the downwind receptors to determine 

which States make a significant 

contribution to 8-hour ozone 

nonattainment in downwind States. 

The counties we are projecting to be 

nonattainment for 8-hour ozone in the 

2010 base case and 2015 base case are 

listed in Table VI–5 and Table VI–6, 

respectively.

TABLE VI–5.—PROJECTED 2010 BASE CASE 8-HOUR OZONE NONATTAINMENT COUNTIES AND CONCENTRATIONS (PPB) 

State County 2010 Base 

Connecticut ................................................................................. Fairfield Co ................................................................................. 92.6 

Connecticut ................................................................................. Middlesex Co ............................................................................. 90.9 

Connecticut ................................................................................. New Haven Co ........................................................................... 91.6 

Delaware ..................................................................................... New Castle Co ........................................................................... 85.0 

District of Columbia ..................................................................... .................................................................................................... 85.2 

Georgia ....................................................................................... Fulton Co ................................................................................... 86.5 

Maryland ..................................................................................... Anne Arundel Co ....................................................................... 88.8 

Maryland ..................................................................................... Cecil Co ..................................................................................... 89.7 

Maryland ..................................................................................... Harford Co ................................................................................. 93.0 

Maryland ..................................................................................... Kent Co ...................................................................................... 86.2 

Michigan ...................................................................................... Macomb Co ................................................................................ 85.5 

New Jersey ................................................................................. Bergen Co .................................................................................. 86.9 

New Jersey ................................................................................. Camden Co ................................................................................ 91.9 

New Jersey ................................................................................. Gloucester Co ............................................................................ 91.8 

New Jersey ................................................................................. Hunterdon Co ............................................................................. 89.0 

New Jersey ................................................................................. Mercer Co .................................................................................. 95.6 

New Jersey ................................................................................. Middlesex Co ............................................................................. 92.4 

New Jersey ................................................................................. Monmouth Co ............................................................................ 86.6 

New Jersey ................................................................................. Morris Co ................................................................................... 86.5 

New Jersey ................................................................................. Ocean Co ................................................................................... 100.5 

New York .................................................................................... Erie Co ....................................................................................... 87.3 

New York .................................................................................... Richmond Co ............................................................................. 87.3 

New York .................................................................................... Suffolk Co .................................................................................. 91.1 

New York .................................................................................... Westchester Co ......................................................................... 85.3 

Ohio ............................................................................................. Geauga Co ................................................................................. 87.1 

Pennsylvania ............................................................................... Bucks Co .................................................................................... 94.7 

Pennsylvania ............................................................................... Chester Co ................................................................................. 85.7 

Pennsylvania ............................................................................... Montgomery Co ......................................................................... 88.0 

Pennsylvania ............................................................................... Philadelphia Co .......................................................................... 90.3 

Rhode Island ............................................................................... Kent Co ...................................................................................... 86.4 

Texas .......................................................................................... Denton Co .................................................................................. 87.4 

Texas .......................................................................................... Galveston Co ............................................................................. 85.1 

Texas .......................................................................................... Harris Co .................................................................................... 97.9 

Texas .......................................................................................... Jefferson Co ............................................................................... 85.6 

Texas .......................................................................................... Tarrant Co .................................................................................. 87.8 

Virginia ........................................................................................ Arlington Co ............................................................................... 86.2 

Virginia ........................................................................................ Fairfax Co .................................................................................. 85.7 

Wisconsin .................................................................................... Kenosha Co ............................................................................... 91.3 

Wisconsin .................................................................................... Ozaukee Co ............................................................................... 86.2 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25245

TABLE VI–5.—PROJECTED 2010 BASE CASE 8-HOUR OZONE NONATTAINMENT COUNTIES AND CONCENTRATIONS (PPB)—

Continued

State County 2010 Base 

Wisconsin .................................................................................... Sheboygan Co ........................................................................... 88.3 

TABLE VI–6.—PROJECTED 2015 BASE CASE 8-HOUR OZONE NONATTAINMENT COUNTIES AND CONCENTRATIONS (PPB) 

State County 2015 Base 

Connecticut ................................................................................. Fairfield Co ................................................................................. 91.4 

Connecticut ................................................................................. Middlesex Co ............................................................................. 89.1 

Connecticut ................................................................................. New Haven Co ........................................................................... 89.8 

Maryland ..................................................................................... Anne Arundel Co ....................................................................... 86.0 

Maryland ..................................................................................... Cecil Co ..................................................................................... 86.9 

Maryland ..................................................................................... Harford Co ................................................................................. 90.6 

Michigan ...................................................................................... Macomb Co ................................................................................ 85.1 

New Jersey ................................................................................. Bergen Co .................................................................................. 85.7 

New Jersey ................................................................................. Camden Co ................................................................................ 89.5 

New Jersey ................................................................................. Gloucester Co ............................................................................ 89.6 

New Jersey ................................................................................. Hunterdon Co ............................................................................. 86.5 

New Jersey ................................................................................. Mercer Co .................................................................................. 93.5 

New Jersey ................................................................................. Middlesex Co ............................................................................. 89.8 

New Jersey ................................................................................. Ocean Co ................................................................................... 98.0 

New York .................................................................................... Erie Co ....................................................................................... 85.2 

New York .................................................................................... Suffolk Co .................................................................................. 89.9 

Pennsylvania ............................................................................... Bucks Co .................................................................................... 93.0 

Pennsylvania ............................................................................... Montgomery Co ......................................................................... 86.5 

Pennsylvania ............................................................................... Philadelphia Co .......................................................................... 88.9 

Texas .......................................................................................... Harris Co .................................................................................... 97.3 

Texas .......................................................................................... Jefferson Co ............................................................................... 85.0 

Wisconsin .................................................................................... Kenosha Co ............................................................................... 89.4 

C. How Did EPA Assess Interstate 

Contributions to Nonattainment? 

1. PM2.5 Contribution Modeling 

Approach 

For the proposed rule, EPA performed 

State-by-State zero-out modeling to 

quantify the contribution from 

emissions in each State to future PM2.5

nonattainment in other States and to 

determine whether that contribution 

meets the air quality prong (i.e., before 

considering cost) of the ‘‘contribute 

significantly’’ test. The zero-out 

modeling technique provides an 

estimate of downwind impacts by 

comparing the model predictions from 

the 2010 base case to the predictions 

from a run in which all anthropogenic 

SO2 and NOX emissions are removed 

from specific States. Counties forecast to 

be nonattainment for PM2.5 in the 

proposal 2010 base case were used as 

receptors for quantifying interstate 

contributions of PM2.5. For each Stateby-State zero-out run we projected the 

annual average PM2.5 concentration at 

each receptor using the proposed SMAT 

technique, as described in the NPR 

AQMTSD. The contribution from an 

upwind State to nonattainment at a 

given downwind receptor was 

determined by calculating the difference 

in PM2.5 concentration between the 2010 

base case and the zero-out run at that 

receptor. We followed this process for 

each State-by-State zero-out run and 

each receptor. For each upwind State, 

we identified the largest contribution 

from that State to a downwind 

nonattainment receptor in order to 

determine the magnitude of the 

maximum downwind contribution from 

each State. The maximum downwind 

contribution was proposed as the metric 

for determining whether or not the 

contribution was significant. As 

described in section III, EPA proposed, 

in the alternative, a criterion of 0.10 μg/

m3 and 0.15 μg/m3 for determining 

whether emissions in a State make a 

significant contribution (before 

considering cost) to PM2.5

nonattainment in another State. Details 

on these procedures can be found in the 

NPR AQMTSD. 

Comments: Commenters questioned 

the use of zero-out modeling and said 

that EPA should support the 

development of a source apportionment 

model for PM2.5 contributions. The 

commenter recommended that EPA 

delay the final rule until such a 

technique can be used. Another 

commenter provided results of a sulfate 

source apportionment technique 

currently under development along with 

modeling results which showed that the 

zero-out technique and source 

apportionment for sulfate provide 

similar results in terms of the magnitude 

and extent of downwind impacts. The 

commenter noted that the results 

suggest that zero-out modeling may 

somewhat underestimate the transport 

of sulfate. 

Response: The EPA continues to 

believe that the zero-out technique is a 

credible method for quantifying 

interstate PM2.5 contributions. This is 

supported by a commenter’s results 

showing that the zero-out technique and 

source apportionment appear to give 

similar results. We accept the 

commenter’s modeling for sulfate source 

apportionment results which indicate 

that the zero-out technique does not 

overestimate interstate transport. 

Moreover, EPA rejects the notion that 

we should delay needed reductions 

while we await alternative assessment 

techniques.

2. 8-Hour Ozone Contribution Modeling 

Approach 

In the proposal, EPA quantified the 

impact of emissions from specific 

upwind States on 8-hour ozone 

concentrations in projected downwind 

nonattainment areas. The procedures we 

followed to assess interstate ozone 

contribution for the proposal analysis 

are summarized below. We are using 

these same procedures along with the 

updated CAMX modeling platform, as 

25246 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

102The six States are Kansas, Nebraska, North 

Dakota, Oklahoma, South Dakota, and Texas.

described in section VI.A., to assess 

ozone contributions for today’s rule. 

Details on these procedures can be 

found in the NFR AQMTSD. 

We applied two different modeling 

techniques, zero-out and source 

apportionment, to assess the 

contributions of emissions in upwind 

States on 8-hour ozone nonattainment 

in downwind States. The outputs of the 

two modeling techniques were 

evaluated in terms of three key 

contribution factors to determine which 

States make a significant contribution to 

downwind ozone nonattainment as 

described in section VI.B.2. The zeroout and source apportionment modeling 

techniques provide different, but 

equally valid, technical approaches to 

quantifying the downwind impact of 

emissions from upwind States. The 

zero-out modeling analysis provides an 

estimate of downwind impacts by 

comparing the model predictions from 

the 2010 base case and the predictions 

from a model run in which all 

anthropogenic NOX and VOC emissions 

are removed from specific States. The 

source apportionment modeling 

quantifies downwind impacts by 

tracking and allocating the amounts of 

ozone formed from man-made NOX and 

VOC emissions in upwind States. 

Because large portions of the six States 

along the western border of the 

modeling domain 102 are outside the 

area covered by our modeling, EPA did 

not analyze the contributions to 

downwind ozone nonattainment for 

these States.

In the analysis done at proposal, EPA 

considered three fundamental factors for 

evaluating whether emissions in an 

upwind State make large and/or 

frequent contributions to downwind 

nonattainment: (1) The magnitude of the 

contribution; (2) the frequency of the 

contribution; and (3) the relative 

amount of the contribution when 

compared against contributions from 

other areas. The factors are the basis for 

several metrics that can be used to 

assess a particular impact. The metrics 

used in this analysis were the same as 

those used in the NOX SIP Call. 

Within these three factors, eight 

specific metrics were calculated to 

assess the contribution of each of the 31 

States to the residual nonattainment 

counties. For the zero-out modeling, 

EPA considered: (1) The maximum 

contribution (magnitude); (2) the 

number and percentage of exceedances 

with contributions in certain 

concentration ranges (frequency); (3) the 

total contribution relative to the total 

exceedance level ozone in the receptor 

area (relative amount); and (4) the 

population-weighted total contribution 

relative to the total population-weighted 

exceedance level ozone in the receptor 

area (relative amount). For the source 

apportionment modeling EPA 

considered: (5) The maximum 

contribution (magnitude); (6) the highest 

daily average contribution (magnitude); 

(7) the number and percentages of 

exceedances with contributions in 

certain concentration ranges 

(frequency); and (8) the total average 

contribution to exceedance ozone in the 

downwind area (relative amount). The 

values for these metrics were calculated 

using only those periods during which 

the model predicted 8-hour average 

ozone concentrations greater than or 

equal to 85 ppb in at least one of the 

model grid cells associated with the 

receptor county in the 2010 base case. 

Grid cells were linked to a specific 

nonattainment county if any part of the 

grid cell covered any portion of the 

projected 2010 nonattainment county. 

The first step in evaluating the 

contribution factors was to screen out 

linkages for which the contributions 

were clearly small. This initial 

screening was based on two criteria: (1) 

The maximum contribution had to be 

greater than or equal to 2 ppb from 

either of the two modeling techniques; 

and (2) the total average contribution to 

exceedance of ozone in the downwind 

area had to be greater than 1 percent. If 

either screening test was not met, then 

the linkage was not considered 

significant. Those linkages that had 

contributions which exceeded the 

screening criteria were evaluated further 

in steps 2 through 4. 

In step 2, we evaluated the 

contributions in each linkage based on 

the zero-out modeling and in step 3 we 

evaluated the contributions in each 

linkage based on the source 

apportionment modeling. In step 4, we 

considered the results of both step 2 and 

step 3 to determine which of the 

linkages were significant. For both 

techniques, EPA determined whether 

the linkage is significant by evaluating 

the magnitude, frequency, and relative 

amount of the contributions. Each 

upwind State that made relatively large 

and/or frequent contributions to 

nonattainment in the downwind area, 

based on these factors, was considered 

to contribute significantly to 

nonattainment in the downwind area.

The EPA believes that each of the 

factors provides an independent 

measure of contribution, however, there 

had to be at least two different factors 

that indicated large and/or frequent 

contributions in order for the linkage to 

be found significant. In this regard, the 

finding of a significant contribution for 

an individual linkage was not based on 

any single factor. Further, each of the 

modeling approaches had to show at 

least one indicator of a large and/or 

frequent contribution in order for the 

linkage to be found significant. The EPA 

received several general comments on 

the procedures for assessing interstate 

contributions of ozone to projected 

residual nonattainment areas, as 

discussed below. 

Comment: A commenter opposed the 

use of population-weighted metrics to 

determine whether an upwind State’s 

impact on a location in another State is 

significant. 

Response: The commenter’s concern 

was that transport contributions to rural 

areas with low populations were not 

being weighted appropriately. This is 

not a valid concern because the relative 

contribution factor from the zero-out 

modeling is presumed to be met if either 

of the two criteria (population-weighted, 

or non-population-weighted) show large 

contributions. 

Comment: Also, EPA received a 

specific comment on a certain linkage 

that was deemed to be significant in the 

analysis done to support the NPR. The 

commenter objected to the conclusion 

that Mississippi significantly 

contributes to residual ozone 

exceedances near Memphis. The 

objection resulted from issues with grid 

resolution, episode selection, and the 

fact that the zero-out and source 

apportionment modeling for Mississippi 

included some emissions from 

Tennessee and Arkansas due to the 

irregular State boundaries. 

Response: As noted in section VI.B.2, 

Crittenden County, AR is no longer 

projected to be a nonattainment area in 

the 2010 base case. As a result, the issue 

of Mississippi’s contribution to ozone in 

the Memphis area is moot. 

D. What Are the Estimated Interstate 

Contributions to PM2.5 and 8-Hour 

Ozone Nonattainment? 

1. Results of PM2.5 Contribution 

Modeling 

In this section, we present the 

interstate contributions from emissions 

in upwind States to PM2.5

nonattainment in downwind 

nonattainment counties. States which 

contribute 0.2 μg/m3 or more to PM2.5

nonattainment in another State are 

determined to contribute significantly 

(before considering cost). We calculated 

the interstate PM2.5 contributions using 

the State-by-State zero-out modeling 

technique, as indicated above in section 

VI.C.1. This technique is described in 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25247

103As noted above, we combined Maryland and 

the District of Columbia as a single entity in our 

contribution modeling. This is a logical approach 

because of the small size of the District of Columbia 

and, hence, its emissions and its close proximity to 

Maryland. Under our analysis, Maryland and the 

District of Columbia are linked as significant 

contributors to the same downwind nonattainment 

counties. The EPA received no adverse comment on 

this approach. We also considered these entities 

separately, and in view of the close proximity of 

these two areas we believe that Maryland is linked 

as a significant contributor to nonattainment in the 

District of Columbia and that the District of 

Columbia is linked as a significant contributor to 

nonattainment in Maryland.

the NFR AQMTSD. We performed zeroout modeling using CMAQ for each of 

37 States individually (i.e., Alabama, 

Arkansas, Connecticut, Delaware, 

Florida, Georgia, Illinois, Indiana, Iowa, 

Kansas, Kentucky, Louisiana, Maine, 

Maryland combined with the District of 

Columbia, Massachusetts, Michigan, 

Minnesota, Mississippi, Missouri, 

Nebraska, New Hampshire, New Jersey, 

New York, North Carolina, North 

Dakota, Ohio, Oklahoma, Pennsylvania, 

Rhode Island, South Carolina, South 

Dakota, Tennessee, Texas, Vermont, 

Virginia, West Virginia, and Wisconsin). 

We calculated each State’s 

contribution to PM2.5 in each of the 62 

counties that are projected to be 

nonattainment in the 2010 base case 

(i.e., ‘‘modeled’’ nonattainment) and are 

also ‘‘monitored’’ nonattainment in 

2001–2003, as described in section 

VI.B.1.b. The maximum contribution 

from each upwind State to downwind 

PM2.5 nonattainment is provided in 

Table VI–7. The contributions from each 

State to nonattainment in each 

nonattainment county are provided in 

the NFR AQMTSD. Based on the Stateby-State modeling, there are 23 States 

and the District of Columbia 103 which 

contribute 0.2 μg/m3 or more to 

downwind PM2.5 nonattainment 

(Alabama, the District of Columbia, 

Florida, Georgia, Illinois, Indiana, Iowa, 

Kentucky, Louisiana, Maryland, 

Michigan, Minnesota, Mississippi, 

Missouri, New York, North Carolina, 

Ohio, Pennsylvania, South Carolina, 

Tennessee, Texas, Virginia, West 

Virginia, and Wisconsin). In Table VI–

8, we provide a list of the downwind 

nonattainment counties to which each 

upwind State contributes 0.2 μg/m3 or 

more (i.e., the upwind State-todownwind nonattainment ‘‘linkages’’).

TABLE VI–7.—MAXIMUM DOWNWIND

PM2.5 CONTRIBUTION (μG/M3) FOR

EACH OF 37 STATES

Upwind State 

Maximum 

downwind 

contribution 

Alabama .................................... 0.98 

Arkansas ................................... 0.19 

Connecticut ............................... <0.05 

Delaware ................................... 0.14 

Florida ....................................... 0.45 

Georgia ..................................... 1.27 

Illinois ........................................ 1.02 

Indiana ...................................... 0.91 

Iowa .......................................... 0.28 

Kansas ...................................... 0.11 

Kentucky ................................... 0.90 

TABLE VI–7.—MAXIMUM DOWNWIND

PM2.5 CONTRIBUTION (μG/M3) FOR

EACH OF 37 STATES—Continued

Upwind State 

Maximum 

downwind 

contribution 

Louisiana .................................. 0.25 

Maine ........................................ <0.05 

Maryland/DC ............................. 0.69 

Massachusetts .......................... 0.07 

Michigan ................................... 0.62 

Minnesota ................................. 0.21 

Mississippi ................................ 0.23 

Missouri .................................... 1.07 

Nebraska .................................. 0.07 

New Hampshire ........................ <0.05 

New Jersey ............................... 0.13 

New York .................................. 0.34 

North Carolina .......................... 0.31 

North Dakota ............................ 0.11 

Ohio .......................................... 1.67 

Oklahoma ................................. 0.12 

Pennsylvania ............................ 0.89 

Rhode Island ............................ <0.05 

South Carolina .......................... 0.40 

South Dakota ............................ <0.05 

Tennessee ................................ 0.65 

Texas ........................................ 0.29 

Vermont .................................... <0.05 

Virginia ...................................... 0.44 

West Virginia ............................ 0.84 

Wisconsin ................................. 0.56 

TABLE VI–8.—UPWIND STATE-TO-DOWNWIND NONATTAINMENT COUNTY SIGNIFICANT ‘‘LINKAGES’’ FOR PM2.5.

Upwind 

states 

Total 

linkages 

Downwind counties 

AL ......... 21 Bibb GA ............................... Cabell WV ........................... Catawba NC ........................ Clark IN. 

Clarke GA ............................ Clayton GA .......................... Cobb GA ............................. Davidson NC. 

DeKalb GA .......................... Dubois IN ............................ Fayette KY .......................... Floyd GA. 

Fulton GA ............................ Hamilton OH ........................ Hamilton TN ........................ Jefferson KY. 

Knox TN .............................. Lawrence OH ...................... Scioto OH ............................ Vanderburgh IN. 

Walker GA.

FL ......... 7 Bibb GA ............................... Clarke GA ............................ Clayton GA .......................... Cobb GA. 

DeKalb GA .......................... Jefferson AL ........................ Russell AL.

GA ........ 17 Butler OH ............................ Cabell WV ........................... Catawba NC ........................ Clark IN. 

Davidson NC ....................... Fayette KY .......................... Hamilton OH ........................ Hamilton TN. 

Jefferson AL ........................ Jefferson KY ........................ Kanawha WV ...................... Knox TN. 

Lawrence OH ...................... Montgomery OH .................. Russell AL ........................... Scioto OH. 

Vanderburgh IN.

IL ........... 23 Allegheny PA ....................... Butler OH ............................ Cabell WV ........................... Clark IN. 

Cuyahoga OH ..................... Dubois IN ............................ Fayette KY .......................... Franklin OH. 

Hamilton OH ........................ Hamilton TN ........................ Jefferson AL ........................ Jefferson KY. 

Kanawha WV ...................... Lake IN ................................ Lawrence OH ...................... Mahoning OH. 

Marion IN ............................. Montgomery OH .................. Scioto OH ............................ Stark OH. 

Summit OH .......................... Vanderburgh IN ................... Wayne MI ............................

IN .......... 46 Allegheny PA ....................... Beaver PA ........................... Berkeley WV ....................... Bibb GA.

Brooke WV .......................... Butler OH ............................ Cabell WV ........................... Cambria PA. 

Catawba NC ........................ Clarke GA ............................ Clayton GA .......................... Cobb GA. 

Cook IL ................................ Cuyahoga OH ..................... Davidson NC ....................... DeKalb GA. 

Fayette KY .......................... Floyd GA ............................. Franklin OH ......................... Fulton GA. 

Hamilton OH ........................ Hamilton TN ........................ Hancock WV ....................... Jefferson AL. 

Jefferson KY ........................ Jefferson OH ....................... Kanawha WV ...................... Knox TN. 

25248 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

TABLE VI–8.—UPWIND STATE-TO-DOWNWIND NONATTAINMENT COUNTY SIGNIFICANT ‘‘LINKAGES’’ FOR PM2.5.—Continued

Lancaster PA ....................... Lawrence OH ...................... Madison IL ........................... Mahoning OH. 

Marion WV .......................... Marshall WV ........................ Montgomery OH .................. Ohio WV. 

Russell AL ........................... St. Clair IL ........................... Scioto OH ............................ Stark OH. 

Summit OH .......................... Walker GA ........................... Wayne MI ............................ Washington PA. 

Westmoreland PA ............... Wood WV.

IA .......... 5 Cook IL ................................ Lake IN ................................ Madison IL ........................... Marion IN. 

St. Clair IL.

KY ......... 35 Allegheny PA ....................... Butler OH ............................ Cabell WV ........................... Catawba NC. 

Clark IN ............................... Clarke GA ............................ Cobb GA ............................. Cuyahoga OH. 

Davidson NC ....................... Dubois IN ............................ Floyd GA ............................. Franklin OH. 

Hamilton OH ........................ Hamilton TN ........................ Jefferson AL ........................ Jefferson OH. 

Kanawha WV ...................... Knox TN .............................. Lawrence OH ...................... Madison IL. 

Mahoning OH ...................... Marion IN ............................. Marion WV .......................... Marshall WV. 

Montgomery OH .................. Ohio WV .............................. St. Clair IL ........................... Scioto OH. 

Stark OH ............................. Summit OH .......................... Vanderburgh IN ................... Walker GA. 

Washington PA ................... Westmoreland PA ............... Wood WV..

LA ......... 2 Jefferson AL ........................ Russell AL.

MD/DC .. 13 Berkeley WV ....................... Berks PA ............................. Cambria PA ......................... Dauphin PA. 

Delaware PA ....................... District of Columbia ............. Lancaster PA ....................... New Castle DE. 

New York NY ...................... Philadelphia PA ................... Union NJ ............................. Westmoreland PA. 

York PA.

MI .......... 36 Allegheny PA ....................... Beaver PA ........................... Berks PA ............................. Brooke WV. 

Butler OH ............................ Cabell WV ........................... Cambria PA ......................... Clark IN. 

Cook IL ................................ Cuyahoga OH ..................... Dauphin PA ......................... Delaware PA. 

Fayette KY .......................... Franklin OH ......................... Hamilton OH ........................ Hancock WV. 

Jefferson OH ....................... Lake IN ................................ Lancaster PA ....................... Lawrence OH. 

Mahoning OH ...................... Marion IN ............................. Marion WV .......................... Marshall WV. 

Montgomery OH .................. New Castle DE .................... Ohio WV .............................. Philadelphia PA. 

Scioto OH ............................ Stark OH ............................. Summit OH .......................... Union NJ. 

Washington PA ................... Westmoreland PA ............... Wood WV ............................ York PA. 

MN ........ 2 Cook IL ................................ Lake IN.

MO ........ 9 Clark IN ............................... Cook IL ................................ Dubois IN ............................ Jefferson KY. 

Lake IN ................................ Madison IL ........................... Marion IN ............................. St. Clair IL.

Vanderburgh IN..

MS ........ 1 Jefferson AL.

NY ......... 5 Berks PA ............................. Lancaster PA ....................... New Castle DE .................... New Haven CT. 

Union NJ.

NC ........ 7 Anne Arundel MD ................ Baltimore City ...................... Bibb GA ............................... Clarke GA. 

District of Columbia ............. Kanawha WV ...................... Knox TN..

OH ........ 51 Anne Arundel MD ................ Allegheny PA ....................... Baltimore City MD ............... Beaver PA. 

Berkeley WV ....................... Berks PA ............................. Bibb GA ............................... Brooke WV. 

Cabell WV ........................... Cambria PA ......................... Catawba NC ........................ Clark IN. 

Clarke GA ............................ Clayton GA .......................... Cobb GA ............................. Cook IL. 

Dauphin PA ......................... Davidson NC ....................... DeKalb GA .......................... Delaware PA. 

District of Columbia ............. Dubois IN ............................ Fayette KY .......................... Floyd GA. 

Fulton GA ............................ Hamilton TN ........................ Hancock WV ....................... Jefferson AL. 

Jefferson KY ........................ Kanawha WV ...................... Knox TN .............................. Lake IN. 

Lancaster PA ....................... Madison IL ........................... Marion IN ............................. Marion WV. 

Marshall WV ........................ New Castle DE .................... New York NY ...................... Ohio WV. 

Philadelphia PA ................... Russell AL ........................... St. Clair IL ........................... Union NJ. 

Vanderburgh IN ................... Walker GA ........................... Washington PA ................... Wayne MI. 

Westmoreland PA ............... Wood WV ............................ York PA.

PA ......... 25 Anne Arundel MD ................ Baltimore City ...................... Berkeley WV ....................... Brooke WV. 

Cabell WV ........................... Catawba NC ........................ Clarke GA ............................ Cuyahoga OH. 

Davidson NC ....................... District of Columbia ............. Hancock WV ....................... Jefferson OH. 

Kanawha WV ...................... Lawrence OH ...................... Mahoning OH ...................... Marion WV. 

Marshall WV ........................ New Castle DE .................... New York NY ...................... Ohio WV. 

Stark OH ............................. Summit OH .......................... Union NJ ............................. Wayne MI. 

Wood WV.

SC ......... 9 Bibb GA ............................... Catawba NC ........................ Clarke GA ............................ Clayton GA. 

Cobb GA ............................. Davidson NC ....................... DeKalb GA .......................... Fulton GA. 

Russell AL.

TN ......... 23 Bibb GA ............................... Butler OH ............................ Cabell WV ........................... Catawba NC. 

Clark IN ............................... Clarke GA ............................ Clayton GA .......................... Cobb GA. 

Davidson NC ....................... DeKalb GA .......................... Dubois IN ............................ Fayette KY. 

Floyd GA ............................. Fulton GA ............................ Hamilton OH ........................ Jefferson AL. 

Jefferson KY ........................ Kanawha WV ...................... Lawrence OH ...................... Russell AL. 

Scioto OH ............................ Vanderburgh TN .................. Walker GA. 

TX ......... 2 Madison IL ........................... St Clair IL.

VA ......... 13 Anne Arundel MD ................ Baltimore City MD ............... Berkeley WV ....................... Berks PA. 

Catawba NC ........................ Dauphin PA ......................... Davidson NC ....................... Delaware PA. 

District of Columbia ............. Lancaster PA ....................... New Castle DE .................... Philadelphia PA. 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25249

104As noted above, we combined Maryland and 

the District of Columbia as a single entity in our 

contribution modeling. This is a logical approach 

because of the small size of the District of Columbia 

and, hence, its emissions and its close proximity to 

Maryland. Under our analysis, Maryland and the 

District of Columbia are linked as significant 

contributors to the same downwind nonattainment 

counties. The EPA received no adverse comment on 

this approach. We also considered these entities 

separately, and in view of the close proximity of 

these two areas we believe that Maryland is linked 

as a significant contributor to nonattainment in the 

District of Columbia and that the District of 

Columbia is linked as a significant contributor to 

nonattainment in Maryland.

TABLE VI–8.—UPWIND STATE-TO-DOWNWIND NONATTAINMENT COUNTY SIGNIFICANT ‘‘LINKAGES’’ FOR PM2.5.—Continued

York PA.

WV ........ 33 Anne Arundel MD ................ Allegheny PA ....................... Baltimore City MD ............... Beaver PA. 

Berks PA ............................. Butler OH ............................ Cambria PA ......................... Catawba NC. 

Clarke GA ............................ Cuyahoga OH ..................... Dauphin PA ......................... Davidson NC. 

Delaware PA ....................... District of Columbia ............. Fayette KY .......................... Franklin OH. 

Hamilton OH ........................ Jefferson OH ....................... Knox TN .............................. Lancaster PA. 

Lawrence OH ...................... Mahoning OH ...................... Montgomery OH .................. New Castle DE. 

New York NY ...................... Philadelphia PA ................... Scioto OH ............................ Stark OH. 

Summit OH .......................... Union NJ ............................. Washington PA ................... Westmoreland PA. 

York PA.

WI ......... 4 Cook IL ................................ Lake IN ................................ Marion IN ............................. Wayne MI. 

2. Results of 8-Hour Ozone Contribution 

Modeling

In this section, we present the results 

of air quality modeling to determine 

which upwind States contribute 

significantly (before considering cost) to 

8-hour ozone nonattainment in 

downwind States. The analytical 

procedures to determine which States 

make a significant contribution are 

based on the zero-out and source 

apportionment modeling techniques 

using CAMX, as described in section 

VI.C.2 and in the NFR AQMTSD. We 

performed ozone contribution modeling 

using both of these techniques for 31 

States in the East and the District of 

Columbia (i.e., Alabama, Arkansas, 

Connecticut, Delaware, Georgia, Florida, 

Iowa, Illinois, Indiana, Kentucky, 

Louisiana, Massachusetts, Maine, 

Maryland combined with the District of 

Columbia, Michigan, Minnesota, 

Mississippi, Missouri, New Hampshire, 

New Jersey, New York, North Carolina, 

Ohio, Pennsylvania, Rhode Island, 

South Carolina, Tennessee, Vermont, 

Virginia, West Virginia, and Wisconsin). 

We evaluated the interstate ozone 

contributions from each of the 31 

upwind States and the District of 

Columbia to each of the 40 counties that 

are projected to be nonattainment in the 

2010 base case (i.e., ‘‘modeled’’

nonattainment) and are also 

‘‘monitored’’ nonattainment in 2001–

2003, as described in section VI.B.2.b. 

We analyzed the contributions from 

upwind States to these counties in terms 

of various metrics, described above and 

in more detail in the NFR AQMTSD. 

Based on the State-by-State modeling, 

there are 25 States and the District of 

Columbia 104 which make a significant 

contribution (before considering cost) to 

8-hour ozone nonattainment in 

downwind States (i.e., Alabama, 

Arkansas, Connecticut, Delaware, the 

District of Columbia, Florida, Iowa, 

Illinois, Indiana, Kentucky, Louisiana, 

Massachusetts, Maryland, Michigan, 

Mississippi, Missouri, New Jersey, New 

York, North Carolina, Ohio, 

Pennsylvania, South Carolina, 

Tennessee, Virginia, West Virginia, and 

Wisconsin). In Table VI–9, we provide 

a list of the downwind nonattainment 

counties to which each upwind State 

makes a significant contribution (i.e., 

the upwind State-to-downwind 

nonattainment ‘‘linkages’’).

TABLE VI–9.—UPWIND STATE-TO-DOWNWIND NONATTAINMENT COUNTY SIGNIFICANT ‘‘LINKAGES’’ FOR 8-HOUR OZONE. 

Upwind 

states 

Total 

linkages 

Downwind counties 

AL ......... 3 Fulton GA ............................ Harris TX ............................. Jefferson TX. 

AR ......... 3 Galveston TX ...................... Harris TX ............................. Jefferson TX. 

CT ......... 2 Kent RI ................................ Suffolk NY. 

DE ......... 13 Bucks PA ............................. Camden NJ ......................... Chester PA .......................... Gloucester NJ. 

Hunterdon NJ ...................... Mercer NJ ............................ Middlesex NJ ....................... Monmouth NJ. 

Montgomery PA .................. Morris NJ ............................. Ocean NJ ............................ Philadelphia PA. 

Suffolk NY.

FL ......... 1 Fulton GA 

IA .......... 3 Kenosha WI ......................... Macomb MI ......................... Sheboygan WI. 

IL ........... 5 Geauga OH ......................... Kenosha WI ......................... Macomb MI ......................... Ozaukee WI. 

Sheboygan WI. 

IN .......... 5 Geauga OH ......................... Kenosha WI ......................... Macomb MI ......................... Ozaukee WI.

Sheboygan WI..

KY ......... 3 Fulton GA ............................ Geauga OH ......................... Macomb MI. ........................

LA ......... 3 Galveston TX ...................... Harris TX ............................. Jefferson TX. 

MA ........ 2 Kent RI ................................ Middlesex NJ. 

MD/DC .. 23 Arlington VA ........................ Bergen NJ ........................... Bucks PA ............................. Camden NJ. 

Chester PA .......................... District of Columbia ............. Erie NY ................................ Fairfax VA. 

Fairfield CT .......................... Gloucester NJ ..................... Hunterton NJ ....................... Mercer NJ. 

Middlesex NJ ....................... Monmouth NJ ...................... Montgomery PA .................. Morris NJ. 

25250 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

105 In addition to the SO2 and NOX reductions in 

these States, we also modeled summer-season only 

EGU NOX controls for Connecticut and 

Massachusetts, which significantly contribute to 

ozone, but not to PM2.5 nonattainment in downwind 

areas.

106For the purposes of this discussion, we have 

calculated the percent reduction in total EGU 

TABLE VI–9.—UPWIND STATE-TO-DOWNWIND NONATTAINMENT COUNTY SIGNIFICANT ‘‘LINKAGES’’ FOR 8-HOUR OZONE.—

Continued

New Castle DE .................... New Haven CT .................... Ocean NJ ............................ Philadelphia PA. 

Richmond NY ...................... Suffolk NY ........................... Westchester NY ..................

MI .......... 19 Anne Arundel MD ................ Bergen NJ ........................... Bucks PA ............................. Camden NJ. Cecil MD .............................. Chester PA .......................... Erie NY ................................ Geauga OH. 

Gloucester NJ ..................... Kent MD .............................. Mercer NJ ............................ Middlesex NJ. 

Monmouth NJ ...................... Morris NJ ............................. New Castle DE .................... Ocean NJ. 

Philadelphia PA ................... Richmond NY ...................... Suffolk NY ...........................

MO ........ 4 Geauga OH ......................... Kenosha WI ......................... Ozaukee WI ........................ Sheboygan WI.

MS ........ 2 Harris TX ............................. Jefferson TX. 

NC ........ 8 Anne Arundel MD ................ Fulton GA ............................ Harford MD .......................... Kent MD. 

Newcastle DE ...................... Suffolk NY ........................... Bucks PA ............................. Chester PA. 

NJ ......... 10 Erie NY ................................ Fairfield CT .......................... Kent RI ................................ Middlesex CT. 

Montgomery PA .................. New Haven CT .................... Philadelphia PA ................... Richmond NY. 

Suffolk NY ........................... Westchester NY. 

NY ......... 9 Fairfield CT .......................... Kent RI ................................ Mercer NJ ............................ Middlesex CT. 

Middlesex NJ ....................... Monmouth NJ ...................... Morris NJ ............................. New Haven CT. 

Ocean NJ. 

Anne Arundel MD ................ Arlington VA ........................ Bergen NJ ........................... Bucks PA. 

OH ........ 28 Camden NJ ......................... Cecil MD .............................. Chester PA .......................... District of Columbia. 

Fairfax VA ........................... Fairfield CT .......................... Gloucester NJ ..................... Harford MD. 

Hunterton NJ ....................... Kent MD .............................. Kent RI ................................ Macomb MI. 

Mercer NJ ............................ Middlesex CT ...................... Middlesex NJ ....................... Monmouth NJ. 

Montgomery PA .................. Morris NJ ............................. New Castle DE .................... New Haven CT. 

Ocean NJ ............................ Philadelphia PA ................... Suffolk NY ........................... Westchester NY. 

PA ......... 25 Anne Arundel MD ................ Arlington VA ........................ Bergen NJ ........................... Camden NJ. 

Cecil MD .............................. District of Columbia ............. Erie NY ................................ Fairfax VA. 

Fairfield CT .......................... Gloucester NJ ..................... Harford MD .......................... Hunterton NJ. 

Kent MD .............................. Kent RI ................................ Mercer NJ ............................ Middlesex CT. 

Middlesex NJ ....................... Monmouth NJ ...................... Morris NJ ............................. New Castle DE. 

New Haven CT .................... Ocean NJ ............................ Richmond NY ...................... Suffolk NY. 

Westchester NY. 

SC ......... 1 Fulton GA. 

TN ......... 1 Fulton GA. 

VA ......... 26 Anne Arundel MD ................ Bergen NJ ........................... Bucks PA ............................. Camden NJ.

Cecil MD .............................. Chester PA .......................... District of Columbia ............. Erie NY. 

Fairfield CT .......................... Gloucester NJ ..................... Harford MD .......................... Hunterton NJ. 

Kent MD .............................. Kent RI ................................ Mercer NJ ............................ Middlesex CT. 

Middlesex NJ ....................... Monmouth NJ ...................... Morris NJ ............................. New Castle DE. 

New Haven CT .................... Ocean NJ ............................ Philadelphia PA ................... Richmond NY. 

Suffolk NY ........................... Westchester NY. 

WI ......... 2 Erie NY ................................ Macomb MI. 

WV ........ 25 Anne Arundel MD ................ Bergen NJ ........................... Bucks PA ............................. Camden NJ. 

Cecil MD .............................. Chester PA .......................... Fairfax VA ........................... Fairfield CT. 

Fulton GA ............................ Gloucester NJ ..................... Harford MD .......................... Hunterton NJ. 

Kent MD .............................. Mercer NJ ............................ Middlesex NJ ....................... Monmouth NJ. 

Montgomery PA .................. Morris NJ ............................. New Castle DE .................... New Haven CT. 

Ocean NJ ............................ Philadelphia PA ................... Richmond NY ...................... Suffolk NY. 

Westchester NY.

E. What are the Estimated Air Quality 

Impacts of the Final Rule? 

In this section, we describe the air 

quality modeling performed to 

determine the projected impacts on 

PM2.5 and 8-hour ozone of the SO2 and 

NOX emissions reductions in the control 

region modeled. The modeling used to 

estimate the air quality impact of these 

reductions assumes annual SO2 and 

NOX controls for Arkansas, Delaware, 

and New Jersey in addition to the 23-

States plus the District of Columbia. 

Since Arkansas, Delaware, and New 

Jersey are not included in the final CAIR 

region for PM2.5, the modeled estimated 

impacts on PM2.5 are overstated for 

today’s final rule. However, EPA plans 

to include Delaware and New Jersey in 

the CAIR region for PM2.5 through a 

separate regulatory process. Thus, the 

estimates are reflective of the total 

impacts expected for CAIR assuming 

Delaware and New Jersey will become 

part of the annual SO2 and NOX trading 

programs. 

As discussed in section IV, EPA 

analyzed the impacts of the regional 

emissions reductions in both 2010 and 

2015. These impacts are quantified by 

comparing air quality modeling results 

for the regional control scenario to the 

modeling results for the corresponding 

2010 and 2015 base case scenarios. The 

2010 and 2015 emissions reductions 

from the power generation sector 

include a two-phase cap and trade 

program covering the control region 

modeled (i.e., the 23 States plus the 

District of Columbia included in today’s 

rule and Arkansas, Delaware, and New 

Jersey).105 Phase 1 of the regional 

strategy (the 2010 reductions) is forecast 

to reduce total EGU SO2 emissions 106 in 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25251

emissions which includes units greater than and 

less than 25 MW.

the control region modeled by 40 

percent in 2010. Phase 2 (the 2015 

reductions) is forecast to provide a 48 

percent reduction in EGU SO2 emissions 

compared to the base case in 2015. 

When fully implemented post-2015, we 

expect this rule to result in more than 

a 70 percent reduction in EGU SO2

emissions compared to current 

emissions levels. The reductions at full 

implementation occur post-2015 due to 

the existing title IV bank of SO2

allowances, which can be used under 

the CAIR program. The net effect of the 

strategy on total SO2 emissions in the 

control region modeled considering all 

sources of emissions, is a 28 percent 

reduction in 2010 and a 32 percent 

reduction in 2015.

For NOX, Phase 1 of the strategy is 

forecast to reduce total EGU emissions 

by 44 percent in 2009. Total NOX

emissions across the control region (i.e., 

includes all sources) are 11 percent 

lower in the 2010 CAIR scenario 

compared to the emissions in the 2010 

base case. In Phase 2, EGU NOX

emissions are projected to decline by 54 

percent in 2015 in this region. Total 

NOX emissions from all anthropogenic 

sources are projected to be reduced by 

14 percent in 2015. The percent change 

in emissions by State for SO2 and NOX

in 2010 and 2015 for the regional 

control strategy modeled are provided 

in the NFR EITSD.

1. Estimated Impacts on PM2.5

Concentrations and Attainment 

We determined the impacts on PM2.5

of the CAIR regional strategy by running 

the CMAQ model for this strategy and 

comparing the results to the PM2.5

concentrations predicted for the 2010 

and 2015 base cases. In brief, we ran the 

CMAQ model for the regional strategy in 

both 2010 and 2015. The model 

predictions were used to project future 

PM2.5 concentrations for CAIR in 2010 

and 2015 using the SMAT technique, as 

described in section VI.B.1. We 

compared the results of the 2010 and 

2015 regional strategy modeling to the 

corresponding results from the 2010 and 

2015 base cases to quantify the expected 

impacts of CAIR. 

The impacts of the SO2 and NOX

emissions reductions expected from 

CAIR on PM2.5 in 2010 and 2015 are 

provided in Table VI–10 and Table VI–

11, respectively. In these tables, 

counties shown in bold/italics are 

projected to come into attainment with 

CAIR.

TABLE VI–10.—PROJECTED PM2.5 CONCENTRATIONS (μG/M3) FOR THE 2010 BASE CASE AND CAIR AND THE IMPACT OF

CAIR REGIONAL CONTROLS IN 2010 

State County 2010 Base 

case 2010 CAIR Impact of CAIR 

Alabama ................................................................ DeKalb Co ............................................................ 15.23 13.97 ¥1.26 

Alabama ................................................................ Jefferson Co ......................................................... 18.57 17.46 ¥1.11 

Alabama ................................................................ Montgomery Co .................................................... 15.12 14.10 ¥1.02 

Alabama ................................................................ Morgan Co ............................................................ 15.29 14.11 ¥1.18 

Alabama ................................................................ Russell Co ............................................................ 16.17 15.15 ¥1.02 

Alabama ................................................................ Talladega Co ........................................................ 15.34 14.00 ¥1.34 

Delaware ............................................................... New Castle Co ..................................................... 16.56 14.84 ¥1.72 

District of Columbia .............................................. ............................................................................... 15.84 13.68 ¥2.16 

Georgia ................................................................. Bibb Co ................................................................. 16.27 15.17 ¥1.10 

Georgia ................................................................. Clarke Co ............................................................. 16.39 14.96 ¥1.43 

Georgia ................................................................. Clayton Co ............................................................ 17.39 16.29 ¥1.10 

Georgia ................................................................. Cobb Co ............................................................... 16.57 15.35 ¥1.22 

Georgia ................................................................. DeKalb Co ............................................................ 16.75 15.70 ¥1.05 

Georgia ................................................................. Floyd Co ............................................................... 16.87 15.87 ¥1.00 

Georgia ................................................................. Fulton Co .............................................................. 18.02 16.98 ¥1.04 

Georgia ................................................................. Hall Co .................................................................. 15.60 14.28 ¥1.32 

Georgia ................................................................. Muscogee Co ....................................................... 15.65 14.57 ¥1.08 

Georgia ................................................................. Richmond Co ........................................................ 15.68 14.64 ¥1.04 

Georgia ................................................................. Walker Co ............................................................. 15.43 14.22 ¥1.21 

Georgia ................................................................. Washington Co ..................................................... 15.31 14.22 ¥1.09 

Georgia ................................................................. Wilkinson Co ........................................................ 16.27 15.22 ¥1.05 

Illinois .................................................................... Cook Co ............................................................... 17.52 16.88 ¥0.64 

Illinois .................................................................... Madison Co .......................................................... 16.66 15.96 ¥0.70 

Illinois .................................................................... St. Clair Co ........................................................... 16.24 15.54 ¥0.70 

Indiana .................................................................. Clark Co ............................................................... 16.51 15.15 ¥1.36 

Indiana .................................................................. Dubois Co ............................................................. 15.73 14.37 ¥1.36 

Indiana .................................................................. Lake Co ................................................................ 17.26 16.48 ¥0.78 

Indiana .................................................................. Marion Co ............................................................. 16.83 15.54 ¥1.29 

Indiana .................................................................. Vanderburgh Co ................................................... 15.54 14.26 ¥1.28 

Kentucky ............................................................... Boyd Co ................................................................ 15.23 13.38 ¥1.85 

Kentucky ............................................................... Bullitt Co ............................................................... 15.10 13.67 ¥1.43 

Kentucky ............................................................... Fayette Co ............................................................ 15.95 14.17 ¥1.78 

Kentucky ............................................................... Jefferson Co ......................................................... 16.71 15.44 ¥1.27 

Kentucky ............................................................... Kenton Co ............................................................ 15.30 13.72 ¥1.58 

Maryland ............................................................... Anne Arundel Co .................................................. 15.26 12.98 ¥2.28 

Maryland ............................................................... Baltimore city ........................................................ 16.96 14.88 ¥2.08 

Michigan ................................................................ Wayne Co ............................................................. 19.41 18.23 ¥1.18 

Missouri ................................................................. St. Louis City ........................................................ 15.10 14.40 ¥0.70 

New Jersey ........................................................... Union Co .............................................................. 15.05 13.60 ¥1.45 

New York .............................................................. New York Co ........................................................ 16.19 14.95 ¥1.24 

North Carolina ....................................................... Catawba Co .......................................................... 15.48 14.07 ¥1.41 

North Carolina ....................................................... Davidson Co ......................................................... 15.76 14.36 ¥1.40 

25252 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

TABLE VI–10.—PROJECTED PM2.5 CONCENTRATIONS (μG/M3) FOR THE 2010 BASE CASE AND CAIR AND THE IMPACT OF

CAIR REGIONAL CONTROLS IN 2010—Continued

State County 2010 Base 

case 2010 CAIR Impact of CAIR 

North Carolina ....................................................... Mecklenburg Co ................................................... 15.22 13.92 ¥1.30 

Ohio ...................................................................... Butler Co .............................................................. 16.45 15.03 ¥1.42 

Ohio ...................................................................... Cuyahoga Co ....................................................... 18.84 17.11 ¥1.73 

Ohio ...................................................................... Franklin Co ........................................................... 16.98 15.13 ¥1.85 

Ohio ...................................................................... Hamilton Co .......................................................... 18.23 16.61 ¥1.62 

Ohio ...................................................................... Jefferson Co ......................................................... 17.94 15.64 ¥2.30 

Ohio ...................................................................... Lawrence Co ........................................................ 16.10 14.11 ¥1.99 

Ohio ...................................................................... Mahoning Co ........................................................ 15.39 13.40 ¥1.99 

Ohio ...................................................................... Montgomery Co .................................................... 15.41 13.83 ¥1.58 

Ohio ...................................................................... Scioto Co .............................................................. 18.13 15.98 ¥2.15 

Ohio ...................................................................... Stark Co ............................................................... 17.14 15.08 ¥2.06 

Ohio ...................................................................... Summit Co ............................................................ 16.47 14.69 ¥1.78 

Ohio ...................................................................... Trumbull Co .......................................................... 15.28 13.50 ¥1.78 

Pennsylvania ......................................................... Allegheny Co ........................................................ 20.55 18.01 ¥2.54 

Pennsylvania ......................................................... Beaver Co ............................................................ 15.78 13.61 ¥2.17 

Pennsylvania ......................................................... Berks Co ............................................................... 15.89 13.56 ¥2.33 

Pennsylvania ......................................................... Cambria Co .......................................................... 15.14 12.72 ¥2.42 

Pennsylvania ......................................................... Dauphin Co .......................................................... 15.17 12.88 ¥2.29 

Pennsylvania ......................................................... Delaware Co ......................................................... 15.61 13.94 ¥1.67 

Pennsylvania ......................................................... Lancaster Co ........................................................ 16.55 14.09 ¥2.46 

Pennsylvania ......................................................... Philadelphia Co .................................................... 16.65 14.98 ¥1.67 

Pennsylvania ......................................................... Washington Co ..................................................... 15.23 12.99 ¥2.24 

Pennsylvania ......................................................... Westmoreland Co ................................................. 15.16 12.60 ¥2.56 

Pennsylvania ......................................................... York Co ................................................................ 16.49 14.20 ¥2.29 

Tennessee ............................................................ Davidson Co ......................................................... 15.36 14.26 ¥1.10 

Tennessee ............................................................ Hamilton Co .......................................................... 16.89 15.57 ¥1.32 

Tennessee ............................................................ Knox Co ................................................................ 17.44 16.16 ¥1.28 

Tennessee ............................................................ Sullivan Co ........................................................... 15.32 14.01 ¥1.31 

West Virginia ......................................................... Berkeley Co .......................................................... 15.69 13.43 ¥2.26 

West Virginia ......................................................... Brooke Co ............................................................ 16.63 14.42 ¥2.21 

West Virginia ......................................................... Cabell Co .............................................................. 17.03 15.08 ¥1.95 

West Virginia ......................................................... Hancock Co .......................................................... 17.06 14.89 ¥2.17 

West Virginia ......................................................... Kanawha Co ......................................................... 17.56 15.27 ¥2.29 

West Virginia ......................................................... Marion Co ............................................................. 15.32 12.90 ¥2.42 

West Virginia ......................................................... Marshall Co .......................................................... 15.81 13.46 ¥2.35 

West Virginia ......................................................... Ohio Co ................................................................ 15.14 12.81 ¥2.33 

West Virginia ......................................................... Wood Co .............................................................. 16.66 14.14 ¥2.52 

TABLE VI–11.—PROJECTED PM2.5 CONCENTRATIONS (μG/M3) FOR THE 2015 BASE CASE AND CAIR AND THE IMPACT OF

CAIR REGIONAL CONTROLS IN 2015

State County 2015 Base 

case 2015 CAIR Impact of CAIR 

Alabama ................................................................ DeKalb Co ............................................................ 15.24 13.46 ¥1.78

Alabama ................................................................ Jefferson Co ......................................................... 18.85 17.36 ¥1.49

Alabama ................................................................ Montgomery Co .................................................... 15.24 13.87 ¥1.37

Alabama ................................................................ Morgan Co ............................................................ 15.26 13.85 ¥1.41

Alabama ................................................................ Russell Co ............................................................ 16.10 14.66 ¥1.44

Alabama ................................................................ Talladega Co ........................................................ 15.22 13.35 ¥1.87

Delaware ............................................................... New Castle Co ..................................................... 16.47 14.41 ¥2.06

District of Columbia .............................................. ............................................................................... 15.57 13.11 ¥2.46

Georgia ................................................................. Bibb Co ................................................................. 16.41 14.83 ¥1.58

Georgia ................................................................. Chatham Co ......................................................... 15.06 13.86 ¥1.20

Georgia ................................................................. Clarke Co ............................................................. 16.15 14.10 ¥2.05

Georgia ................................................................. Clayton Co ............................................................ 17.46 15.85 ¥1.61

Georgia ................................................................. Cobb Co ............................................................... 16.51 14.67 ¥1.84

Georgia ................................................................. DeKalb Co ............................................................ 16.82 15.29 ¥1.53

Georgia ................................................................. Floyd Co ............................................................... 17.33 15.79 ¥1.54

Georgia ................................................................. Fulton Co .............................................................. 18.00 16.47 ¥1.53

Georgia ................................................................. Hall Co .................................................................. 15.36 13.48 ¥1.88

Georgia ................................................................. Muscogee Co ....................................................... 15.58 14.06 ¥1.52

Georgia ................................................................. Richmond Co ........................................................ 15.76 14.23 ¥1.53

Georgia ................................................................. Walker Co ............................................................. 15.37 13.65 ¥1.72

Georgia ................................................................. Washington Co ..................................................... 15.34 13.67 ¥1.67

Georgia ................................................................. Wilkinson Co ........................................................ 16.54 15.01 ¥1.53

Illinois .................................................................... Cook Co ............................................................... 17.71 16.95 ¥0.76

Illinois .................................................................... Madison Co .......................................................... 16.90 16.07 ¥0.83

Illinois .................................................................... St. Clair Co ........................................................... 16.49 15.64 ¥0.85

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25253

TABLE VI–11.—PROJECTED PM2.5 CONCENTRATIONS (μG/M3) FOR THE 2015 BASE CASE AND CAIR AND THE IMPACT OF

CAIR REGIONAL CONTROLS IN 2015—Continued

State County 2015 Base 

case 2015 CAIR Impact of CAIR 

Illinois .................................................................... Will Co .................................................................. 15.12 14.27 ¥0.85

Indiana .................................................................. Clark Co ............................................................... 16.37 14.79 ¥1.58

Indiana .................................................................. Dubois Co ............................................................. 15.66 14.16 ¥1.50

Indiana .................................................................. Lake Co ................................................................ 17.27 16.36 ¥0.91

Indiana .................................................................. Marion Co ............................................................. 16.77 15.38 ¥1.39

Indiana .................................................................. Vanderburgh Co ................................................... 15.56 14.17 ¥1.39

Kentucky ............................................................... Boyd Co ................................................................ 15.06 12.95 ¥2.11

Kentucky ............................................................... Fayette Co ............................................................ 15.62 13.54 ¥2.08

Kentucky ............................................................... Jefferson Co ......................................................... 16.61 15.13 ¥1.48

Kentucky ............................................................... Kenton Co ............................................................ 15.09 13.26 ¥1.83

Maryland ............................................................... Baltimore city ........................................................ 17.04 14.50 ¥2.54

Maryland ............................................................... Baltimore Co ......................................................... 15.08 12.75 ¥2.33

Michigan ................................................................ Wayne Co ............................................................. 19.28 17.95 ¥1.33

Mississippi ............................................................. Jones Co .............................................................. 15.18 14.06 ¥1.12

Missouri ................................................................. St. Louis city ......................................................... 15.34 14.50 ¥0.84

New York .............................................................. New York Co ........................................................ 15.76 14.33 ¥1.43

North Carolina ....................................................... Catawba Co .......................................................... 15.19 13.45 ¥1.74

North Carolina ....................................................... Davidson Co ......................................................... 15.34 13.61 ¥1.73

Ohio ...................................................................... Butler Co .............................................................. 16.32 14.67 ¥1.65

Ohio ...................................................................... Cuyahoga Co ....................................................... 18.60 16.67 ¥1.93

Ohio ...................................................................... Franklin Co ........................................................... 16.64 14.57 ¥2.07

Ohio ...................................................................... Hamilton Co .......................................................... 18.03 16.10 ¥1.93

Ohio ...................................................................... Jefferson Co ......................................................... 17.83 15.26 ¥2.57

Ohio ...................................................................... Lawrence Co ........................................................ 15.92 13.71 ¥2.21

Ohio ...................................................................... Mahoning Co ........................................................ 15.13 12.94 ¥2.19

Ohio ...................................................................... Montgomery Co .................................................... 15.16 13.33 ¥1.83

Ohio ...................................................................... Scioto Co .............................................................. 17.92 15.55 ¥2.37

Ohio ...................................................................... Stark Co ............................................................... 16.86 14.58 ¥2.28

Ohio ...................................................................... Summit Co ............................................................ 16.14 14.18 ¥1.96

Ohio ...................................................................... Trumbull Co .......................................................... 15.05 13.08 ¥1.97

Pennsylvania ......................................................... Allegheny Co ........................................................ 20.33 17.47 ¥2.86

Pennsylvania ......................................................... Beaver Co ............................................................ 15.54 13.09 ¥2.45

Pennsylvania ......................................................... Berks Co ............................................................... 15.66 12.99 ¥2.67

Pennsylvania ......................................................... Delaware Co ......................................................... 15.52 13.52 ¥2.00

Pennsylvania ......................................................... Lancaster Co ........................................................ 16.28 13.33 ¥2.95

Pennsylvania ......................................................... Philadelphia Co .................................................... 16.53 14.53 ¥2.00

Pennsylvania ......................................................... York Co ................................................................ 16.22 13.46 ¥2.76

Tennessee ............................................................ Davidson Co ......................................................... 15.36 14.02 ¥1.34

Tennessee ............................................................ Hamilton Co .......................................................... 16.82 14.94 ¥1.88

Tennessee ............................................................ Knox Co ................................................................ 17.34 15.61 ¥1.73

Tennessee ............................................................ Shelby Co ............................................................. 15.17 14.19 ¥0.98

Tennessee ............................................................ Sullivan Co ........................................................... 15.37 13.77 ¥1.60

West Virginia ......................................................... Berkeley Co .......................................................... 15.32 12.73 ¥2.59

West Virginia ......................................................... Brooke Co ............................................................ 16.51 14.05 ¥2.46

West Virginia ......................................................... Cabell Co .............................................................. 16.86 14.64 ¥2.22

West Virginia ......................................................... Hancock Co .......................................................... 16.97 14.54 ¥2.43

West Virginia ......................................................... Kanawha Co ......................................................... 17.17 14.66 ¥2.51

West Virginia ......................................................... Marshall Co .......................................................... 15.52 12.87 ¥2.65

West Virginia ......................................................... Wood Co .............................................................. 16.69 13.88 ¥2.81

As described in section VI.B.1, we 

project that 79 counties in the East will 

be nonattainment for PM2.5 in the 2010 

base case. We estimate that, on average, 

the regional strategy will reduce PM2.5

in these 79 counties by 1.6 μg/m3. In 

over 90 percent of the nonattainment 

counties (i.e., 74 out of 79 counties), we 

project that PM2.5 will be reduced by at 

least 1.0 μg/m3. In over 25 percent of the 

79 nonattainment counties (i.e., 23 of 

the 79 counties), we project PM2.5

concentrations will decline by of more 

than 2.0 μg/m3. Of the 79 counties that 

are nonattainment in the 2010 Base, we 

project that 51 counties will come into 

attainment as a result of the SO2 and 

NOX emissions reductions expected 

from the regional controls. Even those 

28 counties that remain nonattainment 

in 2010 after implementation of the 

regional strategy will be closer to 

attainment as a result of these emissions 

reductions. Specifically, the average 

reduction of PM2.5 in the 28 residual 

nonattainment counties is projected to 

be 1.3 μg/m3. After implementation of 

the regional controls, we project that 18 

of the 28 residual nonattainment 

counties in 2010 will be within 1.0 μg/

m3 of the NAAQS and 12 counties will 

be within 0.5 μg/m3 of attainment.

In 2015 we are projecting that PM2.5

in the 74 base case nonattainment 

counties will be reduced by 1.8 μg/m3, 

on average, as a result of the SO2 and 

NOX reductions in the regional strategy. 

In over 90 percent of the nonattainment 

counties (i.e., 67 of the 74 counties) 

concentrations of PM2.5 are predicted to 

be reduced by at least 1.0 μg/m3. In over 

35 percent of the counties (i.e., 27 of the 

74 counties), we project the regional 

strategy to reduce PM2.5 by more than 

2.0 μg/m3. As a result of the reductions 

in PM2.5, 56 nonattainment counties are 

projected to come into attainment in 

2015. The remaining 18 nonattainment 

25254 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

counties are projected to be closer to 

attainment with the regional strategy. 

Our modeling results indicate that PM2.5

will be reduced in the range of 0.7 μg/

m3 to 2.9 μg/m3 in these 18 counties. 

The average reduction across these 18 

residual nonattainment counties is 1.5 

μg/m3. 

Thus, the SO2 and NOX emissions 

reductions which will result from the 

regional strategy will greatly reduce the 

extent of PM2.5 nonattainment by 2010 

and beyond. These emissions reductions 

are expected to substantially reduce the 

number of PM2.5 nonattainment 

counties in the East and make 

attainment easier for those counties that 

remain nonattainment by substantially 

lowering PM2.5 concentrations in these 

residual nonattainment counties. 

2. Estimated Impacts on 8-Hour Ozone 

Concentrations and Attainment 

We determined the impacts on 8-hour 

ozone of the regional strategy by 

running the CAMX model for this 

strategy and comparing the results to the 

ozone concentrations predicted for the 

2010 and 2015 base cases. In brief, we 

ran the CAMX model for the regional 

strategy in both 2010 and 2015. The 

model predictions were used to project 

future 8-hour ozone concentrations for 

the regional strategy in 2010 and 2015 

using the Relative Reduction Factor 

technique, as described in section 

VI.B.1. We compared the results of the 

2010 and 2015 regional strategy 

modeling to the corresponding results 

from the 2010 and 2015 base cases to 

quantify the expected impacts of the 

regional controls. 

The results of the regional strategy 

ozone modeling are expressed in terms 

of the expected reductions in projected 

8-hour concentrations and the 

implications for future nonattainment. 

The impacts of the regional NOX

emissions reductions on 8-hour ozone 

in 2010 and 2015 are provided in Table 

VI–12 and Table VI–13, respectively. In 

these tables, counties shown in bold/

italics are projected to come into 

attainment with the regional controls.

TABLE VI–12.—PROJECTED 8-HOUR CONCENTRATIONS (PPB) FOR THE 2010 BASE CASE AND CAIR AND THE IMPACT OF

CAIR REGIONAL CONTROLS IN 2010 

State County 2010 Base 

case 2010 CAIR Impact of CAIR 

Connecticut ........................................................... Fairfield Co ........................................................... 92.6 92.2 ¥0.4 

Connecticut ........................................................... Middlesex Co ........................................................ 90.9 90.6 ¥0.3 

Connecticut ........................................................... New Haven Co ..................................................... 91.6 91.3 ¥0.3 

District of Columbia .............................................. District of Columbia .............................................. 85.2 85.0 ¥0.2 

Delaware ............................................................... New Castle Co ..................................................... 85.0 84.7 ¥0.3 

Georgia ................................................................. Fulton Co .............................................................. 86.5 85.1 ¥1.4 

Maryland ............................................................... Anne Arundel Co .................................................. 88.8 88.6 ¥0.2 

Maryland ............................................................... Cecil Co ................................................................ 89.7 89.5 ¥0.2 

Maryland ............................................................... Harford Co ............................................................ 93.0 92.8 ¥0.2 

Maryland ............................................................... Kent Co ................................................................ 86.2 85.8 ¥0.4 

Michigan ................................................................ Macomb Co .......................................................... 85.5 85.4 ¥0.1 

New Jersey ........................................................... Bergen Co ............................................................ 86.9 86.0 ¥0.9 

New Jersey ........................................................... Camden Co .......................................................... 91.9 91.6 ¥0.3 

New Jersey ........................................................... Gloucester Co ...................................................... 91.8 91.3 ¥0.5 

New Jersey ........................................................... Hunterdon Co ....................................................... 89.0 88.6 ¥0.4 

New Jersey ........................................................... Mercer Co ............................................................. 95.6 95.2 ¥0.4 

New Jersey ........................................................... Middlesex Co ........................................................ 92.4 92.1 ¥0.3 

New Jersey ........................................................... Monmouth Co ....................................................... 86.6 86.4 ¥0.2 

New Jersey ........................................................... Morris Co .............................................................. 86.5 85.5 ¥1.0 

New Jersey ........................................................... Ocean Co ............................................................. 100.5 100.3 ¥0.2 

New York .............................................................. Erie Co ................................................................. 87.3 86.9 ¥0.4 

New York .............................................................. Richmond Co ........................................................ 87.3 87.1 ¥0.2 

New York .............................................................. Suffolk Co ............................................................. 91.1 90.8 ¥0.3 

New York .............................................................. Westchester Co .................................................... 85.3 84.7 ¥0.6 

Ohio ...................................................................... Geauga Co ........................................................... 87.1 86.6 ¥0.5 

Pennsylvania ......................................................... Bucks Co .............................................................. 94.7 94.3 ¥0.4 

Pennsylvania ......................................................... Chester Co ........................................................... 85.7 85.4 ¥0.3 

Pennsylvania ......................................................... Montgomery Co .................................................... 88.0 87.6 ¥0.4 

Pennsylvania ......................................................... Philadelphia Co .................................................... 90.3 89.9 ¥0.4 

Rhode Island ......................................................... Kent Co ................................................................ 86.4 86.2 ¥0.2 

Texas .................................................................... Denton Co ............................................................ 87.4 86.8 ¥0.6 

Texas .................................................................... Galveston Co ........................................................ 85.1 84.6 ¥0.5 

Texas .................................................................... Harris Co .............................................................. 97.9 97.4 ¥0.5 

Texas .................................................................... Jefferson Co ......................................................... 85.6 85.0 ¥0.6 

Texas .................................................................... Tarrant Co ............................................................ 87.8 87.2 ¥0.6 

Virginia .................................................................. Arlington Co .......................................................... 86.2 86.0 ¥0.2 

Virginia .................................................................. Fairfax Co ............................................................. 85.7 85.4 ¥0.3 

Wisconsin .............................................................. Kenosha Co .......................................................... 91.3 91.0 ¥0.3 

Wisconsin .............................................................. Ozaukee Co ......................................................... 86.2 85.8 ¥0.4 

Wisconsin .............................................................. Sheboygan Co ...................................................... 88.3 87.7 ¥0.6 

TABLE VI–13.—PROJECTED 8-HOUR CONCENTRATIONS (PPB) FOR THE 2015 BASE CASE AND CAIR AND THE IMPACT OF

CAIR REGIONAL CONTROLS IN 2015 

State County 2015 Base 

case 2015 CAIR Impact of CAIR 

Connecticut ........................................................... Fairfield Co ........................................................... 91.4 90.6 ¥0.8 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25255

107The CAIR scenario modeled for the visibility 

analysis included controls in Arkansas, Delaware, 

and New Jersey.

TABLE VI–13.—PROJECTED 8-HOUR CONCENTRATIONS (PPB) FOR THE 2015 BASE CASE AND CAIR AND THE IMPACT OF

CAIR REGIONAL CONTROLS IN 2015—Continued

State County 2015 Base 

case 2015 CAIR Impact of CAIR 

Connecticut ........................................................... Middlesex Co ........................................................ 89.1 88.4 ¥0.7 

Connecticut ........................................................... New Haven Co ..................................................... 89.8 89.1 ¥0.7 

Maryland ............................................................... Anne Arundel Co .................................................. 86.0 84.9 ¥1.1 

Maryland ............................................................... Cecil Co ................................................................ 86.9 85.4 ¥1.5 

Maryland ............................................................... Harford Co ............................................................ 90.6 89.6 ¥1.0 

Michigan ................................................................ Macomb Co .......................................................... 85.1 84.2 ¥0.9 

New Jersey ........................................................... Bergen Co ............................................................ 85.7 84.5 ¥1.2 

New Jersey ........................................................... Camden Co .......................................................... 89.5 88.3 ¥1.2 

New Jersey ........................................................... Gloucester Co ...................................................... 89.6 88.2 ¥1.4 

New Jersey ........................................................... Hunterdon Co ....................................................... 86.5 85.4 ¥1.1 

New Jersey ........................................................... Mercer Co ............................................................. 93.5 92.4 ¥1.1 

New Jersey ........................................................... Middlesex Co ........................................................ 89.8 88.8 ¥1.0 

New Jersey ........................................................... Ocean Co ............................................................. 98.0 96.9 ¥1.1 

New York .............................................................. Erie Co ................................................................. 85.2 84.2 ¥1.0 

New York .............................................................. Suffolk Co ............................................................. 89.9 89.0 ¥0.9 

Pennsylvania ......................................................... Bucks Co .............................................................. 93.0 91.8 ¥1.2 

Pennsylvania ......................................................... Montgomery Co .................................................... 86.5 84.9 ¥1.6 

Pennsylvania ......................................................... Philadelphia Co .................................................... 88.9 87.5 ¥1.4 

Texas .................................................................... Harris Co .............................................................. 97.3 96.4 ¥0.9 

Texas .................................................................... Jefferson Co ......................................................... 85.0 84.1 ¥0.9 

Wisconsin .............................................................. Kenosha Co .......................................................... 89.4 88.8 ¥0.6 

As described in section VI.B.1, we 

project that 40 counties in the East 

would be nonattainment for 8-hour 

ozone under the assumptions in the 

2010 base case. Our modeling of the 

regional controls in 2010 indicates that 

3 of these counties will come into 

attainment of the 8-hour ozone NAAQS 

and that ozone in 16 of the 40 

nonattainment counties will be reduced 

by 1 ppb or more. In addition, our 

modeling predicts that 8-hour ozone 

exceedances (i.e., 8-hour ozone of 85 

ppb or higher) within nonattainment 

areas are expected to decline by 5 

percent in 2010 with CAIR. Of the 37 

counties that are projected to remain 

nonattainment in 2010 after the regional 

strategy, nearly half (i.e., 16 of the 37 

counties) are within 2 ppb of 

attainment. 

In 2015, we project that 6 of the 22 

counties which are nonattainment for 8-

hour ozone in the base case will come 

into attainment with the regional 

strategy. Ozone concentrations in over 

70 percent (i.e., 16 of 22 counties) of the 

2015 base case nonattainment counties 

are projected to be reduced by 1 ppb or 

more as a result of the regional strategy. 

Exceedances of the 8-hour ozone 

NAAQS are predicted to decline in 

nonattainment areas by 14 percent with 

regional controls in place in 2015. Thus, 

the NOX emissions reductions which 

will result from the regional strategy 

will help to bring 8-hour ozone 

nonattainment areas in the East closer to 

attainment by 2010 and beyond. 

F. What are the Estimated Visibility 

Impacts of the Final Rule? 

1. Methods for Calculating Projected 

Visibility in Class I Areas 

The NPR contained example future 

year visibility projections for the 20 

percent worst days and 20 percent best 

days at Class I areas that had complete 

IMPROVE monitoring data in 1996. 

Changes in future visibility were 

predicted by using the REMSAD model 

to generate relative visibility changes, 

then applying those changes to 

measured current visibility data. Details 

of the visibility modeling and 

calculations can be found in the NPR 

AQMTSD. An example visibility 

calculation was given in Appendix M of 

the NPR AQMTSD along with the 

predicted improvement in visibility (in 

deciviews) on the 20 percent best and 

worst days at 44 Class I areas. The data 

contained in Appendix M was for 

informational purposes only and was 

not used in the significant contribution 

determination or control strategy 

development decisions. 

The SNPR contained visibility 

calculations in support of the ‘‘betterthan-BART’’ analysis. The better-thanBART analysis employed a two-pronged 

test to determine if the modeled 

visibility improvements from the CAIR 

cap and trade program for EGU’s were 

‘‘better’’ than the visibility 

improvements from a nationwide BART 

program. The analysis used the 

visibility calculation methodology 

detailed in the NPR TSD. Detailed 

results of the SNPR better-than-BART 

analysis are contained in the SNPR 

AQMTSD. The better-than-BART 

analysis for the final rule is addressed 

in section IX.C.2 of the preamble. 

Additional information on the visibility 

calculation methodology is contained in 

the NFR AQMTSD. 

2. Visibility Improvements in Class I 

Areas 

For the NFR we have modeled several 

new CAIR107 and CAIR + BART cases 

to re-examine the better-than-BART 

two-pronged test. We have modeled an 

updated nationwide BART scenario as 

well as a CAIR in the East/BART in the 

West scenario. The results were 

analyzed at 116 Class I areas that have 

complete IMPROVE data for 2001 or are 

represented by IMPROVE monitors with 

complete data. Twenty-nine of the Class 

I areas are in the East and 87 are in the 

West. The results of the visibility 

analysis are summarized in section 

IX.C.2. Detailed results for all 116 Class 

I areas are presented in the NFR 

AQMTSD.

VII. SIP Criteria and Emissions 

Reporting Requirements 

This section describes: (1) The criteria 

we will use in determining 

approvability of SIPs submitted to meet 

the requirements of today’s rulemaking; 

(2) the dates for submittal of the SIPs 

that are required under the CAIR; (3) the 

consequences of either failing to submit 

such a SIP or submitting a SIP which is 

25256 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

disapproved; and (4) the emissions 

inventory reporting requirements for 

States. 

A. What Criteria Will EPA Use To 

Evaluate the Approvability of a 

Transport SIP? 

1. Introduction

The approvability criteria for CAIR 

SIP submissions are finalized today in 

40 CFR 51.123 (NOX emissions 

reductions) and in 40 CFR 51.124 (SO2

emissions reductions). Most of the 

criteria are substantially similar to those 

that currently apply to SIP submissions 

under CAA section 110 or part D 

(nonattainment). For example, each 

submission must describe the control 

measures that the State intends to 

employ, identify the enforcement 

methods for monitoring compliance and 

managing violations, and demonstrate 

that the State has legal authority to carry 

out its plan. 

This part of the preamble explains 

additional approvability criteria specific 

to the CAIR that were proposed and 

discussed in the CAIR NPR or in the 

CAIR SNPR, and are being promulgated 

today. As explained in both the CAIR 

NPR and the CAIR SNPR, EPA proposed 

that each affected State must submit SIP 

revisions containing control measures 

that assure that a specified amount of 

NOX and SO2 emissions reductions are 

achieved by specified dates. 

Although EPA determined the amount 

of emissions reductions required by 

identifying specific, highly costeffective control levels for EGUs, EPA 

explained in the CAIR NPR and the 

CAIR SNPR that States have flexibility 

in choosing which sources to control to 

achieve the required emissions 

reductions. As long as a State’s 

emissions reductions requirements are 

met, a State may impose controls on 

EGUs only, on non-EGUs only, or on a 

combination of EGUs and non-EGUs. 

The SIP approvability criteria are 

intended to provide as much certainty 

as possible that, whichever sources a 

State chooses to control, the controls 

will result in the required amount of 

emissions reductions. 

In the CAIR NPR, EPA proposed a 

‘‘hybrid’’ approach for the mechanisms 

used to ensure emissions reductions are 

achieved. This approach incorporates 

elements of an emissions ‘‘budget’’

approach (requiring an emissions cap on 

affected sources) and an ‘‘emissions 

reduction’’ approach (not requiring an 

emissions cap). In this hybrid approach, 

if States impose control measures on 

EGUs, they would be required to impose 

an emissions cap on all EGUs, which 

would effectively be an emissions 

budget. And, as stated in the CAIR NPR, 

if States impose control measures on 

non-EGUs, they would be encouraged 

but not required to impose an emissions 

cap on non-EGUs. In the CAIR NPR, we 

requested comment on the issue of 

requiring States to impose caps on any 

source categories that the State chooses 

to regulate. 

In the CAIR SNPR, we proposed to 

modify the hybrid approach and require 

States that choose to control large 

industrial boilers or turbines (greater 

than 250 MMBTU/hr) to impose an 

emissions cap on all such sources 

within their State. This is similar to 

EPA’s approach in the NOX SIP Call 

which required States to include an 

emissions cap on such sources as well 

as on EGUs if the SIP submittals 

included controls on such sources. (See 

40 CFR 51.121(f)(2)(ii).) 

A few commenters supported the use 

of emissions caps on any source 

category subject to CAIR controls, 

including non-EGUs, because it would 

be the most effective way to 

demonstrate compliance with the 

budget. A few other commenters 

opposed the use of an emissions cap on 

non-EGUs, saying either that States 

should have the flexibility to determine 

whether to impose a cap, or that such 

a requirement would result in increased 

costs for non-EGUs including 

cogeneration units that are non-EGUs. 

No commenter opposing such a 

requirement provided any information 

indicating that such a requirement 

would be ineffective or impracticable. 

Today EPA is adopting the modified 

approach, as described in the CAIR 

SNPR, that States choosing to control 

EGUs or large industrial boilers or 

turbines must do so by imposing an 

emissions cap on such sources, similar 

to what was required in the NOX SIP 

Call.

Extensive comments were received 

regarding the need for an ozone season 

NOX cap in States identified to be 

contributing significantly to the region’s 

ozone nonattainment problems. In 

proposal, EPA stated that the annual 

NOX cap under CAIR reduced NOX

emissions sufficiently enough to not 

warrant a regional ozone season NOX

cap. Commenters remained very 

concerned that the annual NOX cap 

would not aid ozone attainment. While 

EPA feels that the annual NOX limit will 

most likely be protective in the ozone 

season, a seasonal cap will provide 

certainty, which EPA agrees is very 

important in the effort to help areas 

achieve ozone attainment. Today, EPA 

is finalizing an ozone season NOX cap 

for States shown to contribute 

significantly for ozone. As is further 

explained in section VIII, EPA is also 

finalizing an ozone season trading 

program that States may use to achieve 

the required emissions reductions. This 

program will subsume the existing NOX

SIP Call trading program. Therefore, any 

State that wishes to continue including 

its sources in an interstate trading 

program run by EPA to achieve the 

emissions reductions required by EPA 

must modify its SIP to conform with 

this new trading program. 

The EPA will automatically find that 

a State is continuing to meet its NOX SIP 

Call obligation if it achieves all of its 

required CAIR emissions reductions by 

capping EGUs, it modifies its existing 

NOX SIP Call to require its non-EGUs 

currently participating in the NOX SIP 

Call budget trading program to conform 

to the requirements of the CAIR ozone 

season NOX trading program with a 

trading budget that is the same or tighter 

than the budget in the currently 

approved SIP, and it does not modify 

any of its other existing NOX SIP Call 

rules. If a State chooses to achieve the 

ozone season NOX emissions reduction 

requirements of CAIR in another way, it 

will also be required to demonstrate that 

it continues to meet the requirements of 

the NOX SIP Call. 

Specific criteria for approval of CAIR 

SIP submissions as promulgated by 

today’s action are described below. The 

criteria are dependent on the types of 

sources a State chooses to control. 

2. Requirements for States Choosing To 

Control EGUs 

a. Emissions Caps and Monitoring 

As explained in the CAIR NPR (69 FR 

4626), and in the CAIR SNPR (69 FR 

32691), EPA proposed requiring States 

to apply the ‘‘budget’’ approach if they 

choose to control EGUs; that is, each 

State must cap total EGU emissions at 

the level that assures the appropriate 

amount of reductions for that State. The 

requirement to cap all EGUs is 

important because it prevents shifting of 

utilization (and resulting emissions) to 

uncapped EGUs. The EGUs are part of 

a highly interconnected electricity grid 

that makes utilization shifting likely and 

even common. The units are large and 

offer the same market product (i.e., 

electricity), and therefore the units that 

are least expensive to operate are likely 

to be operated as much as possible. If 

capped and uncapped units are 

interconnected, the uncapped units’

costs would tend to decrease relative to 

the capped units, which must either 

reduce emissions or use or buy 

allowances, and the uncapped units’

utilization would likely increase. The 

cap ensures that emissions reductions 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25257

108Title IV allowances can however be traded 

freely across the boundary of the CAIR region 

without any significant, negative environmental 

consequence. The potential negative consequences 

have been addressed through other requirements 

discussed below, like the retirement of excess title 

IV allowances.

from these interconnected sources are 

actually achieved rather than emissions 

simply shifting among sources. The caps 

constitute the State EGU Budgets for 

SO2 and NOX. Additionally, EPA 

proposed that, if States choose to 

control EGUs, they must require EGUs 

to follow part 75 monitoring, 

recordkeeping, and reporting 

requirements. Part 75 monitoring and 

reporting requirements have been used 

effectively for determining NOX and SO2

emissions from EGUs under the title IV 

Acid Rain program and the NOX SIP 

Call program and in combination with 

emissions caps are an integral part of 

those programs. (Additional explanation 

for the need for Part 75 monitoring is 

given in the NPR and SNPR and is 

incorporated here.) Therefore, today, 

EPA adopts the requirements for 

emission caps and Part 75 monitoring 

for EGUs in these States.

b. Using the Model Trading Rules 

As proposed, if a State chooses to 

allow its EGUs to participate in EPAadministered interstate NOX and SO2

emissions trading programs, the State 

must adopt EPA’s model trading rules, 

as described elsewhere in today’s 

preamble and in §§ 96.101–96.176 (for 

NOX) and §§ 96.201–96.276 (for SO2), 

set forth below. Additionally, EPA 

proposed that for the States for which 

EPA made a finding of significant 

contribution for both ozone and PM2.5, 

participation in both the NOX and SO2

trading programs would be required in 

order to be included in the EPAadministered program. States for which 

the finding was for ozone only could 

choose to participate in only the EPAadministered NOX trading program 

through adoption of the NOX model 

trading rule. The EPA stated that States 

adopting EPA’s model trading rules, 

modified only as specifically allowed by 

EPA, will meet the requirement for 

applying an emissions cap and 

requirement to use part 75 monitoring, 

recordkeeping, and reporting for EGUs. 

Some commenters opposed EPA’s 

proposal to require participation in both 

the NOX and SO2 trading programs 

because some States may want to 

participate in the EPA-administered 

trading programs for only NOX or only 

SO2. A few commenters claimed that the 

requirement to participate in both 

programs would limit State flexibility or 

is an ‘‘all or nothing’’ approach; other 

commenters objected that there was no 

environmental basis for such a 

requirement; and one commenter 

suggested that States not affected by 

CAIR but that volunteer to control 

emissions should be permitted to join 

the program for one or both pollutants. 

Additionally, commenters cited a need 

for an ozone season NOX program. 

The EPA has taken the comments into 

account and in today’s action agrees to 

allow a State identified to contribute 

significantly for PM2.5 (and therefore 

required to make annual SO2 and NOX

reductions) to participate in the EPAadministered CAIR trading program for 

either SO2 or NOX, not necessarily both, 

so long as the State adopts the model 

rule for the applicable trading program. 

In response to extensive comments 

relating to EPA’s proposal to forego a 

seasonal NOX cap because EPA 

demonstrated that the annual NOX cap 

was sufficiently stringent, EPA is 

finalizing an ozone season NOX trading 

program for States identified as 

contributing significantly for ozone. 

These States will be subject to an ozone 

season NOX cap and an annual NOX cap 

if the State is also identified as 

contributing significantly for PM2.5. 

Therefore, today’s action includes an 

additional model rule for an ozone 

season NOX trading program (40 CFR 

96, subparts AAAA through IIII). The 

States that may use the ozone season 

NOX trading program but not the annual 

NOX trading program are those States in 

the CAIR region identified as 

contributing significantly for ozone only 

(Arkansas, Connecticut, Delaware, 

Massachusetts, and New Jersey). 

As discussed in the proposal, EPA is 

finalizing the option for New Hampshire 

and Rhode Island to participate in the 

regional trading program through use of 

the CAIR ozone season NOX model rule 

because sources in these States have 

made investments in NOX controls in 

the past based on the existence of a 

regional ozone season NOX trading 

program. Additionally, the States’

combined projected 2010 and 2015 NOX

emissions are less than one-half of one 

percent of the total CAIR regional NOX

cap and therefore would not create a 

significant increase in the CAIR cap. All 

comments received were supportive of 

this approach and EPA is finalizing it 

today. 

None of these States (Arkansas, 

Connecticut, Delaware, Massachusetts, 

New Hampshire, New Jersey, or Rhode 

Island) has the option to participate in 

the EPA-administered CAIR SO2 trading 

program nor the annual CAIR NOX

trading program because there are no 

PM2.5-related emissions reductions 

required under today’s action in those 

States. (Of course, sources in these 

States will still be subject to the Acid 

Rain SO2 cap and trade program.) 

Likewise, Texas, Minnesota and Georgia 

may not participate in the ozone season 

NOX program, because they have not 

been shown to contribute significantly 

to the regional ozone problem. They are, 

however, required to make annual NOX

and SO2 reductions and may choose to 

participate in the annual NOX and 

annual SO2 trading program to meet 

their CAIR obligations. 

Except for the special cases of Rhode 

Island and New Hampshire, other States 

outside of the CAIR region may not 

participate in the CAIR trading 

programs for either pollutant, because 

they were not shown to contribute 

significantly to PM2.5 or ozone 

nonattainment in the CAIR region. 

Allowing States outside of the CAIR 

region to participate would generally 

create an opportunity—through net 

sales of allowances from the non-CAIR 

States to CAIR States—for emission 

increases in States that have been 

shown to contribute significantly to 

nonattainment in the CAIR region.108

A State may not participate in the 

EPA-administered trading programs if 

they choose to get a portion of CAIR 

reductions from non-EGUs. (This is also 

discussed in Section VIII.) The EPA 

maintains that requiring certain 

consistencies among States in the 

regionwide trading programs that EPA 

has offered to run does not unfairly 

limit States’ flexibility to choose an 

approach for achieving CAIR mandated 

reductions that is best suited for a 

particular State’s unique circumstances. 

States are free to achieve the reductions 

through whatever alternative 

mechanisms the States wish to design; 

for example, a group of States could 

cooperatively implement their own 

multi-State trading programs that EPA 

would not administer. 

c. Using a Mechanism Other Than the 

Model Trading Rules 

If States choose to control EGUs 

through a mechanism other than the 

EPA-administered NOX and SO2

emissions trading programs, then the 

States (i) must still impose an emissions 

cap on total EGU emissions and require 

part 75 monitoring, recordkeeping, and 

reporting requirements on all EGUs, and 

(ii) must use the same definition of EGU 

as EPA uses in its model trading rules, 

i.e., the sources described as ‘‘CAIR 

units’’ in § 96.102, § 96.202, and 

§ 96.302. A few commenters expressed 

concern that these requirements limit 

States’ discretion in designing control 

measures to meet the CAIR 

requirements, but failed to offer any 

25258 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

reason why the requirements would be 

impracticable or ineffective. The EPA 

believes that the requirements are 

necessary for a number of reasons. The 

requirements to cap all EGUs and to use 

the same definition of EGU are 

important because they prevent shifting 

of utilization (and resulting emissions) 

from capped to uncapped sources. In 

this case, not requiring a cap on total 

EGU emissions in these States is likely 

to result in increased utilization and 

consequently increased emissions in 

these States. The requirement to use 

part 75 monitoring ensures the accuracy 

of monitored data and consistency of 

reporting among sources (and thus the 

certainty that emissions reductions 

actually occurred) across all States. 

Furthermore, most EGUs are currently 

monitoring and reporting using part 75 

so it does not impose an additional 

requirement. Therefore, EPA is 

finalizing the proposed approach. 

If a State chooses to design its own 

intrastate or interstate NOX or SO2

emissions trading programs, the State 

must, in addition to meeting the 

requirements of the rules finalized in 

today’s action, consider EPA’s guidance, 

‘‘Improving Air Quality with Economic 

Incentive Programs,’’ January, 2001 

(EPA–452/R–01–001) (available on 

EPA’s Web site at: http://www.epa.gov/

ttn/ecas/incentiv.html). The State’s 

programs are subject to EPA approval. 

The EPA will not administer a Statedesigned trading program. Additionally, 

it should be noted that allowances from 

any alternate trading program may not 

be used in the EPA-administered trading 

programs. 

d. Retirement of Excess Title IV 

Allowances 

The CAIR NPR proposed 

requirements on SIPs relating to the 

effects of title IV SO2 allowance 

allocations for 2010 and beyond that are 

in excess of the State’s CAIR EGU SO2

emissions budget. The requirements 

were intended to ensure that the excess 

is not used in a manner that would lead 

to a significant increase in supply of 

title IV allowances, the collapse of the 

price of title IV allowances, the 

disruption of operation of the title IV 

allowance market and the title IV SO2

cap and trade system, and the potential 

for increased emissions in all States 

prior to 2010 and in non-CAIR States in 

2010 and later. These negative impacts 

on the title IV allowance market and on 

air quality, which are discussed in 

detail in section IX.B. below, would 

undermine the efficacy of the title IV 

program and could erode confidence in 

cap and trade programs in general. To 

avoid these impacts, EPA proposed to 

require retirement of the excess title IV 

allowances through a retirement ratio 

mechanism. 

The EPA proposed, as a mechanism 

for removing these additional 

allowances and meeting the 50 percent 

reduction required under phase I (2010–

2014), that each affected EGU had to 

hold, and EPA would retire, two vintage 

2010–2014 allowances for every ton of 

SO2 that the unit emits. Further, EPA 

proposed that, for phase II (which 

begins in 2015) when a 65 percent 

reduction is required, each affected EGU 

had to hold, and EPA would retire, three 

vintage 2015 and beyond allowances for 

every ton of SO2 that the unit emits. 

This 3-to-1 ratio would result in slightly 

more reductions than EPA has 

determined were necessary to eliminate 

the significant contribution by an 

upwind State. 

In the CAIR SNPR, EPA proposed two 

alternatives for addressing the issue of 

the additional allowances. Under the 

first alternative, affected EGUs had to 

hold, and EPA would retire, vintage 

2015 and beyond allowances at a rate of 

2.86-to-1 rather than 3-to-1, which 

would result in exactly the amount of 

reductions EPA has determined are 

necessary to eliminate a State’s 

significant contribution. 

Alternatively, also in the CAIR SNPR, 

EPA proposed requiring the retirement 

of 2015 and beyond vintage allowances 

at a 3-to-1 ratio and permitting States to 

convert the additional reductions into 

allowances in their rules. The EPA also 

suggested that some States may want to 

use these reserved allowances to create 

an incentive for additional local 

emissions reductions that will be 

needed to bring all areas into attainment 

with the PM2.5 NAAQS.

As part of today’s final CAIR 

rulemaking, EPA is finalizing a ratio of 

2.86-to-one. The ratio ultimately 

represents a reduction of 65 percent 

from the final title IV cap level, which 

has been found to be highly costeffective. For a detailed discussion 

regarding EPA’s determination of highly 

cost-effective, please refer to Section IV 

of the final CAIR preamble. As 

discussed earlier, EPA must employ a 

uniform ratio across sources to ensure 

consistency and the same costeffectiveness level across sources. 

Therefore, EPA will use a Phase II ratio 

of 2.86-to-1 for all States affected by 

CAIR who choose to participate in the 

trading program. 

Today, EPA is finalizing the general 

requirement that all SIPs must include 

a mechanism to ensure that excess SO2

allowances are retired. Furthermore, for 

States that participate in the EPAadministered cap and trade program, 

EPA is finalizing a specific mechanism 

that States must use. 

i. States Participating in the EPAAdministered SO2 Trading Program 

If a State chooses to participate in the 

EPA-administered trading program, the 

State’s excess title IV allowance 

retirement mechanism must follow the 

provisions of the SO2 model trading rule 

that requires that vintage 2010 through 

2014 title IV allowances be retired at a 

ratio of two allowances for every ton of 

emissions and that vintage 2015 and 

beyond title IV allowances be retired at 

a ratio of 2.86 allowances for every ton 

of emissions. Pre-2010 vintage 

allowances would be retired at a ratio of 

one allowance for every ton of 

emissions. (See discussion of the model 

SO2 cap and trade rule in section VIII of 

today’s preamble.) States using the 

model SO2 cap and trade rule satisfy the 

requirement for retirement of excess 

title IV allowances. 

ii. States Not Participating in the EPAAdministered SO2 Trading Program 

In the CAIR NPR, EPA stated that if 

a State does not choose to participate in 

the EPA-administered trading programs 

but controls only EGUs, the State may 

choose the specific method to retire 

allowances in excess of its budget. The 

EPA considered alternative ways for 

retiring these excess allowances and, as 

stated in the CAIR SNPR, believed that 

the use by different States of different 

means to address this concern could 

undermine the regionwide emissions 

reduction goals of the CAIR rulemaking. 

The EPA further described its concerns 

in section II of the preamble to the CAIR 

SNPR. (See 69 FR 32686–32688.) 

Because of these concerns, in the CAIR 

SNPR, EPA withdrew the CAIR NPR 

proposal on this point and re-proposed 

that all States use a 2-for-1 retirement 

ratio for vintage 2010 through 2014 

allowances and a 2.86-for-1 or a 3-for1 retirement ratio for vintage 2015 and 

beyond allowances to address concerns 

about title IV allowances that exceed 

State budgets. The EGUs would have a 

total emissions cap enforced by the 

State. 

The SNPR described that for sources 

affected by both title IV and CAIR, 

allowance deductions and associated 

compliance determinations would be 

sequential. That is, title IV compliance 

would be determined and then CAIR 

compliance would be determined. So, in 

2010–2014, after surrendering one 

vintage 2010 through 2014 allowance 

for each ton of emissions for title IV 

compliance, the source would then 

surrender one additional allowance (for 

a total of two allowances for each ton 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25259

109 In the CAIR SNPR, EPA mistakenly cited the 

EGU budget numbers from Tables VI–9 and VI–10 

in the CAIR NPR (69 FR 4619–20) when it should 

have cited Tables II–1 and II–2 in the CAIR SNPR. 

The EPA used the correct numbers, however, in the 

proposed regulatory text in the CAIR SNPR (69 FR 

32729–30 and 69 FR 32733–34 (§§ 51.123(e)(2) and 

51.124(e)(2)).

which meets the CAIR requirement). 

Similarly, in 2015 and beyond, after 

surrendering one vintage 2015 and 

beyond allowance for each ton of 

emissions for title IV compliance, the 

source would surrender 1.86 or 2 

additional allowances and therefore 

meet the CAIR requirement. 

Commenters argued that in States where 

EGUs are not trading under CAIR that 

the excess title IV allowances could be 

removed in a variety of ways and that 

EPA did not need to require each State 

do this the same way, only that each 

State ensure that they are removed. 

Today, EPA adopts the following 

requirement: If a State does not choose 

to participate in the EPA-administered 

trading programs but controls only 

EGUs, the State must include in its SIP 

a mechanism for retiring the excess title 

IV allowances (i.e., the difference 

between total allowance allocations in 

the State and the State EGU SO2

budget). To meet this requirement, the 

State may use the above-described 

retirement mechanism or may develop a 

different mechanism that will achieve 

the required retirement of excess 

allowances. 

3. Requirements for States Choosing to 

Control Sources Other Than EGUs 

a. Overview of Requirements 

As noted in both the CAIR NPR and 

the CAIR SNPR, if a State chooses to 

require emissions reductions from nonEGUs, the State must adopt and submit 

SIP revisions and supporting 

documentation designed to quantify the 

amount of reductions from the non-EGU 

sources and to assure that the controls 

will achieve that amount. Although EPA 

did not propose in the CAIR NPR that 

States be required to impose an 

emissions cap on those sources, but 

instead solicited comment on the issue, 

EPA proposed in the CAIR SNPR that 

States be required to impose an 

emissions cap in certain cases on nonEGU sources. (See discussion in VII.A.1 

of today’s preamble.)

If a State chooses to obtain some, but 

not all, of its required reductions for 

SO2 or NOX emissions from non-EGUs, 

it would still be required to set an EGU 

budget for SO2 or NOX respectively, but 

it would set such a budget at some level 

higher than shown in Tables V–1, V–2, 

or V–4 in today’s preamble, thus 

allowing more emissions from EGUs. 

The difference between the amount of a 

State’s SO2 budget in Table V–1 and a 

State’s selected higher EGU SO2 budget 

would be the amount of SO2 emissions 

reductions the State demonstrates it will 

achieve from non-EGU sources. By the 

same token, the difference between the 

amount of a State’s annual NOX budget 

in Table V–2 and a State’s selected 

higher annual EGU NOX budget would 

be the amount of annual NOX emissions 

reductions the State demonstrates it will 

achieve from non-EGU sources.109

Further, the difference between the 

amount of a State’s seasonal NOX budget 

in Table V–4 and a State’s selected 

higher ozone season EGU NOX budget 

would be the amount of ozone season 

NOX emissions reductions the State 

demonstrates it will achieve from nonEGU sources.

Special Concerns About SO2

Allowances 

In the case where a State requires a 

portion of its SO2 emissions reductions 

from non-EGU sources and a portion 

from EGUs, there remains a concern 

about the impact of excess title IV 

allowances above a State’s EGU cap, 

particularly on the operation of the title 

IV SO2 cap and trade program. 

Consequently, today, we are adopting 

the requirement that these States 

include a mechanism for retirement of 

the allowances in excess of the State’s 

SO2 budget. 

Like a State choosing to control only 

EGUs but not to participate in the 

trading program, a State that chooses to 

control non-EGUs and EGUs must adopt 

a mechanism for retiring surplus title IV 

allowances. The number of title IV 

allowances that must be retired is equal 

to the difference between the number of 

title IV allowances allocated to EGUs in 

that State and the SO2 budget the State 

sets for EGUs under this rule. If the 

State uses a retirement mechanism (as 

discussed in VII.A.2.d.) in which a 

source surrendering allowances under 

the title IV SO2 cap and trade program 

surrenders more allowances than 

otherwise required under title IV, the 

total number of allowances surrendered 

per ton of emissions in this case will be 

less than 2 to 1 in Phase 1 and less than 

2.86 to 1 in Phase 2. This is because the 

non-EGUs will control to achieve a 

portion of the CAIR SO2 reduction 

required, and so there will be a smaller 

surplus of title IV allowances than if all 

the required reductions were achieved 

by EGUs. The appropriate retirement 

factor will equal two times the State’s 

SO2 budget in Phase I or 2.86 times the 

State’s SO2 budget in Phase II as noted 

in Table V–1 of the budget section, 

divided by the State’s selected higher 

EGU SO2 budget (taking into account 

non-EGU reductions). The factor could 

then be used as the EGU retirement ratio 

for compliance purposes in a scenario 

where a State has decided to control 

SO2 emissions from EGUs through a 

mechanism other than the EPAadministered trading program. 

A simplified example can help 

illustrate this. Let us assume a State’s 

sources were allocated a total of 200 

allowances under title IV. Under CAIR, 

in Phase I, the State’s reduction 

requirement would thus be 100 tons. 

Suppose this State decided that 25 tons 

would be reduced by non-EGUs and the 

remaining 75 tons would be reduced by 

the EGUs. (The State’s budget for EGUS 

would increase to 125 tons.) The State 

would also need to retire 75 excess title 

IV allowances. This could be 

accomplished by requiring each Acid 

Rain source to surrender a total of 1.6 

vintage 2010 through 2014 allowances 

(200 allowances allocated in the State/

125 tons in State EGU budget) per ton 

of SO2 emissions. The allowances 

surrendered would satisfy the Acid Rain 

Program requirement of surrendering 

one allowance per ton of emissions, as 

well as achieving the additional 

retirement requirement under CAIR 

since 200 allowances would be used for 

EGUs to emit the EGU budget of 125 

tons of SO2. (Pre-2010 allowances 

continue to be available for use on a 

one-allowance-per-ton-of-emissions 

basis here as in other situations.) 

This is consistent with EPA’s overall 

approach. If this same State decided to 

get all reductions (i.e., 100 tons) from 

EGUs, the State would require EGUs to 

retire 100 additional allowances by 

surrendering a total of 2 vintage 2010 

through 2014 allowances (200 

allowances allocated in the State/100 

tons in State EGU budget) per ton of SO2

emissions. 

The demonstration of emissions 

reductions from non-EGUs is a critical 

requirement of the SIP revision due 

from a State that chooses to control nonEGUs. The State must take into account 

the amount of emissions attributable to 

the source category in both (i) the base 

case, in the implementation years 2010 

and 2015, i.e., without assuming any 

SIP-required reductions under the CAIR 

from non-EGUs; and (ii) in the control 

case, in the implementation years 2010 

and 2015, i.e., assuming SIP-required 

reductions under the CAIR from nonEGUs. We proposed an alternative 

methodology for calculating the base 

case for certain large non-EGU sources, 

as described below, but generally the 

difference between emissions in the 

base case and emissions in the control 

25260 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

case equals the amount of emissions 

reductions that can be claimed from 

application of the controls on nonEGUs. (See discussion later in this 

section for criteria applicable to 

development of the baseline and 

projected control emissions 

inventories.) 

States that meet the lesser of their 

CAIR ozone season NOX budget or NOX

SIP Call EGU trading budget using the 

CAIR ozone season NOX trading 

program also satisfy their NOX SIP Call 

requirements for EGUs. States may also 

choose to include all of their NOX SIP 

Call non-EGUs in the CAIR ozone 

season NOX program at their NOX SIP 

Call levels (i.e., the non-EGU trading 

budget remains the same). 

To the extent EPA allows through the 

Regional Haze Rule and a State then 

chooses to use EPA analysis to show 

that CAIR reductions from EGUs meet 

BART requirements, States that achieve 

a portion of their CAIR reductions from 

sources other than EGUs and wanting to 

show that even with those reductions 

the EGUs will meet BART requirements 

must make a supplemental 

demonstration that BART requirements 

are satisfied.

b. Eligibility of Non-EGU Reductions 

In the CAIR SNPR, EPA proposed 

that, in evaluating whether emissions 

reductions from non-EGUs would count 

towards the emissions reductions 

required under the CAIR, States may 

only include reductions attributable to 

measures that are not otherwise 

required under the CAA. Specifically, 

EPA proposed that States must exclude 

non-EGU reductions attributable to 

measures otherwise required by the 

CAA, including: (1) Measures required 

by rules already in place at the date of 

promulgation of today’s final rule, such 

as adopted State rules, SIP revisions 

approved by EPA, and settlement 

agreements; (2) measures adopted and 

implemented by EPA (or other Federal 

agencies) such as emissions reductions 

required pursuant to the Federal Motor 

Vehicle Control Program for mobile 

sources (vehicles or engines) or mobile 

source fuels, or pursuant to the 

requirements for National Emissions 

Standards for Hazardous Air Pollutants; 

and (3) specific measures which are 

mandated under the CAA (which may 

have been further defined by EPA 

rulemaking) based on the classification 

of an area which has been designated 

nonattainment for a NAAQS, such as 

vehicle inspection and maintenance 

programs. 

In discussing this proposal, EPA 

noted that States required to make CAIR 

SIP submittals may also be required to 

make separate SIP submittals to meet 

other requirements applicable to nonEGUs, e.g., nonattainment SIPs required 

for areas designated nonattainment 

under the PM2.5 or 8-hour ozone 

NAAQS or regional haze SIPs. The EPA 

noted it is likely that CAIR SIP 

submittals will be due before or at the 

same time as some of these other SIP 

submittals. We therefore proposed that 

States relying on reductions from 

controls on non-EGUs must commit in 

the CAIR SIP revisions to replace the 

emissions reductions attributable to any 

CAIR SIP measure if that measure is 

subsequently determined to be required 

to meet any other SIP requirement. 

Some commenters objected to the 

proposed exclusion of credit for 

measures which are mandated under the 

CAA based on the classification of an 

area which has been designated 

nonattainment for a NAAQS, as well as 

to the proposed requirement that such 

measures must be replaced if they are 

later determined to be required in 

meeting separate SIP requirements. 

These commenters reasoned that such a 

requirement would not be applied to 

EGUs and would impose unnecessary 

and costly burdens on non-EGUs, thus 

creating an incentive for States to avoid 

controlling non-EGUs and to impose all 

CAIR reduction requirements on EGUs. 

One commenter further objected that, as 

long as a measure was not included in 

the base case EPA used to determine a 

State’s contribution to other States’

nonattainment under CAA section 

110(a)(2)(D), there is no justification for 

excluding CAIR credit for such measure, 

and that EPA’s proposed exclusion of 

credit for any measure ‘‘otherwise 

required by the CAA’’ is inconsistent 

with the NOX SIP Call. 

In response to these comments, EPA 

agrees that it is not appropriate to apply 

this proposed restriction inconsistently 

to EGUs and non-EGUs. Thus, EPA is 

adopting a modified form of the 

proposed criteria for the eligibility of 

non-EGU emissions reductions, 

eliminating the requirement that States 

must exclude non-EGU reductions 

attributable to measures otherwise 

required by the CAA based on the 

classification of an area which has been 

designated nonattainment for a NAAQS. 

Consequently, the final rule allows 

credit for measures that a State later 

adopts in response to requirements 

which result from an area’s 

nonattainment classification, such as 

reasonably available control technology 

(RACT). With this change, all emissions 

reductions are eligible for credit in 

meeting CAIR except: (1) Measures 

adopted or implemented by the State as 

of the date of promulgation of today’s 

final rule, such as adopted State rules, 

SIP revisions approved by EPA, and 

settlement agreements; and (2) measures 

adopted or implemented by the Federal 

government (e.g., EPA or other Federal 

agencies) as of the date of submission of 

the SIP revision by the State to EPA, 

such as emissions reductions required 

pursuant to the Federal Motor Vehicle 

Control Program for mobile sources 

(vehicles or engines) or mobile source 

fuels, or pursuant to the requirements 

for National Emissions Standards for 

Hazardous Air Pollutants. 

This exclusion of credit is consistent 

with EPA’s approach in the NOX SIP 

Call, although a direct comparison of 

the creditability requirements in the 

CAIR and in the NOX SIP Call is not 

possible due to the timing and context 

in which both rules were developed. 

The NOX SIP Call used statewide 

budgets for all sources as an accounting 

tool to determine the adequacy of a 

strategy, while the CAIR takes a 

different approach in which baseline 

emission inventories for non-EGU 

sectors will, if needed, be developed 

later. The NOX SIP Call did, as does the 

CAIR, restrict States from taking credit 

for any Federal measures adopted after 

promulgation of the rule (63 FR 57427–

28). It also did not allow credit for 

already adopted measures, but the 

timing of the NOX SIP Call was such 

that nonattainment planning measures 

would have already likely been adopted 

as the SIP deadlines for adoption of 

such measures had passed. In today’s 

action, nonattainment planning 

measures adopted after the 

promulgation of today’s rule will be 

allowed credit under CAIR.

In order to take credit for CAIR 

reductions from non-EGUs, the 

reductions must be beyond what is 

required under the NOX SIP Call. That 

is, a reduction must be in the non-ozone 

season or it must be beyond what is 

expected in the ozone season. Nonozone season reductions must also be 

beyond what is in the base case, 

particularly for units that have low NOX

burners and certain SCRs (e.g., ones 

required to be run annually). The 

reductions must be in addition to those 

already expected. If ozone season 

reductions are considered, the non-EGU 

NOX SIP Call trading budget must be 

adjusted by the increment of CAIR 

reductions beyond the levels in the NOX

SIP Call. This removes the 

corresponding allowances from the 

market and ensures that the emissions 

do not shift to other sources. 

After evaluating the eligibility of nonEGU reductions in accordance with the 

requirements discussed here, States 

must exclude credit for ineligible 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25261

110The many EPA guidance documents and tools 

for preparing emission inventory estimates for SO2

and NOX are available at the following Web sites: 

http://www.epa.gov/ttn/chief/net/general.html, 

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

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

publications.html#general, http://www.epa.gov/ttn/

chief/software/index.html, and http://www.epa.gov/

ttn/chief/efinformation.html.

111The 2010 modeling date is relevant for both 

SO2 and NOX even though NOX requirements begin 

in 2009. See Section IV for discussion.

measures by (i) including such measures 

in both the baseline and controlled 

emissions inventory cases, if they have 

already been adopted; or (ii) excluding 

them from both the base and control 

emissions inventory cases if they have 

not yet been adopted. (See discussion 

later in this section regarding 

development of emissions inventories 

and demonstration of non-EGU 

reductions.) 

c. Emissions Controls and Monitoring 

As noted in section VII.A.1., we 

modified the ‘‘hybrid’’ approach 

described in the CAIR NPR as it applies 

to certain non-EGUs, and adopt today 

the approach described in the CAIR 

SNPR. Specifically, for States that 

choose to impose controls on large 

industrial boilers and turbines, i.e., 

those whose maximum design heat 

input is greater than 250 mmBtu/hr, to 

meet part or all of their emissions 

reductions requirements under the 

CAIR, State rules must include an 

emissions cap on all such sources in 

their State. Additionally, in this 

situation, States must require those large 

industrial boilers and turbines to meet 

part 75 requirements for monitoring and 

reporting emissions as well as 

recordkeeping. This ensures consistency 

in measurement and certainty of 

reductions and has been proven 

technologically and economically 

feasible in other programs. 

If a State chooses to control non-EGUs 

other than large industrial boilers and 

turbines to obtain the required 

emissions reductions, the State must 

either (i) impose the same requirements, 

i.e., an emissions cap on total emissions 

from non-EGUs in the source category in 

the State and part 75 monitoring, 

reporting and recordkeeping 

requirements; or (ii) demonstrate why 

such requirements are not practicable. 

In the latter case, the State must adopt 

appropriate alternative requirements to 

ensure that emissions reductions are 

being achieved using methods that 

quantify those emissions reductions, to 

the extent practicable, with the same 

degree of assurance that reductions are 

being quantified for EGUs and non-EGU 

boilers and turbines using part 75 

monitoring. This is to ensure that, 

regardless of how a State chooses to 

meet the CAIR emissions reduction 

requirements, all reductions made by 

States to comply with the CAIR have the 

same, high level of certainty as that 

achieved through the cap and trade 

approach. Further, if a State adopts 

alternative requirements that do not 

apply to all non-EGUs in a particular 

source category (defined to include all 

sources where any aspect of production 

of one or more such sources is 

reasonably interchangeable with that of 

one or more other such sources), the 

State must demonstrate that it has 

analyzed the potential for shifts in 

production from the regulated sources 

to unregulated or less stringently 

regulated sources in the same State as 

well as in other States and that the State 

is not including reductions attributable 

to sources that may shift emissions to 

such unregulated or less regulated 

sources. 

d. Emissions Inventories and 

Demonstrating Reductions 

To quantify emissions reductions 

attributable to controls on non-EGUs, 

the States must submit both baseline 

and projected control emissions 

inventories for the applicable 

implementation years. We have issued 

many guidance documents and tools for 

preparing such emissions inventories, 

some of which apply to specific sectors 

States may choose to control.110 While 

much of that guidance is applicable to 

today’s rulemaking, there are some key 

differences between quantification of 

emissions reduction requirements under 

a SIP designed to help achieve 

attainment with a NAAQS and 

emissions reduction requirements under 

a SIP designed to reduce emissions that 

contribute significantly to a downwind 

State’s nonattainment problem or 

interfere with maintenance in a 

downwind State. Because States are 

taking actions as a result of their impact 

on other States, and because the 

impacted States have no authority to 

reduce emissions from other States, the 

emissions reduction estimates become 

even more important. (For a complete 

discussion, see 69 FR 32693; June 10, 

2004.)

Specifically, when we review CAIR 

SIPs for approvability, we intend to 

review closely the emissions inventory 

projections for non-EGUs to evaluate 

whether emissions reduction estimates 

are correct. We intend to review the 

accuracy of baseline historical 

emissions for the subject sources, 

assumptions regarding activity and 

emissions growth between the baseline 

year and 2010 111 and 2015, and 

assumptions about the effectiveness of 

control measures.

Before describing the specific steps 

involved in this quantification process, 

EPA notes that a few commenters 

objected to the proposed requirements 

as arbitrary restrictions intended to 

discourage States’ discretion in 

imposing control measures on nonEGUs since these requirements would 

use what the commenters describe as 

extremely conservative emissions 

baseline and emissions reduction 

estimates. No commenter refuted EPA’s 

explanation, noted above, of the need 

for stringent requirements to ensure 

greater accuracy of emission inventories 

and greater certainty of reduction 

estimates used in SIPs addressing 

transported pollutants. The EPA 

maintains that the need for more 

accurate inventories and more certain 

reduction estimates justifies the 

requirements discussed below. Further, 

no commenter provided an alternate 

method of addressing EPA’s concerns 

about the development of such 

inventories and reduction estimates. 

Thus, EPA is finalizing its proposed 

approach. 

i. Historical Baseline 

To quantify non-EGU reductions, as 

the first step, a historical baseline must 

be established for emissions of SO2 or 

NOX from the non-EGU source(s) in a 

recent year. The historical baseline 

inventory should represent actual 

emissions from the sources prior to the 

application of the controls. We expect 

that States will choose a representative 

year (or average of several years) during 

2002–2005 for this purpose. 

The requirements for estimating the 

historical baseline inventory that follow 

reflect EPA’s view that, when States 

assign emissions reductions to non-EGU 

sources, achievement of those 

reductions should carry a high degree of 

certainty, just as EGU reductions can be 

quantified with a high degree of 

certainty in accordance with the 

applicable part 75 monitoring 

requirements. Because the non-EGU 

emissions reductions are estimated by 

subtracting controlled emissions from a 

projected baseline, if the historical 

baseline overestimates actual emissions, 

the estimated reductions could be 

higher than the actual reductions 

achieved. 

For non-EGU sources that are subject 

to part 75 monitoring requirements, 

historical baselines must be derived 

from actual emissions obtained from 

part 75 monitored data. For non-EGU 

sources that do not have part 75 

monitoring data, historical baselines 

must be established that estimate actual 

25262 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

emissions in a way that matches or 

approaches as closely as possible the 

certainty provided by the part 75 

measured data for EGUs. For these 

sources, States must estimate historical 

baseline emissions using source-specific 

or category-specific data and 

assumptions that ensure a source’s or 

source category’s actual emissions are 

not overestimated. 

To determine the baseline for sources 

that do not have part 75 measured data, 

States must use emission factors that 

ensure that emissions are not 

overestimated (e.g., emission factors at 

the low end of a range when EPA 

guidance presents a range) or the State 

must provide additional information 

that shows with reasonable confidence 

that another value is more appropriate 

for estimating actual emissions. Other 

monitoring or stack testing data can be 

considered, but care must be taken not 

to overestimate baselines. If a 

production or utilization factor is part of 

the historical baseline emissions 

calculation, a factor that ensures that 

emissions are not overestimated must be 

used, or additional data must be 

provided. Similarly, if a control or rule 

effectiveness factor enters into the 

estimate of historical baseline 

emissions, such a factor must be 

realistic and supported by facts or 

analysis. For these factors, a high value 

(closer to 100 percent control and 

effectiveness) ensures that emissions are 

not overestimated. 

ii. Projections of 2010 and 2015 

Baselines 

The second step in quantifying SO2 or 

NOX emissions reductions for non-EGUs 

is to use the historical baseline 

emissions and project emissions that 

would be expected in 2010 and 2015 

without the CAIR. This step results in 

the 2010 and 2015 baseline emissions 

estimates. 

The EPA proposed and requested 

comment on two procedures for 

estimating the future baselines: one 

relies on projections based on a number 

of estimated parameters; the second 

uses the lower of this projection and 

actual historical emissions. Today, EPA 

finalizes the second approach for 

determining 2010 and 2015 emissions 

baselines.

To estimate future emissions, States 

must use state-of-the-art methods for 

projecting the source or source 

category’s economic output. Economic 

and population forecasts must be as 

specific as possible to the applicable 

industry, State, and county of the source 

and must be consistent with both 

national projections and relevant official 

planning assumptions, including 

estimates of population and vehicle 

miles traveled developed through 

consultation between State and local 

transportation and air quality agencies. 

However, if these official planning 

assumptions are themselves 

inconsistent with official U.S. Census 

projections of population or with energy 

consumption projections contained in 

the most recent Annual Energy Outlook 

published by the U.S. Department of 

Energy, then adjustments must be made 

to correct the inconsistency, or the SIP 

must demonstrate how the official 

planning assumptions are more 

accurate. If the State expects changes in 

production method, materials, fuels, or 

efficiency to occur between the baseline 

year and 2010 or 2015, the State must 

account for these changes in the 

projected 2010 and 2015 baseline 

emissions. For example, if a source has 

publicly announced a change or applied 

for a permit for a change, it should be 

reflected in the projections. The 

projection must also reflect any adopted 

regulations that are ineligible control 

measures and that will affect source 

emissions. 

As stated above, EPA is requiring 

States to use the lower of historical 

baseline emissions or projected 2010 or 

2015 emissions, as applicable, for a 

source category. This is because changes 

in production method, materials, fuels, 

or efficiency often play a key role in 

changes in emissions. Because of factors 

such as these, emissions can often stay 

the same or even decrease as 

productivity within a sector increases. 

These factors that contribute to emission 

decreases can be very difficult to 

quantify. Underestimating the impact of 

these types of factors can very easily 

result in a projection for increased 

emissions within a sector, when a 

correct estimate will result in a 

projection for decreased emissions 

within the sector. A few commenters 

opposed this methodology as arbitrary 

but failed to explain why EPA’s 

concerns, as described above, are not 

valid. Commenters also failed to 

propose other methodologies for 

addressing these concerns. Thus, EPA is 

finalizing the use of this second 

methodology. 

iii. Controlled Emissions Estimates for 

2010 and 2015 

The third step is to develop the 2010 

and 2015 controlled emissions estimates 

by assuming the same changes in 

economic output and other factors listed 

above but adding the effects of the new 

controls adopted for the purpose of 

meeting the CAIR. The controls may 

take the form of regulatory 

requirements, e.g., emissions caps, 

emission rate limits, technology 

requirements, or work practice 

requirements. The State’s estimate of the 

effect of the control regulations must be 

realistic in light of the specific 

provisions for monitoring, reporting, 

and enforcement and experience with 

similar regulatory approaches. 

In addition, the State’s analysis must 

examine the possibility that the controls 

may cause production and emissions to 

shift to unregulated or less stringently 

regulated sources in the same State or 

another State. If all sources of a source 

category (defined to include all sources 

where any aspect of production is 

reasonably interchangeable) within the 

State are regulated with the same 

stringency and compliance assurance 

provisions, the analysis of production 

and emissions shifts need only consider 

the possibility of shifts to other States. 

If only a portion of a source category 

within a State is regulated, the analysis 

must also include any in-State shifting. 

In estimating controlled emissions in 

2010 and 2015, assumptions regarding 

control measures that are not eligible for 

CAIR reduction credit must be the same 

as in the 2010 and 2015 baseline 

estimates. For example, a State may not 

take credit for reductions in the sulfur 

content of nonroad diesel fuel that are 

required under the recent Federal 

nonroad fuel rule (69 FR 38958; June 29, 

2004). By including the effect of this 

Federal rule in both the baseline and 

controlled emissions estimates for 2010 

and 2015, the State will appropriately 

exclude this ineligible reduction when 

it subtracts the controlled emissions 

estimates from the baseline emissions 

estimates. 

The method that we are adopting 

today specifies the 2010 and 2015 

emissions reductions which can be 

counted toward satisfying the CAIR. The 

method requires the use of the historical 

baseline or the baseline emission 

estimates, whichever is lower. That is, 

the reduction is calculated as follows: (i) 

For 2010, the difference between the 

lower of historical baseline or 2010 

baseline emissions estimates and the 

2010 controlled emissions estimates, 

minus any emissions that may shift to 

other sources rather than be eliminated; 

and (ii) for 2015, the difference between 

the lower of historical baseline or 2015 

baseline emissions estimates and the 

2015 controlled emissions estimates, 

minus any emissions that may shift to 

other sources rather than be eliminated. 

4. Controls on Non-EGUs Only 

Although we stated that we believe it 

is unlikely States may choose to control 

only non-EGUs, we proposed in the 

CAIR SNPR provisions for determining 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25263

112See ‘‘Technical Support Document for the 

Clean Air Interstate Rule Notice of Final 

Rulemaking; Regional and State SO2 and NOX

Emissions Budgets’’ for tables containing 

information to calculate these amounts for both SO2

and NOX.

113By statute, the date for submission of 

nonattainment area SIPs is to be no later than 3 

years from the date of nonattainment designation. 

Section 172(b).

the specified emissions reductions that 

must be obtained if States pursue this 

alternative, and we adopt those 

provisions today. The reason we think 

it is unlikely is based on States’

emissions profiles. Most SO2 emissions 

are from EGUs and therefore it is 

unlikely that a State can achieve the 

required emissions reductions without 

regulating EGUs to some degree. In 

addition, SO2 emissions reductions from 

EGUs are highly cost effective. States 

that choose this path must ensure that 

the amount of non-EGU reductions is 

equivalent to all of the emissions 

reductions that would have been 

required from EGUs had the State 

chosen to assign all the emissions 

reductions to EGUs. For SO2 emissions, 

this amount in 2010 would be 50 

percent of a State’s title IV SO2

allocations for all units in the State and, 

for 2015, 65 percent of such allocations. 

For NOX emissions, this amount would 

be the difference between a State’s EGU 

budget for NOX under the CAIR and its 

NOX baseline EGU emissions inventory 

as projected in the Integrated Planning 

Model (IPM) for 2010 and 2015, 

respectively.112

In addition, the same requirements 

described elsewhere in this part of 

today’s preamble regarding the 

eligibility of non-EGU reductions, 

emissions control and monitoring, 

emissions inventories and 

demonstration of reductions, will apply 

to the situation where a State chooses to 

control only non-EGUs.

5. Use of Banked Allowances and the 

Compliance Supplement Pool 

In the CAIR NPR, EPA stated that 

States may allow EGUs to demonstrate 

compliance with the State EGU SO2

budget by using title IV allowances (i) 

that were banked, or (ii) that were 

obtained in the current year from 

sources in other States (69 FR 4627). 

The EPA adopts this provision in 

today’s action. The EPA adopts a similar 

provision for the use of banked NOX SIP 

Call allowances (pre-2009) to 

demonstrate compliance with the State 

EGU ozone season NOX budget. See also 

the CAIR NPR (69 FR 4633). Therefore, 

State rules may allow the use of pre2010 title IV and pre-2009 NOX SIP Call 

allowances banked in the title IV and 

NOX SIP Call trading programs for 

compliance in the CAIR. States 

participating in the EPA-administered 

CAIR trading programs must allow the 

use of these pre-2010 title IV allowances 

or pre-2009 NOX SIP Call allowances in 

accordance with EPA’s model trading 

rules. 

Additionally, States with annual NOX

reduction requirements may use 

compliance supplement pool (CSP) 

allowances as described in sections V 

and VIII. Distribution of the CSP is 

essentially the same as the process used 

in the NOX SIP Call, through one or both 

of two mechanisms. States may 

distribute CSP allowances on a pro-rata 

basis to sources that implement NOX

control measures resulting in reductions 

in 2007 or 2008 that are beyond what is 

required by any applicable State or 

Federal emissions limitation (early 

reductions). The second CSP 

distribution mechanism that a State can 

use is to issue CSP allowances based on 

the demonstration of a need for an 

extension of the 2009 deadline for 

implementing emission controls. The 

demonstration must show unacceptable 

risk either to a source’s own operation 

or its associated industry—for EGUs, 

power supply reliability, for non-EGUs 

risk comparable to that described for the 

electricity industry. See also 63 FR 

57356 for further discussion of these 

points. 

Pre-2010 title IV SO2 allowances, pre2009 NOX SIP Call allowances and CAIR 

annual NOX CSP allowances can all be 

counted toward a States efforts to 

achieve its CAIR reduction obligations 

regardless of whether the CAIR trading 

programs are used or not. 

B. State Implementation Plan Schedules 

1. State Implementation Plan 

Submission Schedule 

In the NPR, we proposed to require 

States to submit SIPs to address 

interstate transport in accordance with 

the provisions of this rule 

approximately 18 months from the date 

of this final rule (69 FR 4624). After 

careful consideration of the comments 

we received concerning this issue, we 

have concluded that States should 

submit SIPs to satisfy this final rule as 

expeditiously as possible, but no later 

than 18 months from the date of today’s 

action. Under this schedule, upwind 

States’ transport SIPs to meet CAA 

section 110(a)(2)(D) will be due before 

the downwind States’ PM2.5 and 8-hour 

ozone nonattainment area SIPs under 

CAA section 172(b). We expect that the 

downwind States’ 8-hour ozone 

nonattainment area SIPs will be due by 

June 15, 2007, and their PM2.5

nonattainment SIPs will be due by April 

5, 2008.113

We believe that this sequence for SIP 

submissions to address upwind 

interstate transport and downwind 

nonattainment areas is consistent both 

with the applicable provisions of the 

CAA and with sound policy objectives. 

The CAA provides for this sequence of 

submissions in section 110(a)(1) and 

(a)(2), which provide that the submittal 

period for SIPs required by section 

110(a)(2)(D) runs from the earlier date of 

the NAAQS revision, and in section 

172(b), which provides that the 

submittal period for the nonattainment 

area SIPs runs from the later date of 

designation. Clean Air Act section 

110(a)(1) requires each State to submit 

a SIP to EPA ‘‘within 3 years * * * after 

the promulgation of a [NAAQS] (or any 

revision thereof).’’ Section 110(a)(2) 

makes clear that this SIP must include, 

among other things, provisions to 

address the requirements of section 

110(a)(2)(D). We read these provisions 

together to require that each upwind 

State must submit, within 3 years of a 

new or revised NAAQS, SIPs that 

address the section 110(a)(2)(D) 

requirement. By contrast, the schedule 

provided in section 172(b) is only 

applicable to the nonattainment area SIP 

requirements.

Section 110(a) imposes the obligation 

upon States to make a submission, but 

the contents of that submission may 

vary depending on the facts and 

circumstances. In particular, the data 

and analytical tools available at the time 

the section 110(a)(2)(D) SIP is developed 

and submitted to EPA necessarily affect 

the content of the submission. Where, as 

here, the data and analytical tools to 

identify a significant contribution from 

upwind States to nonattainment areas in 

downwind States are available, the 

State’s SIP submission must address the 

existence of the contribution and the 

emission reductions necessary to 

eliminate the significant contribution. In 

other circumstances, however, the tools 

and information may not be available. In 

such circumstances, the section 

110(a)(2)(D) SIP submission should 

indicate that the necessary information 

is not available at the time the 

submission is made or that, based on the 

information available, the State believes 

that no significant contribution to 

downwind nonattainment exists. EPA 

can always act at a later time after the 

initial section 110(a)(2)(D) submissions 

to issue a SIP call under section 

110(k)(5) to States to revise their SIPs to 

provide for additional emission controls 

to satisfy the section 110(a)(2)(D) 

obligations if such action were 

25264 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

114Under section 107(d), EPA is required to 

identify all areas of each State as falling into one 

of these three categories.

115The EPA notes that under the provisions of 

section 107(d), certain portions of an upwind State 

that are monitoring attainment may be designated 

nonattainment because they contribute to violations 

of the NAAQS in a ‘‘nearby’’ area. Nevertheless, 

warranted based upon subsequentlyavailable data and analyses. This is 

precisely the circumstance that was 

presented at the time of the NOX SIP 

Call in 1998 when EPA issued a section 

110(k)(5) SIP call to states regarding 

their section 110(a)(2)(D) obligations on 

the basis of new information that was 

developed years after the States’ SIPs 

had been previously approved as 

satisfying section 110(a)(2)(D) without 

providing for additional controls since 

the information available at the earlier 

point in time did not indicate the need 

for such additional controls. 

Not only is this sequencing consistent 

with the CAA, it is consistent with 

sound policy considerations. The 

upwind reductions required by today’s 

action will facilitate attainment 

planning by the States affected by 

transport downwind. Rather than being 

‘‘premature’’ as some commenters 

suggested, EPA’s understanding of the 

data and models leads the Agency to 

believe that requiring the States to 

address the upwind transport 

contribution to downwind 

nonattainment earlier in the process as 

a first step is a reasonable approach and 

is fully consistent with the statutory 

structure. This approach will allow 

downwind States to develop SIPs that 

address their share of emissions with 

knowledge of what measures upwind 

States will have adopted. In addition, 

most of the downwind States that will 

benefit by today’s rulemaking are 

themselves significant contributors to 

violations of the standards further 

downwind and, thus, are subject to the 

same requirements as the States further 

upwind. The reductions these 

downwind States must implement due 

to their additional role as upwind States 

will help reduce their own PM2.5 and 8-

hour ozone problems on the same 

schedule as emissions reductions for the 

upwind States. We believe that 

providing 18 months from the date of 

today’s action for States to submit the 

transport SIPs required by this rule is 

appropriate and reasonable, for the 

reasons discussed more fully below. 

a. The EPA’s Authority To Require 

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

Accordance With the Schedule of 

Section 110(a)(1)

A number of commenters objected to 

EPA’s proposal to require States to 

submit the transport SIPs on the 

schedule set forth in section 110(a)(1). 

The commenters argued that section 

110(a)(1) does not apply to the 

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

because the former refers to plans that 

States must adopt ‘‘to implement, 

maintain, and enforce’’ the NAAQS 

‘‘within’’ the State, whereas the latter 

refers to plans that prevent emissions 

that affect nonattainment or 

maintenance of the NAAQS in places 

outside the State. According to the 

commenters, because section 110(a)(1) 

SIPs purportedly need not address the 

interstate transport issues governed by 

section 110(a)(2)(D), the States have no 

current obligation to prevent such 

interstate transport and, by extension, 

there is no basis for the CAIR at this 

time. 

The EPA disagrees with the 

commenters. A State’s SIP must of 

course provide for ‘‘implementation, 

maintenance, and enforcement’’ of the 

NAAQS ‘‘within’’ the State because 

States lack authority to impose 

requirements on sources in other States; 

i.e., any plan submitted by a State will 

necessarily be applicable to sources 

‘‘within’’ that State. The CAA, however, 

also requires that such SIPs must be 

submitted to EPA no later than three 

years after promulgation of a new or 

revised NAAQS and must contain 

adequate provisions regarding interstate 

transport from emission sources within 

the State in compliance with section 

110(a)(2)(D). The explicit terms of the 

statute provide for the State submission 

of initial SIPs after promulgation of a 

new NAAQS, and provide that such 

SIPs should address interstate transport. 

Section 110(a)(1) provides that:

[e]ach State shall * * * adopt and submit to 

the Administrator, within 3 years (or such 

shorter period as the Administrator may 

prescribe) after the promulgation of a 

national primary ambient air quality standard 

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

provides for implementation, maintenance, 

and enforcement of such primary standard in 

each [area] within such State.

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

part, that:

[e]ach implementation plan submitted by a 

State under this Act shall be adopted by the 

State after reasonable notice and public 

hearing. Each such plan shall * * * (D) 

contain adequate provisions—(i) prohibiting 

* * * any source or other type of emissions 

activity within the State from emitting any 

air pollutant in amounts which will—(I) 

contribute significantly to nonattainment in, 

or interfere with maintenance by, any other 

State with respect to [the NAAQS].

By referencing each implementation 

plan in section 110(a)(2), it is clear that 

the implementation plans required 

under section 110(a)(1) must satisfy the 

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

Thus, the plain meaning of these 

provisions, read together, is that SIP 

submissions are required within 3 years 

of promulgation of a new or revised 

NAAQS, and that the SIP submissions 

must meet the requirements of section 

110(a)(2)(D). 

By contrast, other requirements of 

section 110(a)(2) are not triggered by 

EPA’s promulgation of a new or revised 

NAAQS, but rather by EPA’s final 

designation of nonattainment areas. For 

example, section 110(a)(2)(I) by its terms 

indicates that State SIPs must meet that 

requirement not on the schedule of 

section 110(a)(1), but instead on the 

schedule of section 172(b). 

The explicit distinction in the statute 

between requirements that States must 

meet on the schedule of section 

110(a)(1) versus the schedule of section 

172(b) reinforces the conclusion that 

States are to meet the initial 

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

within the schedule of section 110(a)(1).

In this context, it is important to note 

that the requirements of section 

110(a)(1) plans are not limited to areas 

designated attainment, nonattainment, 

or unclassifiable.114 Section 110(a)(1) 

requires each State to develop and 

submit a plan that provides for the 

implementation, maintenance, and 

enforcement of the NAAQS in ‘‘each’’

area of the State. Similarly, the 

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

SIPs must prohibit interstate transport 

of air pollutants that significantly 

contribute to downwind nonattainment 

is not limited to any particular category 

of formally designated areas in the State. 

The provisions apply to emissions 

activities that occur anywhere in a state, 

regardless of its designation. If, as the 

commenters suggested, the requirements 

of section 110(a)(2)(D) plans are 

governed not by section 110(a)(1), but 

rather by the schedule of section 172, 

that would lead to the absurd result that 

upwind States need only reduce 

emissions from designated 

nonattainment areas to prevent 

significant contribution to 

nonattainment or interference with 

maintenance in a downwind State. 

Given that large portions of many 

upwind States may be designated as 

attainment for the NAAQS for local 

purposes, yet still contain large sources 

of emissions that affect downwind 

States through interstate transport, EPA 

believes that Congress could not have 

intended the prohibitions of section 

110(a)(2)(D) to apply only to 

nonattainment areas in upwind 

States.115 Indeed, the language of 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25265

there will be portions of upwind States that include 

emissions sources that are not in designated 

nonattainment areas, whether because of local 

monitored nonattainment, or because of 

contribution to a nearby nonattainment area, yet 

these portions of the upwind State may contain 

sources that cause emissions that States must 

address to meet the requirements of section 

110(a)(2)(D).

116As noted earlier, what will be needed to meet 

section 110(a)(2) may vary, depending upon the 

specific facts and circumstances surrounding a new 

or revised NAAQS. See, e.g., Proposed 

Requirements for Implementation Plans and 

Ambient Air Quality Surveillance for Sulfur Oxides 

(Sulfur Dioxide) National Ambient Air Quality 

Standard, 60 FR 12492, 12505 (March 7, 1995). In 

the context of a proposed 5-minute NAAQS for S02, 

EPA tentatively concluded that existing SIP 

provisions for the 24-hour and annual S02 NAAQS 

were probably sufficient to meet many elements of 

section 110(a)(2). The EPA did not explicitly 

discuss State obligations under section 110(a)(2)(D) 

for the 5-minute NAAQS in the proposal, but the 

nature of the pollutant, the sources, and the 

proposed NAAQS are such that interstate transport 

would not have been the critical regionwide 

concern that it is for the PM2.5 and 8-hour ozone 

NAAQS. The EPA does not expect States to make 

SIP submissions establishing emission controls for 

the purpose of addressing interstate transport 

without having adequate information available to 

them.

117The EPA notes that the 8-hour ozone 

designations became effective on June 15, 2004, and 

that the PM2.5 designations will become effective on 

April 5, 2005. The EPA believes that the issue 

raised by the commenters is thus moot with respect 

to both the 8-hour ozone and PM2.5 nonattainment 

areas because those designations are now complete.

section 110(a)(2) itself does not support 

such an interpretation. Therefore, the 

alternative schedule provided in section 

172(b) applicable only to nonattainment 

areas cannot be the schedule that 

governs the State submission of 

transport SIPs. This leaves the schedule 

of section 110(a)(1) as the only 

appropriate schedule in the case of SIPs 

following EPA promulgation of new or 

revised NAAQS.

The commenters also disputed that 

the schedule of section 110(a)(1) applies 

to the section 110(a)(2)(D) requirement 

because there are other elements of 

section 110(a)(2) that States could not 

meet on that schedule. As an example, 

the commenters pointed to section 

110(a)(2)(I) which requires States to 

meet certain obligations imposed upon 

designated nonattainment areas. As 

formal designation under the generally 

applicable provisions of section 107(d) 

could take up to 3 years following 

promulgation of a new or revised 

NAAQS, and section 172(b) allows up to 

3 additional years for State submission 

of nonattainment area SIPs, the 

commenters concluded that States could 

not meet section 110(a)(2)(I) on the 

schedule of section 110(a)(1). From the 

fact that States could not meet all of the 

elements of the section 110(a)(2) 

requirement within 3 years, the 

commenters inferred that EPA cannot 

require States to meet any of the 

requirements in section 110(a)(2), 

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

The EPA disagrees with the 

commenters’ approach to the 

interpretation of the statute. The EPA 

agrees that there are certain provisions 

of section 110(a)(2) that are governed 

not by the schedule of section 110(a)(1), 

but instead by the timing requirement of 

section 172(b), e.g., section 110(a)(2)(I). 

Other items in section 110(a)(2), 

however, do not depend upon prior 

designations in order for States to 

develop a SIP to begin to comply with 

them, e.g., section 110(a)(2)(B) 

(pertaining to monitoring); section 

110(a)(2)(E) (stipulating that States must 

provide for adequate resources); and 

section 110(a)(2)(K) (pertaining to 

modeling).

Most important, section 110(a)(2)(D) 

itself does not apply only to impacts on 

downwind nonattainment areas, and 

thus does not presuppose prior 

designations in either upwind or 

downwind States, or suggest that 

section 110(a)(2)(D) is somehow 

inapplicable until the submission of 

nonattainment area plans. By its explicit 

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

States to prohibit emissions from ‘‘any 

source or other types of emissions 

activity within the State’’ that 

‘‘contribute to nonattainment in, or 

interfere with maintenance by’’ any 

other State. A plain reading of the 

statute indicates that the emissions at 

issue can emanate from any portion of 

an upwind State and that the impacts of 

concern can occur in any portion of the 

downwind State. 

While EPA agrees that there is overlap 

between the submission requirements of 

sections 110(a)(1) and (a)(2) and section 

172(c), EPA believes that the plain 

language of these sections requires 

States to submit plans that comply with 

section 110(a)(2)(D) prior to the 

deadline for nonattainment area SIPs 

established by section 172, and that 

there is nothing that compels a contrary 

conclusion in the language of section 

172. Section 172(b) provides that State 

plans for nonattainment areas must 

meet ‘‘the applicable requirements of 

[section 172(c)] and section 110(a)(2)’’

(emphasis added). Thus, the statute 

itself explicitly indicates that the State 

submissions for nonattainment plans 

must meet those requirements of section 

110(a)(2) that are ‘‘applicable,’’ not each 

requirement regardless of applicability. 

In the current situation, EPA believes 

that it is appropriate to view the CAA 

as requiring States to make a submission 

to meet the requirement of section 

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

schedule of section 110(a)(1), rather 

than under the schedule for 

nonattainment SIPs in section 172(b).116

b. The EPA’s Authority To Require 

Section 110(a)(2)(D) Submissions Prior 

to Formal Designation of Nonattainment 

Areas Under Section 107 

A number of commenters argued that 

EPA has no authority to require States 

to comply with section 110(a)(2)(D) 

until after EPA formally designates 

nonattainment areas for the PM2.5 and 8-

hour ozone NAAQS.117 These 

commenters claimed that section 107(d) 

and provisions of the Transportation 

Equity Act for the 21st Century (TEA–

21) governing the designation of PM2.5

and 8-hour ozone nonattainment areas 

preclude EPA from interpreting the 

CAA to require States to submit SIPs 

that comply with section 110(a)(2)(D) on 

the schedule contemplated by section 

110(a)(1). In the view of the 

commenters, EPA could not reasonably 

expect States to determine whether and 

to what extent their in-State sources 

significantly contributed to 

nonattainment in other States within the 

initial 3-year timeframe, in advance of 

nonattainment area designations. 

According to the commenters, section 

107(d) and TEA–21 negate the timing 

requirements of section 110(a)(1), so 

that States have no current obligation to 

address interstate transport and thus 

there is no basis for today’s action.

The EPA disagrees with the 

commenters’ view of the interaction of 

section 110 and section 107(d). The 

statute does not require EPA to have 

completed the designations process 

before the Agency or a State could 

assess the existence of, or extent of, 

significant contribution from one State 

to another. In addition, the technical 

approach by which EPA determines 

significant contribution from upwind to 

downwind States does not depend upon 

the prior completion of the designation 

process. 

The EPA believes that the statute does 

not compel the conclusion that States 

may postpone compliance with section 

110(a)(2)(D) until some future point 

after completion of the designation 

process. As discussed above, a reading 

of the plain language of sections 

110(a)(1) and 110(a)(2) indicates that 

States must adopt and submit a plan to 

EPA within 3 years after promulgation 

of a new or revised NAAQS (the same 

time at which designations are generally 

due under section 107), and that each 

25266 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

118For reasons discussed in more detail above, 

EPA interprets the requirement of section 

110(a)(2)(D) to be among those that Congress 

intended States to meet within the 3-year timeframe 

of section 110(a)(1). The EPA agrees that other 

requirements, such as those of section 110(a)(2)(I), 

are subject to the different timing requirements of 

section 172(b).

such plan must meet the applicable 

requirements of section 110(a)(2)(D).118

Significantly, neither section 110(a)(1) 

nor section 110(a)(2)(D) are limited to 

‘‘nonattainment’’ areas. By their explicit 

terms, both provisions apply to all areas 

within the State, regardless of whether 

EPA has formally designated the areas 

as attainment, nonattainment, or 

unclassifiable, pursuant to section 

107(d). As to causes, section 

110(a)(2)(D) compels States to address 

any ‘‘emissions activity within the 

State,’’ not solely emissions from 

formally designated nonattainment 

areas, nor does it in any other terms 

suggest that designations of upwind 

areas must first have occurred. As to 

impacts, section 110(a)(2)(D) refers only 

to prevention of ‘‘nonattainment’’ in 

other States, not to prevention of 

nonattainment in designated 

nonattainment areas or any similar 

formulation requiring that designations 

for downwind nonattainment areas 

must first have occurred. By 

comparison, other provisions of the 

CAA do clearly indicate when they are 

applicable to designated nonattainment 

areas, rather than simply to 

nonattainment more generally (e.g., 

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

and 211(k)(10)(D)). Because section 

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

‘‘nonattainment,’’ not to ‘‘nonattainment 

areas,’’ EPA concludes that the section 

does not presuppose the existence of 

formally designated nonattainment 

areas, but rather to ambient air quality 

that does not attain the NAAQS. 

The EPA believes that this plain 

reading of the provisions is also the 

most logical approach. A reading that 

section 110(a)(2)(D) means that States 

have no obligation to address interstate 

transport unless and until there are 

formally designated nonattainment 

areas pursuant to section 107 would be 

inconsistent with the larger goal of the 

CAA to encourage expeditious 

attainment of the NAAQS. In this 

immediate instance, currently available 

air quality monitoring data and 

modeling make it clear that many areas 

of the eastern portion of the country are 

in violation of both the PM2.5 and 8-hour 

ozone NAAQS. Air quality modeling 

studies generally available to the States 

demonstrate that, and quantify the 

extent to which, SO2 and NOX

emissions from sources in upwind 

States are contributing to violations of 

the PM2.5 and 8-hour ozone NAAQS in 

downwind States. 

Following the example of the NOX SIP 

Call, EPA has an effective analytical 

approach to determine whether that 

interstate contribution is significant, in 

accordance with section 110(a)(2)(D). 

Thus, EPA currently has the information 

and tools that it needs to determine 

what the initial PM2.5 and 8-hour ozone 

SIPs from upwind States should include 

as appropriate NOX and SO2 emissions 

reductions in order to prevent emissions 

that significantly contribute to 

nonattainment in downwind States. The 

designation process under section 107 is 

the means by which States and EPA 

decide the precise boundaries of the 

nonattainment areas in the downwind 

States. Both PM2.5 and ozone are 

regional phenomena, however, and 

information as to the precise boundaries 

of nonattainment areas is not necessary 

to implement the requirements of 

section 110(a)(2)(D) for these pollutants. 

Consequently, it was not necessary for 

EPA to wait until after completion of 

formal designation of nonattainment 

area boundaries before undertaking this 

rulemaking. Moreover, EPA believes 

that taking action now will achieve 

public health protections more quickly 

as it will enable States to develop 

implementation plans more 

expeditiously and efficiently. 

The EPA disagrees with the 

commenters’ view of the relationship 

between section 110(a)(2) and section 

107 and their apparent view of the 

method by which EPA analyzes whether 

there is a contribution from an upwind 

State to a downwind State, and whether 

that contribution is significant. 

The EPA has, in this case, used the 

detailed data from the extensive 

network of air quality monitors to 

identify which States have monitors that 

are currently showing violations of the 

PM2.5 and 8-hour ozone NAAQS. In the 

NPR, EPA stated that based upon data 

for the 3-year period from 2000–2002, 

‘‘120 counties with monitors exceed the 

annual PM2.5 NAAQS and 297 counties 

with monitor readings exceed the 8-

hour ozone NAAQS’’ (69 FR 4566, 4581; 

January 30, 2004) (emphasis added). 

The geographic distribution of monitors 

with data registering current violations 

indicated that there is nonattainment of 

both the PM2.5 and 8-hour ozone 

NAAQS throughout the eastern United 

States and in other portions of the 

country including California. For 

analyses of future ambient conditions, 

EPA used various modeling tools to 

predict that, in the absence of the CAIR, 

there would be counties with monitors 

that would continue to show violations 

of the PM2.5 and 8-hour ozone NAAQS 

in 2010 and 2015. In subsequent steps, 

EPA analyzed whether the emissions 

from upwind States contributed to the 

ambient conditions at the monitors 

registering NAAQS violations in 

downwind States, and thereafter 

determined whether that contribution 

would be significant pursuant to section 

110(a)(2)(D).

In none of these steps, however, did 

EPA need to know the precise 

boundaries of the nonattainment areas 

that may ultimately result from the 

section 107 designation process. The 

determination of attainment status in a 

given county is based primarily upon 

the monitored ambient measurements of 

the applicable pollutant in the county. 

Thus, it is the readings at the monitors 

that are the appropriate information for 

EPA to evaluate in assessing current and 

future interstate transport at that 

monitor in that county, not the exact 

dimensions of the area that may 

ultimately comprise the formally 

designated nonattainment area. The 

ultimate size of nonattainment areas 

will have a bearing on other 

components of the State’s 

nonattainment area SIP. The size of 

such nonattainment areas, however, is 

not meaningful in assessing whether 

interstate transport from another State 

or States has an impact at a violating 

monitor, and whether the transport 

significantly contributes to 

nonattainment, that the other State or 

States should address to comply with 

section 110(a)(2)(D). Thus, EPA believes 

that basing the significant contribution 

analysis upon the counties with 

monitors that register nonattainment, 

without regard to the precise boundaries 

of the nonattainment areas that may 

ultimately result from the formal 

designation process under section 107, 

is the proper approach. 

For similar reasons, EPA also 

disagrees with the commenters’

assertion that the provisions of TEA–21 

preclude EPA’s interpretation of the 

timing requirements of sections 

110(a)(1) and 110(a)(2). However, TEA–

21 did address the need to create a new 

network of monitors to assess the 

geographic scope and location of PM2.5

nonattainment. Also, TEA–21 did 

provide that such a network should be 

up and running by December 31, 1999. 

TEA–21 did lay out a schedule for the 

collection of data over a period of 3 

years in order to make subsequent 

regulatory decisions. From these facts, 

the commenters concluded that TEA–21 

necessarily contradicts EPA’s position 

that States must now take action to 

address significant contribution to 

downwind nonattainment in their 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25267

initial section 110(a)(1) SIPs, merely 

because the initial 3-year period 

following the promulgation of a new or 

revised NAAQS specified in section 

110(a)(1) has expired. 

The EPA believes that nothing in 

TEA–21 explicitly or implicitly altered 

the timing requirements of section 

110(a)(1) for compliance with section 

110(a)(2)(D), although EPA recognizes 

that the data from monitoring funded by 

that Act contributed to the Agency’s 

development of the SIP requirements in 

today’s rulemaking. The provisions of 

TEA–21 pertained to the installation of 

a network of monitors for PM2.5, and to 

the timing of designation decisions for 

PM2.5 and 8-hour ozone. To be specific, 

TEA–21 had two primary purposes for 

the new NAAQS: (1) To gather 

information ‘‘for use in the 

determination of area attainment or 

nonattainment designations’’ for the 

PM2.5 NAAQS; and (2) to ensure that 

States had adequate time to consider 

guidance from EPA concerning 

‘‘drawing area boundaries prior to 

submitting area designations’’ for the 8-

hour ozone NAAQS. TEA–21 sections 

6101(b)(1) and (2). The EPA interprets 

the third stated purpose of TEA–21 to 

refer to ensuring consistency of timing 

between the Regional Haze program 

requirements and the PM2.5 NAAQS 

requirements. With respect to timing, 

TEA–21 similarly only referred to the 

dates by which States and EPA should 

take their respective actions concerning 

designations. For PM2.5, TEA–21 

provided that States were required ‘‘to 

submit designations referred to in 

section 107(d)(1) * * * within 1 year 

after receipt of 3 years of air quality 

monitoring data.’’ TEA–21 section 

6102(c)(1). For 8-hour ozone, TEA–21 

required States to submit designation 

recommendations within 2 years after 

the promulgation of the new NAAQS, 

and required EPA to make final 

designations within 1 year after that 

(TEA–21 sections 6103(a) and (b)). In all 

of these provisions, TEA–21 only 

addresses SIP timing in the context of 

the designation process of section 

107(d). As explained in more detail 

above, EPA does not believe that the 

timing of section 110(a)(1) and section 

110(a)(2)(D) obligations depend upon 

the prior designation of areas in 

accordance with section 107(d).

The EPA also notes that legislation 

subsequent to TEA–21 further supports 

this conclusion. In the 2004 

Consolidated Appropriations Act, 

Congress further amended section 107 

to provide specific dates by which 

States and EPA must make PM2.5

designations. 42 U.S.C. 7407 note. The 

Act now requires States to have made 

their initial recommendations for PM2.5

designations by February 15, 2004, and 

requires EPA to take action on those 

recommendations and make its final 

designation decisions no later than 

December 31, 2004. Again, these 

requirements pertain only to formal 

designations, and do not directly affect 

the obligations of States to meet other 

SIP requirements. Neither TEA–21 nor 

the 2004 Appropriations Act language 

altered the section 110(a)(1) schedule 

for compliance with section 

110(a)(2)(D). 

The commenters suggested that 

because Congress provided more time 

for making formal designations pursuant 

to section 107, it necessarily follows 

that States should not have to meet the 

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

the schedule of section 110(a)(1). The 

EPA believes that Congress did not, 

through TEA–21 or other actions, alter 

the existing submission schedule for 

SIPs to address interstate transport. By 

contrast, Congress did explicitly alter 

the schedule for submission of plan 

revisions to address Regional Haze. 

From this, EPA infers that Congress did 

not intend EPA to delay action to 

address the issue of interstate transport 

for the 8-hour or PM2.5 NAAQS. Thus, 

EPA must still ensure that States submit 

SIPs in accordance with the substantive 

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

However, because EPA and the States 

now have the data and analyses to 

establish the presence and magnitude of 

interstate transport, in part through the 

monitoring data gathered pursuant to 

TEA–21, the Agency believes that that it 

is now appropriate to require States to 

address interstate transport at this time 

in the manner set forth in today’s rule. 

c. The EPA’s Authority To Require 

Section 110(a)(2)(D) Submissions Prior 

to State Submission of Nonattainment 

Area Plans Under Section 172 

Some commenters suggested that EPA 

cannot determine the existence of a 

significant contribution from upwind 

States to downwind States until EPA 

actually receives the nonattainment area 

SIPs from each State and evaluates how 

much ‘‘residual’’ nonattainment 

remains. If the reasoning of these 

commenters were adopted, downwind 

States would have to construct SIPs to 

attain the NAAQS without first knowing 

what upwind States might ultimately do 

to reduce interstate transport. 

Presumably, the theory is that the 

downwind States may choose to control 

their own local emissions sources more 

aggressively so that sources in upwind 

States could avoid installation of highly 

cost-effective emission controls, 

notwithstanding the continued 

significant impacts of emissions from 

upwind sources on downwind States. 

Alternatively, the rationale may be that 

EPA should wait until submission of 

upwind State nonattainment area SIPs 

to discover whether and to what degree 

the SIPs address interstate transport to 

downwind States. 

For reasons already discussed more 

fully above, EPA does not believe that 

the statute requires a ‘‘wait and see’’

approach to discover what, if anything, 

States may ultimately do to address the 

problem of regional interstate transport. 

Section 110(a)(1) requires ‘‘each’’ State 

to submit a SIP within 3 years after a 

new or revised NAAQS addressing the 

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

When the data and the analyses needed 

to establish the existence of interstate 

transport of pollutants and to determine 

whether there is a significant 

contribution to nonattainment or 

interference with maintenance by one 

State in another State are available, as 

here after the monitoring funded by 

TEA–21, EPA believes that it may act 

upon that information prior to State SIP 

submissions to ensure that States 

address such contribution 

expeditiously, as it is doing in this 

rulemaking. The EPA believes it is a 

better policy to assist the States to 

address the regional component of the 

nonattainment problem in a way that is 

equitable, timely, cost effective, and 

certain.

The EPA acknowledges that 

historically, especially in the case of 1-

hour ozone, the Agency has not had the 

data and the analytical tools to help 

upwind States to address interstate 

transport as early in the SIP process as 

it is doing today for PM2.5 and 8-hour 

ozone. The CAA has required States to 

regulate ozone or its regulatory 

predecessors since 1970. For many 

years, States and EPA focused on the 

adoption and implementation of local 

controls to bring local nonattainment 

areas into attainment. Thus, historically, 

local areas bore the burden of achieving 

attainment through imposition of 

control measures on local sources. By 

comparison, upwind States did not have 

to adopt local controls in attainment 

areas and typically did not adopt such 

controls solely to lessen the impact of 

their emissions on downwind States. 

Since 1977, the CAA has also imposed 

a series of local control obligations on 

1-hour ozone nonattainment areas, such 

as RACT for stationary sources, 

inspection and maintenance for mobile 

sources, and other requirements that 

became increasingly more stringent, 

based upon the level of local 

nonattainment. In spite of these local 

control efforts, there continued to be a 

25268 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

widespread problem with 

nonattainment that resulted, in part, 

from unaddressed interstate transport. A 

lack of information and analytical tools 

hindered the ability of EPA and the 

States to address the regional interstate 

transport component of 1-hour ozone 

nonattainment, until the NOX SIP Call 

in 1998. While it is thus true that the 

NOX SIP Call postdated the submission 

of nonattainment area SIPs, this should 

not be construed as evidence that the 

statute precludes the States and EPA 

from addressing interstate transport 

earlier in the process for the 8-hour 

ozone and PM2.5 NAAQS. 

Given that EPA and the States 

indisputably have the requisite 

information to identify interstate 

transport at this stage of SIP 

development, EPA believes, based upon 

its experience in implementing the 1-

hour ozone NAAQS, that it is preferable 

to take action under section 110(a)(2)(D) 

to address the regional transport 

component of the PM2.5 and 8-hour 

ozone nonattainment problem. States, 

both upwind and downwind, will still 

have an obligation to control emissions 

from sources within their boundaries for 

the purposes of local area attainment 

and maintenance of the NAAQS. The 

EPA does not believe, however, that it 

is either required by the statute, or in 

accordance with sound policy, for the 

Agency to wait until submission of the 

nonattainment area SIPs of downwind 

States to discover whether or not those 

SIPs will control local sources 

sufficiently to provide for eventual 

attainment regardless of continued 

significant contribution through 

interstate transport from upwind States. 

To the contrary, past experience with 

the 1-hour ozone NAAQS has 

demonstrated that delayed action to 

address the interstate component of 

nonattainment will potentially lead to 

delays in attainment as downwind areas 

struggle to overcome the impacts of 

transport. Indeed, a number of scientific 

and technical assessments of ozone and 

PM2.5 by the NRC and the Ozone 

Transport Assessment Group have 

identified addressing interstate 

transport as a critical issue in 

developing SIPs. 

d. The EPA’s Authority To Require 

Section 110(a)(2)(D) Submissions Prior 

to Completion of the Next Review of the 

PM2.5 and 8-Hour Ozone NAAQS 

Commenters also asserted that EPA 

should not take any action to implement 

the 8-hour ozone and PM2.5 NAAQS, 

until completion of the next NAAQS 

review cycle. According to the 

commenters, a series of statements by 

EPA and others indicated an intention 

to take no action to implement the 

NAAQS until after the next review 

cycle, and that statutes passed by 

Congress confirm that EPA is to take no 

such action. 

The EPA disagrees with the assertion 

that it should take no action to 

implement the 1997 PM2.5 and 8-hour 

ozone NAAQS until completion of the 

next NAAQS review. Section 110(a) 

explicitly requires States to begin to 

submit SIPS within 3 years after 

promulgation of a new or revised 

NAAQS. The CAA also requires EPA to 

take action upon State SIP submissions 

within specific timeframes. States are 

likewise explicitly obligated to attain 

existing NAAQS within certain 

specified timeframes. None of these 

basic statutory submission, review, or 

attainment obligations are stayed or 

delayed due to the fact that there may 

be an ongoing NAAQS review cycle. 

Indeed, under section 109, EPA is to 

review all NAAQS on an ongoing basis, 

every 5 years. If the mere existence of 

a NAAQS review cycle were grounds to 

suspend implementation of a NAAQS, it 

would undermine the very goals of the 

statute. 

The commenters argued that certain 

statements made by EPA and others in 

guidance memoranda and elsewhere 

preclude EPA from taking any action to 

implement the PM2.5 and 8-hour ozone 

NAAQS. The EPA believes that the 

commenters are misconstruing those 

statements, and that the statements 

merely reflect the Agency’s assumption 

that the NAAQS review cycle would 

occur on the normal schedule. It would 

be nonsensical to suggest that, if for any 

reason, the NAAQS review cycle were 

delayed, that the CAA would permit no 

implementation of the existing NAAQS. 

Such an approach would invite and 

encourage inappropriate interference in 

the NAAQS review cycle as a means of 

subverting the CAA. 

The commenters further argued that 

Congress has taken action to prevent 

implementation of the 8-hour ozone and 

PM2.5 NAAQS pending the next NAAQS 

review cycle. The EPA does not see any 

such intention on the part of Congress. 

In TEA–21 and the 2004 Consolidated 

Appropriations Act, Congress has 

amended section 107 to provide specific 

dates by which States and EPA must 

make designations. Significantly, 

Congress did not alter the existing 

statute with respect to any other 

deadlines for SIP submissions, or with 

respect to implementation of the PM2.5

and 8-hour ozone NAAQS generally. By 

contrast, in the 2004 Consolidated 

Appropriations Act, Congress did 

explicitly alter the date by which States 

must submit plan revisions to address 

Regional Haze. See, Section 7(A), 42 

U.S.C. section 7407 note. From this 

explicit action, one must infer that 

Congress could have taken action to 

alter the submission date for plans to 

address PM2.5 or 8-hour ozone, had it 

intended to alter the existing statutory 

scheme. Most importantly, however, 

Congress did not make any of the 

changes effected in TEA–21 or the 2004 

Consolidated Appropriations Act 

dependent upon completion of the next 

NAAQS review. To the contrary, 

Congress directed EPA to take certain 

actions notwithstanding the fact that 

there were and are ongoing reviews of 

the NAAQS. From this, EPA infers that 

Congress did not intend EPA to defer all 

action to implement the existing 

NAAQS, including today’s action to 

assist States to address the requirements 

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

e. The EPA’s Authority To Require 

States To Make Section 110(a)(2)(D) 

Submissions Within 18 Months of This 

Final Rule

Some commenters questioned EPA’s 

proposal to require States to make SIP 

submissions in response to this action 

as expeditiously as practicable but no 

later than within 18 months. A number 

of commenters suggested that this 

schedule is too short because of the 

magnitude or complexity of the task or 

because of the typical duration of State 

rulemaking processes. Other 

commenters suggested that EPA should 

follow the example of the NOX SIP Call 

more closely and provide a shorter 

period than the Agency proposed. 

The EPA has concluded that the 

proposed 18-month schedule is 

reasonable given the circumstances and 

given the scope of the actions that we 

are requiring States to take. We issued 

the PM2.5 and 8-hour ozone NAAQS 

revisions in July 1997. More than 3 

years have already elapsed since 

promulgation of the NAAQS, and States 

have not submitted SIPs to address their 

section 110(a)(2)(D) obligations under 

the new NAAQS. We recognize that 

litigation over the new PM2.5 and 8-hour 

ozone NAAQS created substantial 

uncertainty as to whether the courts 

would uphold the new NAAQS, and 

that this uncertainty, as a practical 

matter, rendered it more difficult for 

States to develop SIPs. Moreover, in the 

case of PM2.5, additional time was 

needed for creation of an adequate 

monitoring network, collection of at 

least 3 years of data from that network, 

and analysis of those data. 

In addition, in the NPR, the SNPR, 

and today’s action, we have provided 

States with a great deal of data and 

analysis concerning air quality and 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25269

119See, e.g., section 182(a)(2)(A) (providing a 6-

month schedule for submission of a revision to 

provide for RACT corrections); section 189(d) 

(providing 12 months for submission of plan 

revisions to ensure attainment and required 

emissions reductions). The former revision could be 

relatively limited in scope, but the latter might 

entail submission of a completely revised SIP.

control costs, as well as policy 

judgments from EPA concerning the 

appropriate criteria for determining 

whether upwind sources contribute 

significantly to downwind 

nonattainment under section 

110(a)(2)(D). We recognize that States 

would face great difficulties in 

developing transport SIPs to meet the 

requirements of today’s action without 

these data and policies. In light of these 

factors and the fact that States can no 

longer meet the original 3-year submittal 

date of section 110(a)(1), we believe that 

States need a reasonable period of time 

in which to comply with the 

requirements of today’s action. 

In the comparable NOX SIP Call 

rulemaking, EPA provided 12 months 

for the affected States to submit their 

SIP revisions. One of the factors that we 

considered in setting that 12-month 

period was that upwind States had 

already, as part of the Ozone Transport 

Assessment Group process begun 3 

years before the NOX SIP Call 

rulemaking, been given the opportunity 

to consider available control options. 

Because today’s action requires affected 

States to control both SO2 and NOX

emissions, and to do so for the purpose 

of addressing both the PM2.5 and 8-hour 

ozone NAAQS, we believe it is 

reasonable to allow affected States more 

time than was allotted in the NOX SIP 

Call to develop and submit transport 

SIPs. 

Another factor that we have 

considered is that under section 

110(k)(5), the CAA stipulates that EPA 

may provide up to 18 months for SIP 

submissions to correct substantially 

inadequate plans. While today’s action 

is not pursuant to section 110(k)(5), we 

believe that the provision provides an 

analogy for the appropriate schedule on 

which EPA should expect States to 

make the submission required by 

today’s action. We believe it would not 

be appropriate to set a longer schedule 

for submission of the plan than would 

have been possible under section 

110(k)(5) had the States submitted a 

plan on the original 3-year schedule 

contemplated in section 110(a)(1) that 

did not provide for the emissions 

reductions today’s action requires. 

While the CAA does require States to 

make some SIP submissions on shorter 

schedules, we conclude that the 

complexities of the action required by 

today’s rulemaking militate in favor of 

a longer schedule.119

Finally, we note that by making 

findings that States have thus far failed 

to submit SIPs to meet the requirements 

of section 110(a)(2)(D) for the 8-hour 

ozone and PM2.5 NAAQS, EPA has an 

obligation to implement a Federal 

implementation plan (FIP) to address 

interstate transport no later than 24 

months after that finding, if the States 

fail to take appropriate action. Given 

this schedule for the FIP obligation, EPA 

believes that it is reasonable to require 

States to take action to meet the section 

110(a)(2)(D) obligation with respect to 

the significant contribution identified in 

today’s rule within no more than 18 

months. Such a schedule will allow 

States adequate time to develop 

submissions to meet this requirement 

and will afford EPA adequate time to 

review such submissions before the 

imposition of a FIP in lieu of a SIP, if 

necessary. 

Thus, EPA has concluded that States 

should submit SIPs to reduce interstate 

transport, as required by this final 

action, as expeditiously as practicable 

but no later than 18 months from 

today’s date. Such a schedule will 

provide both upwind and downwind 

States, and those States that are in both 

positions relative to other States, to 

develop SIPs that will facilitate 

expeditious attainment of the PM2.5 and 

the 8-hour ozone standards.

C. What Happens If a State Fails To 

Submit a Transport SIP or EPA 

Disapproves the Submitted SIP? 

1. Under What Circumstances Is EPA 

Required To Promulgate a FIP? 

Under section 110(c)(1), EPA is 

required to promulgate a FIP within 2 

years of: (1) finding that a State has 

failed to make a required submittal; or 

(2) finding that a submittal received 

does not satisfy the minimum 

completeness criteria established under 

section 110(k)(1)(A) (40 CFR part 51, 

appendix V); or (3) disapproving a SIP 

submittal in whole or in part. Section 

110(c)(1) mandates that EPA promulgate 

a FIP unless the States corrects the 

deficiency and EPA approves the SIP 

before the time EPA would promulgate 

the FIP. 

2. What Are the Completeness Criteria? 

Any SIP submittal that is made with 

respect to the final CAIR requirements 

first would be determined to be either 

incomplete or complete. A finding of 

completeness is not a determination that 

the submittal is approvable. Rather, it 

means the submittal is administratively 

and technically sufficient for EPA to 

proceed with its review to determine 

whether the submittal meets the 

statutory and regulatory requirements 

for approval. Under 40 CFR 51.123 and 

40 CFR 51.124 (the proposed new 

regulations for NOX and SO2 SIP 

requirements, respectively), a submittal, 

to be complete, must meet the criteria 

described in 40 CFR, part 51, appendix 

V, ‘‘Criteria for Determining the 

Completeness of Plan Submissions.’’

These criteria apply generally to SIP 

submissions. 

Under CAA section 110(k)(1) and 

section 1.2 of appendix V, EPA must 

notify States whether a submittal meets 

the requirements of appendix V within 

60 days of, but no later than 6 months 

after, EPA’s receipt of the submittal. If 

a completeness determination is not 

made within 6 months after submission, 

the submittal is deemed complete by 

operation of law. For rules submitted in 

response to the CAIR, EPA intends to 

make completeness determinations 

expeditiously. 

3. When Would EPA Promulgate the 

CAIR Transport FIP? 

The EPA views seriously its 

responsibility to address the issue of 

regional transport of PM2.5, ozone, and 

precursor emissions. Decreases in NOX

and SO2 emissions are needed in the 

States named in the CAIR to enable the 

downwind States to develop and 

implement plans to achieve the PM2.5

and 8-hour ozone NAAQS and provide 

clean air for their residents. Thus, EPA 

intends to promulgate the FIP shortly 

after the CAIR SIP submission deadline 

for States that fail to submit approvable 

SIPs in order to help assure that the 

downwind States realize the air quality 

benefits of regional NOX and SO2

reductions as soon as practicable. This 

is consistent with Congress’ intent that 

attainment occur in these downwind 

nonattainment areas ‘‘as expeditiously 

as practicable’’ (sections 181(a), 172(a)). 

To this end, EPA intends to propose the 

FIP prior to the SIP submission 

deadline. 

The FIP proposal would achieve the 

NOX and SO2 emissions reductions 

required under the CAIR by requiring 

EGUs in affected States to reduce 

emissions through participation in 

Federal NOX and SO2 cap and trade 

programs. The EPA intends to integrate 

these Federal trading programs with the 

model trading programs that States may 

choose to adopt to meet the CAIR. 

Although EPA would be proposing FIPs 

for all States affected by the CAIR, EPA 

will only issue a final FIP for those 

jurisdictions that fail to respond 

adequately to the CAIR. 

25270 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

120Other CAA provisions relevant to this final 

rule include section 172(c)(3) (provides that SIPs for 

nonattainment areas must include comprehensive, 

current inventory of actual emissions, including 

periodic revisions); section 182(a)(3)(A) (emissions 

inventories from ozone nonattainment areas); and 

section 187(a)(5) (emissions inventories from CO 

nonattainment areas).

The EPA’s goal is to have approvable 

SIPs that meet the requirements of the 

CAIR. We remain ready to work with 

the States to develop fully approvable 

SIPs, which would eliminate the need 

for EPA to promulgate a FIP. 

D. What Are the Emissions Reporting 

Requirements for States? 

The EPA believes that it is essential 

that achievement of the emissions 

reductions required by the CAIR be 

verified on a regular basis. Emission 

reporting is the principal mechanism to 

verify these reductions and to assure the 

downwind affected States and EPA that 

the ozone and PM2.5 transport problems 

are being mitigated as required by the 

rule. Therefore, the final rule establishes 

a small set of new emission reporting 

requirements applicable to States 

affected by the CAIR, covering certain 

emissions data not already required 

under existing emission reporting 

regulations. The rule language also 

removes a current emission reporting 

requirement related to the NOX SIP call, 

which we believe is not necessary, for 

reasons explained below. A number of 

other proposed changes in emission 

reporting requirements which would 

have affected States not subject to the 

final CAIR are not included in the final 

rule, for reasons explained below. We 

will repropose these other changes, with 

modifications, in a separate proposal to 

allow additional opportunity for public 

comment. 

1. Purpose and Authority 

Because we are consolidating and 

harmonizing the new emission reporting 

requirements promulgated today with 

two pre-existing sets of emission 

reporting requirements, we review here 

the purpose and authority for emission 

reporting requirements in general.

Emissions inventories are critical for 

the efforts of State, local, and Federal 

agencies to attain and maintain the 

NAAQS that EPA has established for 

criteria pollutants such as ozone, PM, 

and CO. Pursuant to its authority under 

sections 110 and 172 of the CAA, EPA 

has long required SIPs to provide for the 

submission by States to EPA of 

emissions inventories containing 

information regarding the emissions of 

criteria pollutants and their precursors 

(e.g., VOCs). The EPA codified these 

requirements in subpart Q of 40 CFR 

part 51, in 1979 and amended them in 

1987. 

The 1990 Amendments to the CAA 

revised many of the provisions of the 

CAA related to the attainment of the 

NAAQS and the protection of visibility 

in Class I areas. These revisions 

established new periodic emissions 

inventory requirements applicable to 

certain areas that were designated 

nonattainment for certain pollutants. 

For example, section 182(a)(3)(A) 

required States to submit an emissions 

inventory every 3 years for ozone 

nonattainment areas beginning in 1993. 

Similarly, section 187(a)(5) required 

States to submit an inventory every 3 

years for CO nonattainment areas. The 

EPA, however, did not immediately 

codify these statutory requirements in 

the CFR, but simply relied on the 

statutory language to implement them. 

In 1998, EPA promulgated the NOX

SIP call which requires the affected 

States and the District of Columbia to 

submit SIP revisions providing for NOX

reductions to reduce their adverse 

impact on downwind ozone 

nonattainment areas. (63 FR 57356, 

October 27, 1998). As part of that rule, 

codified in 40 CFR 51.122, EPA 

established emissions reporting 

requirements to be included in the SIP 

revisions required under that action. 

Another set of emissions reporting 

requirements, termed the Consolidated 

Emissions Reporting Rule (CERR), was 

promulgated by EPA in 2002, and is 

codified at 40 CFR part 51 subpart A. 

(67 FR 39602, June 10, 2002). These 

requirements replaced the requirements 

previously contained in subpart Q, 

expanding their geographic and 

pollutant coverages while simplifying 

them in other ways. 

The principal statutory authority for 

the emissions inventory reporting 

requirements outlined in this final rule 

is found in CAA section 110(a)(2)(F), 

which provides that SIPs must require 

‘‘as may be prescribed by the 

Administrator * * * (ii) periodic 

reports on the nature and amounts of 

emissions and emissions-related data 

from such sources.’’ Section 301(a) of 

the CAA provides authority for EPA to 

promulgate regulations under this 

provision.120

2. Pre-existing Emission Reporting 

Requirements 

As noted above, prior to this final 

rule, two sections of title 40 of the CFR 

contained emissions reporting 

requirements that are applicable to 

States: Subpart A of part 51 (the CERR) 

and section 51.122 in subpart G of part 

51 (the NOX SIP Call reporting 

requirements). 

Under the NOX SIP Call requirements 

in section 51.122, emissions of NOX for 

a defined 5-month ozone season (May 1 

through September 30) and for work 

weekday emissions for point, area and 

mobile sources that the State has 

subjected to emissions control to 

comply with the requirements of the 

NOX SIP Call, are required to be 

reported by the affected States to EPA 

every year. However, emissions of 

sources reporting directly to EPA as part 

of the NOX trading program are not 

required to be reported by the State to 

EPA every year. The affected States are 

also required to report ozone season 

emissions and typical summer daily 

emissions of NOX from all sources every 

third year (2002, 2005, etc.) and in 2007. 

This triennial reporting process does not 

have an exemption for sources 

participating in the emissions trading 

programs. Section 51.122 also requires 

that a number of data elements be 

reported for each source in addition to 

ozone season NOX emissions. These 

data elements describe certain of the 

source’s physical and operational 

parameters.

Emissions reporting under the NOX

SIP Call as first promulgated was 

required starting for the emissions 

reporting year 2002, the year prior to the 

start of the required emissions 

reductions. The reports are due to EPA 

on December 31 of the calendar year 

following the inventory year. For 

example, emissions from all sources and 

types in the 2002 ozone season were 

required to be reported on December 31, 

2003. However, because the Court 

which heard challenges to the NOX SIP 

Call delayed the implementation by 1 

year to 2004, no State was required to 

start reporting until the 2003 inventory 

year. The EPA promulgated a rule to 

subject Georgia and Missouri to the NOX

SIP Call with an implementation date of 

2007. (See 69 FR 21604, April 21, 2004.) 

We have recently proposed to stay the 

NOX SIP Call for Georgia (see 70 FR 

9897, March 1, 2005). Missouri’s 

emissions reporting begins with 2006. 

These emissions reporting requirements 

under the NOX SIP Call affect the 

District of Columbia and 18 of the 28 

States affected by the proposed CAIR. 

As noted above, the other set of preexisting emissions reporting 

requirements is codified at subpart A of 

part 51. Although entitled the 

Consolidated Emissions Reporting Rule 

(CERR), this rule left in place the 

separate § 51.122 for the NOX SIP Call 

reporting. The CERR requirements were 

aimed at obtaining emissions 

information to support a broader set of 

purposes under the CAA than were the 

reporting requirements under the NOX

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25271

121We used the term ‘‘non-point source’’ in the 

SNPR to refer to a stationary source that is treated 

for inventory purposes as part of an aggregated 

source category rather than as an individual facility. 

In the existing subpart A of part 51, such emissions 

sources are referred to as ‘‘area sources.’’ However, 

the term ‘‘area source’’ is used in section 112 of the 

CAA to indicate a non-major source of hazardous 

air pollutants, which could be a point source. As 

emissions inventory activities increasingly 

encompass both NAAQS-related pollutants and 

hazardous air pollutants, the differing uses of ‘‘area 

source’’ can cause confusion. Accordingly, EPA 

proposed to substitute the term ‘‘non-point source’’

for the term ‘‘area source’’ in subpart A, § 51.122, 

and the new § 51.125 to avoid confusion. We are 

not finalizing this change in terminology in today’s 

rule.

SIP Call. The CERR requirements apply 

to all States. 

Like the requirements under the NOX

SIP Call, the CERR requires reporting of 

all sources at 3-year intervals (2005, 

2008, etc.). It requires reporting of 

certain large sources every year. 

However, the required reporting date 

under the CERR is 5 months later than 

under the NOX SIP Call reporting 

requirements. Also, emissions must be 

reported for the whole year, for a typical 

day in winter, and a typical day in 

summer, but not for the 5-month ozone 

season as is required by the NOX SIP 

Call. Finally, the CERR and the NOX SIP 

Call differ in what non-emissions data 

elements must be reported. 

3. Summary of the Proposed Emissions 

Reporting Requirements 

On June 10, 2004, EPA published a 

SNPR (69 FR 32684) to EPA’s January 

30, 2004 proposal (69 FR 4566). The 

EPA’s main objective with respect to 

emissions reporting was to add limited 

new requirements for emissions reports 

to serve the additional purposes of 

verifying the CAIR-required emissions 

reductions. The SNPR also sought to 

harmonize the CERR and NOX SIP Call 

reporting requirements with respect to 

specific data elements and consolidate 

them entirely in subpart A, and to 

reduce and simplify the reporting 

requirements in several ways. These 

latter changes were proposed to be 

applicable to all States, not just those 

affected by the CAIR emissions 

reduction requirements. The major 

changes included in the SNPR are 

described below. 

Amendments were proposed to 

subpart A, which contains § 51.1 

through 51.45 and an appendix, and to 

§ 51.122. We also proposed to add a new 

§ 51.125. 

• In § 51.122, the NOX SIP Call 

provisions, we proposed to abolish 

certain requirements entirely, and to 

replace certain requirements with a 

cross reference to subpart A so that 

detailed lists of required data elements 

appeared only in subpart A. As 

proposed, § 51.122 would then have 

specified what pollutants, sources, and 

time periods the States subject to the 

NOX SIP Call must report and when, but 

would no longer have listed the detailed 

data elements required for those reports. 

• The proposed new § 51.125 would 

have been functionally parallel to 

§ 51.122, specifying all the pollutants, 

sources, and time periods the States 

subject to the proposed CAIR must 

report and when, referencing subpart A 

for the detailed data elements required. 

• The proposed amended subpart A 

would have listed the detailed data 

elements for all three reporting 

programs (CERR, NOX SIP Call, and 

CAIR) as well as provided information 

on submittal procedures, definitions, 

and other generally applicable 

provisions.

Taken together, the pre-existing 

emissions reporting requirements under 

the NOX SIP Call and CERR were 

already rather comprehensive in terms 

of the States covered and the 

information required. Therefore, the 

practical impact of the proposed 

changes would have imposed only three 

new requirements. 

First, in Arkansas, Florida, Iowa, 

Louisiana, Mississippi, and Wisconsin 

for which we proposed and are 

finalizing a finding of significant 

contribution to ozone nonattainment in 

another State but which were not among 

the 22 States already subject to the NOX

SIP Call, the required emissions 

reporting would be expanded to match 

those of the 22 States. The proposed 

change would require that they report 

NOX emissions during the 5-month 

ozone season and for a typical summer 

day, in addition to the existing 

requirement for reporting emissions for 

the full year. We proposed that this new 

requirement begin with the triennial 

inventory year prior to the CAIR 

implementation date. This would be the 

2008 inventory year, the report for 

which would be due to EPA by June 1, 

2010. 

Second, under the existing CERR, 

yearly reporting is required only for 

sources whose emissions exceed 

specified amounts. The SNPR proposed 

that the 28 States and the District of 

Columbia subject to the CAIR for 

reasons of PM2.5 must report to EPA 

each year a set of specified data 

elements for all sources subject to new 

controls adopted specifically to meet the 

CAIR requirements related to PM2.5, 

unless the sources participate in an 

EPA-administered emissions trading 

program. We proposed that this new 

requirement begin with the 2009 

inventory year, the report for which will 

be due to EPA by June 1, 2011. This new 

requirement would have no effect on 

States that fully comply with the CAIR 

by requiring their EGUs to participate in 

the CAIR model cap and trade programs. 

Third, in all States, we proposed to 

expand the definition of what sources 

must report in point source format, so 

that fewer sources would be included in 

non-point source emissions.121 We 

proposed to base the requirement for 

point source format reporting on 

whether the source is a major source 

under 40 CFR part 70 for the pollutants 

for which reporting is required, i.e., for 

CO, VOC, NOX, SO2, PM2.5, PM10 and 

ammonia but without regard to 

emissions of hazardous air pollutants.

A number of other proposed changes 

would have reduced reporting 

requirements on States or provided 

them with additional options. Two of 

the proposed changes in this category 

are of special note in understanding the 

final requirements of today’s rule. (The 

remainder of these changes were 

explained in the SNPR at 69 FR 32697.) 

• The NOX SIP Call rule requires the 

affected States to submit emissions 

inventory reports for a given ozone 

season to EPA by December 31 of the 

following year. The CERR requires 

similar but not identical reports from all 

States by the following June 1, five 

months later. We proposed to move the 

December 31 reporting requirement to 

the following June 1, the more generally 

applicable submission date affecting all 

50 States. We asked for comment on 

whether allowing this 5-month delay is 

consistent with the air quality goals 

served by the emissions reporting 

requirements. However, we also asked 

for comment on the alternative of 

moving forward to December 31 all or 

part of the June 1 reporting for all 50 

States. In particular, we solicited 

comment on requiring that point 

sources be reported on December 31 and 

other sources on June 1.

• We also proposed to eliminate a 

requirement of the NOX SIP Call for a 

special all-sources report by affected 

States for the year 2007, due December 

31, 2008. 

4. Summary of Comments Received and 

EPA’s Responses 

A number of commenters objected to 

the 45-day comment period as being too 

short to allow for full understanding of 

and comment on the emissions 

reporting changes that EPA had 

proposed. With respect to this issue, 

EPA believes that the comment period 

was sufficient for those proposed 

changes that would affect the States 

subject to the emissions reductions 

25272 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

requirements of the CAIR and that are 

specifically directed at ensuring the 

effectiveness of the CAIR, namely: (1) 

The requirement for six more States to 

report ozone season emissions, and (2) 

the requirement for all subject States to 

report annual emissions from controlled 

sources every year if those sources are 

not participating in the emission trading 

programs. These proposed changes are 

easy to understand on their face, and 

also have close precedents in the NOX

SIP Call. Moreover, the States affected 

by these proposed reporting 

requirements were identified as being 

subject to the proposed emissions 

reduction requirements of the CAIR in 

the original NPR, and thus they knew to 

be alert to the contents of the SNPR. We 

also consider the comment period 

sufficient with respect to two other 

specific elements of the proposal, 

namely (3) the proposal to eliminate the 

2007 inventory reporting requirement 

under the NOX SIP Call and (4) the 

proposal to change the reporting date for 

the NOX SIP Call from December 31 (12 

months after the end of the reported 

year) to June 1 (17 months after the end 

of the reported year). These were also 

readily understood proposals, and the 

States affected by them were among 

those initially identified as subject to 

the CAIR itself. A number of substantive 

comments were received on these four 

proposed changes. Therefore, we have 

concluded that it is appropriate to 

consider the substantive comments that 

were received on these four elements of 

the SNPR, and to take final action on 

them. The disposition of the remaining 

elements of the SNPR is discussed 

further below. 

The EPA received one comment from 

the Mississippi Department of 

Environmental Quality on the proposed 

requirement that Mississippi and five 

other States report ozone season 

emissions. Mississippi disagreed that 

they should be included with the other 

States subject to the CAIR provisions, 

including the emissions reporting 

provisions. The EPA has concluded that 

the analysis performed to support CAIR 

and discussed earlier in this preamble 

amply demonstrates that Mississippi 

should be included in the CAIR and 

subject to the CAIR emissions reporting 

requirements. 

We did not receive comments 

specifically on the proposal to require 

States to report annual emissions every 

year from sources controlled to comply 

with the CAIR, if those sources are not 

participating in the emission trading 

programs operated by EPA. While we 

expect the number of such sources to be 

small if not zero, we continue to believe 

that tracking their emissions from year 

to year is appropriate, and we are 

finalizing this requirement. Since the 

CERR already contains a requirement for 

every-year reporting of emissions from 

point sources above certain emission 

thresholds, this requirement will have 

an incremental impact only if States 

choose to control fairly small point 

sources or nonpoint or mobile sources 

as part of their plan for meeting the 

CAIR requirements. 

The EPA received several comments 

regarding the elimination of the NOX

SIP Call special all-sources 2007 

emissions inventory. These comments 

all favored the elimination of the 2007 

emissions inventory, which EPA is 

promulgating in today’s rule. We would 

like to clarify that the NOX SIP Call 

contained no requirement that any State 

make a retrospective demonstration that 

actual statewide emissions of NOX were 

within any limit. The requirement for 

the 2007 inventory was for the purpose 

of program evaluation by EPA. As 

explained in the SNPR, we believe that 

in light of the data on 2007 emissions 

that will be available from the NOX

trading program and the further 

reductions in NOX required by the 

CAIR, the 2007 inventory submissions 

from the States are not needed for this 

purpose.

The EPA also proposed to harmonize 

the report due dates for the NOX SIP 

Call, currently 12 months after the end 

of the reported year, and for the CERR, 

currently 17 months after the end of the 

reported year. The EPA proposed to 

harmonize the dates for both at 17 

months, but asked for comments on a 

12-month due date. Several comments 

were received, all favoring harmonizing 

the report due date at 17 months. While 

we continue to believe in the efficiency 

advantage of harmonized submission 

date requirements, we are not finalizing 

this change. The EPA has reconsidered 

this part of the proposed emissions 

reporting requirements and believes that 

it may be in the interest of the public 

to move in the direction of shortening 

the emissions reporting cycle for all 

three reporting requirements (CERR, 

NOX SIP Call, and CAIR), rather than 

accepting the longer CERR cycle for all 

three reporting requirements. In today’s 

final rule, we are retaining the 12-month 

submission date requirement of the 

original NOX SIP Call for the States 

already subject to it. For the six States 

that are newly subject to reporting 

ozone season NOX emissions and for the 

new requirement for every-year 

reporting by sources controlled to meet 

the CAIR requirements for SO2 and NOX

annual emissions reductions but not 

included in the trading programs, the 

required reporting date for States will be 

June 1, 17 months after the end of the 

reported year, as was proposed. We will 

address reporting deadlines 

comprehensively in a separate NPR 

which will propose a unified, but 

shorter period of time to report to EPA. 

This separate notice will allow for more 

public comment on the reporting cycle. 

The dual approach to reporting due 

dates retained in today’s rule will be 

combined into unified due dates and 

will be influenced by comments 

received in response to our proposal 

when the separate rulemaking is 

completed. 

Regarding elements of the proposed 

requirements beyond these four, i.e., the 

requirements that would have affected 

States not subjected to the CAIR 

emissions reduction requirements as 

well as CAIR States, many commenters 

said that EPA should not have included 

changes to national emissions reporting 

requirements in a proposed rule placing 

emissions reduction requirements on 

only certain States. Commenters also 

questioned whether EPA had given 

adequate time for comment on the more 

detailed revisions in required data 

elements, definitions, etc. Substantively, 

many commenters supported some or 

all of the proposed changes, but some 

commenters objected to some of them. 

The EPA has considered these 

comments. Without conceding EPA’s 

legal authority to include these 

provisions in the final rule in light of 

the history of proposal, public hearing, 

and comment period, EPA has—in an 

abundance of caution—decided to omit 

these provisions from today’s rule (see 

section VIII.D.5 Summary of the 

Emissions Reporting Requirements 

below for the changes which are being 

finalized today). We will repropose 

them, with modifications, in a separate 

NPR to allow additional opportunity for 

public comment by all affected States 

and other parties. 

5. Summary of the Emissions Reporting 

Requirements 

As a result of the comments received, 

EPA has revised the emissions reporting 

requirements of today’s rule by limiting 

new requirements to the ones where 

sufficient notice and opportunity for 

comment was clearly given in the June 

10, 2004, SNPR and that either: (1) Are 

necessary for the monitoring of the 

implementation of the emissions 

reduction requirements of the CAIR, or 

(2) are changes in reporting under the 

NOX SIP Call linked to the CAIR. Three 

specific emissions reporting provisions 

that change the pre-existing 

requirements are included in today’s 

rule.

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25273

122 40 CFR 51.122 is also amended: (1) to remove 

a reference to now-obsolete electronic data 

reporting processes (a ‘‘housekeeping’’ deletion that 

was specifically included in the proposed rule text 

with the SNPR), and (2) to make a minor technical 

correction to properly indicate which of the latitude 

versus longitude data elements corresponds to the 

x-coordinate and which to the y-coordinate (a 

correction that was implicitly proposed in the 

SNPR in that 51.122 was proposed to refer to 51 

subpart A for all its data element descriptions).

1. Alabama, Arkansas, Connecticut, 

Delaware, Florida, Illinois, Indiana, 

Iowa, Kentucky, Louisiana, Maryland, 

Massachusetts, Michigan, Mississippi, 

Missouri, New Jersey, New York, North 

Carolina, Ohio, Pennsylvania, South 

Carolina, Tennessee, Virginia, West 

Virginia, Wisconsin and the District of 

Columbia, which are subject to the CAIR 

for reasons of ozone, are made subject 

to emission reporting requirements for 

NOX that are very similar to the existing 

requirements of the NOX SIP Call, 

which already affects all but six of these 

States. For these six States (Arkansas, 

Florida, Iowa, Louisiana, Mississippi 

and Wisconsin) a new requirement is 

that they report NOX emissions during 

the 5-month ozone season from all 

sources every three years, in addition to 

reporting emissions for the full year and 

for a summer day as was already 

required. This new requirement begins 

with the triennial inventory year 2008. 

For all the listed States, a new 

requirement is to report to EPA for 2009 

and each year thereafter the ozoneseason and summer day NOX emissions, 

plus a set of specified other data 

elements, for all sources subject to new 

controls adopted specifically to meet the 

CAIR requirements related to ozone, 

unless the sources participate in an 

EPA-administered emissions trading 

program. These reports will be due June 

1 of the second year following the end 

of the reported year, i.e., 17 months after 

the end of the reported year. The 

existing CERR includes several other 

reporting requirements which in 

conjunction with this new requirement 

will meet the needs for monitoring the 

implementation of required NOX

emissions reductions. 

2. Alabama, Florida, Georgia, Illinois, 

Indiana, Iowa, Kentucky, Louisiana, 

Maryland, Michigan, Minnesota, 

Mississippi, Missouri, New York, North 

Carolina, Ohio, Pennsylvania, South 

Carolina, Tennessee, Texas, Virginia, 

West Virginia, Wisconsin and the 

District of Columbia, which are subject 

to the CAIR for reasons of PM2.5, must 

report to EPA each year annual NOX and 

SO2 emissions, plus a set of specified 

other data elements, for all sources 

subject to new controls adopted 

specifically to meet the CAIR 

requirements related to PM2.5, unless the 

sources participate in an EPAadministered emissions trading 

program. Previously, these states may 

have been required to report these 

sources only every third year, 

depending on their size. The existing 

CERR includes several other reporting 

requirements which in conjunction with 

this new requirement will meet the 

needs for monitoring the 

implementation of required NOX and 

SO2 emissions reductions. 

3. The EPA has determined that the 

requirement in the NOX SIP Call for a 

special all-sources report by affected 

States for the year 2007, due December 

31, 2008, is no longer needed to 

administer provisions in the NOX SIP 

Call. Accordingly, EPA is eliminating 

this requirement in today’s rule. 

The final rule accomplishes these 

changes by making minimal changes to 

the existing provisions of 40 CFR part 

51. Subpart A, which contains the CERR 

requirements, is not amended at all. 40 

CFR 51.122, the section containing 

emission inventory reporting 

requirements for the NOX SIP Call, is 

substantively amended only to delete 

the requirement for the 2007 inventory 

report.122 A new section 40 CFR 51.125 

is added to contain the two new 

emission inventory reporting 

requirements specifically related to the 

new CAIR requirements for emissions 

reductions, regarding ozone-season 

emissions of NOX and every-year 

reporting of NOX and SO2 emissions 

from all sources controlled but not 

participating in the EPA trading 

programs. The new 40 CFR 51.125 refers 

to 40 CFR subpart A for the other 

specific data elements that must be 

reported.

VIII. Model NOX and SO2 Cap and 

Trade Programs 

A. What Is the Overall Structure of the 

Model NOX and SO2 Cap and Trade 

Programs? 

The EPA is finalizing model rules for 

the CAIR annual NOX, CAIR ozoneseason NOX, and SO2 trading programs 

that States can use to meet the emission 

reduction requirements in the CAIR. 

These rules are designed to be 

referenced by States in State 

rulemaking. State use of the model cap 

and trade rules helps to ensure 

consistency between the State programs, 

which is necessary for the market 

aspects of the regional trading program 

to function properly. It also allows the 

CAIR Program to build on the successful 

Acid Rain Program. Consistency in the 

CAIR requirements from State-to-State 

benefits the affected sources, as well as 

EPA, which administers the program on 

behalf of States. 

This section focuses on the structure 

which maintains the existing NOX SIP 

Call rules (in part 96, subparts A 

through J) while adding parallel rules 

for the CAIR annual NOX (in subparts 

AA through II), CAIR SO2 (in subparts 

AAA through III), and the CAIR ozoneseason NOX (in subparts AAAA through 

IIII) of the model rules. Commenters 

generally supported the proposed 

structure of the model rules, as well as 

the use of the cap and trade approach, 

which are maintained in the final rules. 

Later sections of today’s rule discuss 

specific aspects of the model rules that 

have been modified or maintained in 

response to comment. 

The EPA designed the model rules to 

parallel the NOX SIP Call model trading 

rules (part 96) and to coordinate with 

the Acid Rain Program. Mirroring the 

structure of existing part 96 in the final 

CAIR NOX and SO2 model rules will 

ease the transition to the CAIR rules as 

many States and sources are already 

familiar with the layout of the NOX SIP 

Call rule. In addition, because the EPA 

proposed new CAIR model trading 

rules—separate from the existing NOX

SIP Call model rule in part 96—States 

can continue to reference part 96 

(subparts A through J) through 2008. 

The CAIR ozone-season NOX cap and 

trade program that the EPA has 

included in today’s final rule is 

intended for use by CAIR ozone-affected 

sources as well as those subject to the 

NOX SIP Call in 2009 and beyond. 

Those States that wish to use an EPAadministered, ozone-season cap and 

trade program to achieve the reductions 

mandated by the CAIR or the NOX SIP 

Call, must use the CAIR ozone-season 

NOX model rule (subparts AAAA 

through IIII) in 2009 and beyond. 

The model rules rely on the detailed 

unit-level emissions monitoring and 

reporting procedures of part 75 and 

consistent allowance management 

practices. (Note that full CAIR-related 

SIP requirements, i.e., part 51, are 

discussed in section VII of today’s 

preamble.) Additionally, section IX.B of 

today’s preamble discusses the final 

revisions to parts 72 through 77 in order 

to, among other things, facilitate the 

interaction of the title IV Acid Rain 

Program’s SO2 cap and trade provisions 

and those of the CAIR SO2 trading 

program. 

Road Map of Model Cap and Trade 

Rules 

The following is a brief ‘‘road map’’

to the final CAIR NOX and SO2 cap and 

trade programs. Please refer to the 

detailed discussions of the CAIR 

25274 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

123Rhode Island (RI) is the only State currently 

participating in the NOX SIP Call cap and trade 

program that is not affected by today’s ozone 

finding. As is explained in section IX, RI may join 

the CAIR ozone-season trading program as a means 

of satisfying its NOX SIP Call requirements.

124The 200,000 total includes the share of the 

CSP that DE and NJ would receive if the EPA 

finalizes a parallel rule finding that they are 

significant contributors for PM2.5.

125Compliance with the title IV Acid Rain 

Program will be determined separately from CAIR 

compliance.

programmatic elements throughout 

today’s rule for further information on 

each aspect. 

State Participation 

• States have flexibility to achieve 

emissions reductions however they 

chose, including developing and 

implementing their own trading 

program. 

• States may elect to participate in an 

EPA-managed cap and trade program. 

To participate, a State must adopt the 

model cap and trade rules finalized in 

this section of today’s rule with 

flexibility to modify sections regarding 

NOX allocations and whether to include 

individual unit opt-in provisions. 

• States may participate in EPAmanaged cap and trade programs for 

either the annual NOX, the ozone-season 

NOX, the SO2, or any combination. The 

State can only choose to participate in 

the EPA-administered, CAIR cap and 

trade program(s) that is (are) relevant to 

their finding(s). 

• The annual NOX model rule is to be 

used by only those States that are 

affected by the CAIR PM2.5 finding. 

• The ozone-season NOX model rule 

is designed to be used by those States 

that are affected by the CAIR ozone 

finding as well as take the place of the 

NOX SIP Call requirements.123 The 

CAIR ozone-season NOX program will 

be the only ozone-season NOX program 

that EPA will administer. Because EPA 

will no longer run a NOX SIP Call 

trading program, States may include 

their NOX SIP Call trading sources if 

they adopt the EPA-administered CAIR 

ozone-season NOX program.

• The SO2 model rule is designed to 

satisfy the ongoing statutory 

requirements of the title IV Acid Rain 

SO2 cap and trade program—with 

sequential compliance with title IV and 

the CAIR—for sources in the CAIR 

region that are affected by both the Acid 

Rain Program and the CAIR. 

Trading Sources 

• States must achieve all of the 

mandated emission reductions from 

EGUs to participate in EPA-managed 

cap and trade programs. States may 

include other NOX SIP Call trading 

sources in the ozone-season CAIR NOX

cap and trade program and still 

participate in EPA-managed cap and 

trade programs. 

• States may participate in EPAmanaged cap and trade programs 

whether or not they adopt the optional 

individual opt-in provisions of the 

model rule. However, if the State 

chooses to allow individual sources to 

opt-in, the opt-in requirements must 

reflect the requirements of the model 

rule. 

Emission Allowances 

• The CAIR annual NOX cap and 

trade program will rely upon CAIR 

annual NOX allowances allocated by the 

States. The NOX SIP Call allowances 

and CAIR ozone-season NOX allowances 

cannot be used for compliance with the 

annual CAIR reduction requirement. 

(Note that allowances from the 

Compliance Supplement Pool (CSP) will 

be CAIR annual NOX allowances.) 

• The CAIR ozone-season NOX cap 

and trade program will rely upon CAIR 

ozone-season NOX allowances allocated 

by the States. In addition, pre-2009 NOX

SIP Call allowances can be banked into 

the program and used by CAIR-affected 

sources for compliance with the CAIR 

ozone-season NOX program. The NOX

SIP Call allowances of vintages 2009 

and later can not be used for compliance 

with any EPA-administered cap and 

trade programs. 

• The CAIR SO2 cap and trade 

program will rely upon title IV SO2

allowances but may also include 

additional CAIR SO2 allowances, should 

a State that allows an individual unit 

opt-in mechanism provide CAIR SO2

allowwances to an opt-in source. Pre2010 title IV SO2 allowances can be 

used for compliance with the CAIR. 

• Sulfur dioxide reductions are 

achieved by requiring sources to retire 

more than one allowance for each ton of 

SO2 emissions. The emission value of an 

SO2 allowance is independent of the 

year in which it is used, but is based 

upon its vintage (i.e., the year in which 

the allowance is issued). Sulfur dioxide 

allowances of vintage 2009 and earlier 

offset one ton of SO2 emissions. 

Vintages 2010 through 2014 offset 0.5 

tons of emissions. And, vintages 2015 

and beyond offset 0.35 tons of 

emissions. 

Allocation of Allowances to Sources 

• For SO2 allowances, sources have 

already received allowances through 

title IV. 

• NOX allowances (for both the 

annual and ozone-season programs) will 

be allocated based upon the State’s 

chosen allocation methodology. The 

EPA’s model NOX rules have provided 

an example allocation, complete with 

regulatory text, that may be used by 

State’s or replaced by text that 

implements a States alternative 

allocation methodology. 

Compliance Supplement Pool (CSP) 

• Each State will have a share of the 

CSP that is comprised of 200,000 124

CAIR annual NOX allowances of vintage 

year 2009. The State may distribute the 

CSP allowances based upon the criteria, 

found in the SIP Approvability section 

of today’s rule, for early reductions and 

need.

Emission Monitoring and Reporting by 

Sources 

• Sources monitor and report their 

emissions using part 75. This includes 

individual sources that opt-in to the 

program. 

• Source information management, 

emissions data reporting, and allowance 

trading is done through on-line systems 

similar to those currently used for the 

Acid Rain SO2 and NOX SIP Call 

Programs. 

• Emission monitoring and reporting 

for both the CAIR annual and ozoneseason NOX cap and trade programs will 

use part 75. 

Compliance and Penalties 

• Compliance for the annual and 

ozone-season NOX cap and trade 

programs, as well as the SO2 program, 

will be determined separately.125

• For the NOX and SO2 cap and trade 

programs, any source found to have 

excess emissions must: (1) Surrender 

allowances sufficient to offset the excess 

emissions; and, (2) surrender 

allowances from the next control period 

equal to three times the excess 

emissions. 

Comments Regarding the Use of a Cap 

and Trade Approach and the Proposed 

Structure

Commenters overwhelmingly 

supported the use of a cap and trade 

approach and the overall framework of 

the model rules to achieve the mandated 

emissions reductions. Some supported 

the use of cap and trade for achieving 

regional emissions reductions but noted 

the need to have additional measures 

that ensure that emission reductions 

take place in nonattainment areas. This 

is in line with the EPA’s strategy of 

reducing transported SO2 and NOX

through a regionwide cap and trade 

approach and encouraging States to take 

complementary measures to address 

their particular, persistent 

nonattainment issues. (Note that 

comments on specific mechanisms 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25275

within the cap and trade program are 

discussed in the topic-specific sections 

that follow.) 

B. What Is the Process for States To 

Adopt the Model Cap and Trade 

Programs and How Will It Interact With 

Existing Programs? 

1. Adopting the Model Cap and Trade 

Programs 

States may choose to participate in 

the EPA-administered cap and trade 

programs, which are a fully approvable 

control strategy for achieving all of the 

emissions reductions required under 

today’s rulemaking in a highly costeffective manner. States may simply 

reference the model rules in their State 

rules and, thereby, comply with the 

requirements for statewide budget 

demonstrations detailed in section VII.B 

of today’s preamble. Affected States for 

both PM2.5 and ozone can adopt the 

annual NOX and SO2 cap and trade 

programs in part 96, subparts AA 

through II, part 96 subparts AAA 

through III, and AAAA through IIII. 

States with ozone-season only CAIR 

requirements (i.e., Arkansas, 

Connecticut, Delaware, Massachusetts, 

and New Jersey) can adopt the ozoneseason CAIR NOX program (subparts 

AAAA through IIII). Part 96 subparts 

AA through II and AAA through III can 

be used by States that are affected for 

only PM2.5 (i.e., Georgia, Minnesota, and 

Texas). States that elect to achieve the 

required reductions by regulating other 

sources or using other approaches will 

follow alternate State requirements, also 

described in section VII.B of today’s 

preamble. 

As proposed, EPA is requiring States 

that wish to participate in the EPAmanaged cap and trade program to use 

the model rule to ensure that all 

participating sources, regardless of 

which State in the CAIR region they are 

located, are subject to the same trading 

and allowance holding requirements. 

Further, requiring States to use the 

complete model rule provides for 

accurate, certain, and consistent 

quantification of emissions. Because 

emissions quantification is the basis for 

applying the emissions authorization 

provided by each allowance and 

emissions authorizations (in the form of 

allowances) are the valuable commodity 

traded in the market, the emissions 

quantification requirements of the 

model rule are necessary to maintain the 

integrity of the cap and trade approach 

of the program and therefore, to ensure 

that the environmental goals of the 

program are met.

For States Electing To Participate in the 

EPA-Administered Ozone-Season CAIR 

NOX Cap and Trade Program 

States that wish to achieve their CAIR 

ozone-season requirements through an 

EPA-administered ozone-season NOX

cap and trade program will adopt the 

CAIR model rule in subparts AAAA 

through IIII. (Note that the EPAadministered annual NOX CAIR cap and 

trade program is independent of ozoneseason CAIR NOX model rule.) Because 

EPA will no longer administer the 

trading program for the NOX SIP Call, 

States that wish to continue to meet 

their NOX SIP Call obligations through 

an EPA-administered cap and trade 

program will also adopt the CAIR 

ozone-season model rule. NOX SIP Call 

States will ‘‘sun set’’ their NOX SIP Call 

rules for sources that will move into the 

CAIR NOX ozone-season program. Part 

96, sections A–J (i.e., the NOX SIP Call 

trading rule) will continue to be 

available for the NOX SIP Call and will 

not be removed for the CAIR. The CAIR 

model rules specifically address how 

NOX SIP Call allowances carry forward 

into the CAIR NOX ozone-season 

program. (Section IX.A provides 

additional discussion of interactions 

between the CAIR and the NOX SIP 

Call). 

For States Electing To Participate in the 

EPA-Administered Annual NOX Cap 

and Trade Program 

States that are PM2.5 affected and wish 

to participate in an EPA-administered 

annual NOX cap and trade program will 

adopt the CAIR model rule in subparts 

AA through II. States may participate by 

either adopting the model rule 

provisions by reference or codifying the 

model rule in their State regulations. 

For States Electing To Participate in the 

EPA-Administered SO2 Cap and Trade 

Program 

States may simply adopt new 

provisions, whether by incorporating by 

reference the CAIR SO2 cap and Trade 

rule (part 96, subparts AAA through III) 

or codifying the provisions of the CAIR 

SO2 cap and trade rules, in order to 

participate in the EPA-administered SO2

cap and trade program. The CAIR SO2

model rule works in conjunction with 

the Acid Rain Program provisions, 

which are implemented at the Federal 

level and will stay in place. Today’s 

action also finalizes some revisions to 

the Acid Rain Program (i.e., parts 72, 73, 

74, 75, and 78). (Section IX.B of today’s 

preamble provides additional 

discussion of interactions between the 

CAIR and the Acid Rain Program and 

changes to the Acid Rain Program). 

Comments Regarding the Process for 

Adopting the Model Rules 

Commenters supported EPA’s 

proposed process and emphasized the 

importance of workable model rules, 

because States with limited resources 

are likely to incorporate them by 

reference or heavily rely on them as the 

basis for State rules. 

2. Flexibility in Adopting Model Cap 

and Trade Rules

It is important to have consistency on 

a State-to-State basis with the basic 

requirements of the cap and trade 

approach when implementing a multiState cap and trade program. Such 

consistency ensures the: Preservation of 

the integrity of the cap and trade 

approach so that the required emissions 

reductions are achieved; smooth and 

efficient operation of the trading market 

and infrastructure across the multi-State 

CAIR region so that compliance and 

administrative costs are minimized; and 

equitable treatment of owners and 

operators of regulated sources. However, 

EPA believes that some limited 

differences are possible without 

jeopardizing the environmental and 

other goals of the program. Therefore, 

the final rule allows States to modify the 

model rule language to best suit their 

unique circumstances in a few, specific 

areas. 

First, States have the flexibility to 

include, as full trading partners, all 

trading sources affected by the NOX SIP 

Call in the ozone-season CAIR NOX cap 

and trade program. This is an outgrowth 

of the development of the CAIR ozoneseason NOX program, which will be the 

only ozone-season NOX cap and trade 

program administered by EPA. 

In addition, States may develop their 

own NOX allocations methodologies, 

provided allocation information is 

submitted to EPA in the required 

timeframe. (Section VIII.D of today’s 

preamble discusses unit-level 

allocations and the related comments in 

greater detail. This includes a 

discussion of the provisions establishing 

the advance notice States must provide 

for unit-by-unit allocations). 

Lastly, States using the model cap and 

trade rules may elect to include 

provisions that allow individual units to 

‘‘opt-in’’ to the cap and trade programs. 

States that wish to include this 

mechanism must adopt provisions 

discussed in section VIII.G of today’s 

rulemaking. Adopting the individual 

unit opt-in provisions, which would 

allow non-EGUs that meet the opt-in 

requirements to enter into the EPAmanaged cap and trade programs, does 

not preclude a State from participating 

25276 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

126For example, certain cogeneration units and 

new units 25 MW or less that burn only clean fuel 

are exempt from the Acid Rain Program.

in the EPA-administered cap and trade 

programs. 

C. What Sources Are Affected Under the 

Model Cap and Trade Rules? 

In the January 2004 NPR, EPA 

proposed a method for developing 

budgets that assumed reductions only 

from EGUs. Electric Generating Units 

were defined as: Fossil fuel-fired, noncogeneration EGUs serving a generator 

with a nameplate capacity of greater 

than 25 MWe; and fossil fuel-fired 

cogeneration EGUs meeting certain 

criteria (referred to as the ‘‘1⁄3 potential 

electric output capacity criteria’’). In the 

SNPR, we proposed model cap and 

trade rules that applied to the same 

categories of sources. We are finalizing 

the nameplate capacity cut-off that we 

proposed in the NPR for developing 

budgets and that we proposed in the 

SNPR for the applicability of the model 

trading rules. We are also finalizing the 

‘‘fossil fuel-fired’’ definition and the 1⁄3

electric output capacity criteria that 

were proposed. The actual rule language 

in the SNPR describing the sources to 

which the model rules apply is being 

slightly revised to be clearer in response 

to some comments that the proposed 

language was not clear. 

1. 25 MW Cut-Off 

The EPA is retaining the 25 MW cutoff for EGUs for budget and model rule 

purposes. The EPA believes it is 

reasonable to assume no further control 

of air emissions from smaller EGUs. 

Available air emissions data indicate 

that the collective emissions from small 

EGUs are relatively small and that 

further regulating their emissions would 

be burdensome, to both the regulated 

community and regulators, given the 

relatively large number of such units. 

For example, NOX and SO2 emissions 

from EGUs of 25 MW or less in the CAIR 

region represent approximately one 

percent and two percent of total NOX

and SO2 emissions from EGUs, 

respectively. There are over 4000 EGUs 

of 25 MW or less in the CAIR region. 

Consequently, EPA believes that 

administrative actions to control this 

large group with small emissions would 

be inordinate and thus does not believe 

these small units should be included. 

This approach of using a 25 MW cut-off 

for EGUs is consistent with existing SO2

and NOX cap and trade programs such 

as the NOX SIP Call (where existing and 

new EGUs at or under this cut-off are, 

for similar reasons, not required to be 

included) and the Acid Rain Program 

(where this cut-off is applied to existing 

units and to new units combusting clean 

fuel). Also, EPA’s New Source 

Performance Standards use an 

applicability threshold of approximately 

25 MW under subpart Da. 

One commenter suggested a plantwide cut-off of 250 MW. This 

commenter suggested that including 

units between 25 and 250 MW would 

cause these units to shutdown but failed 

to provide any analysis to support its 

claim. Such a cut-off would be 

inconsistent with other existing SO2 and 

NOX cap and trade programs as noted 

above. The EPA estimates that 

approximately 1⁄3 of the SO2 reductions, 

and 30 percent of the NOX reductions, 

required under today’s rule come from 

plants between 25 MW and 250 MW. 

Our modeling shows that some units 

below 250 MW will put on controls as 

part of our highly cost-effective set of 

control actions. The units also have the 

option to coal-switch, alter dispatch, 

and/or purchase allowances.

Another commenter suggested that, in 

lieu of the language proposed in the 

SNPR, EPA adopt a definition for EGU 

that, according to the commenter, is the 

Acid Rain Program’s definition of 

affected utility. The commenter stated 

that the Acid Rain definition of EGU is 

‘‘all fossil fuel-fired units with a 

nameplate capacity greater than 25 MW 

supplying more than 1⁄3 of potential 

electrical output to the grid.’’ However, 

the commenter misstated the Acid Rain 

definition and confused the Acid Rain 

applicability provisions concerning 

utility units in general with those 

provisions concerning cogeneration 

units in particular. The Acid Rain 

Program covers, with certain 

exceptions,126 all existing fossil fuelfired units greater than 25 MW that 

produce any electricity for sale; and 

new fossil fuel-fired units that produce 

any electricity for sale. The language 

referenced by the commenter 

concerning potential electrical output 

applies, in the Acid Rain Program, only 

to cogeneration units, not all fossil fuelfired units. For non-cogeneration units, 

there is no exemption from Acid Rain 

Program requirements based on the unit 

selling a ‘‘small’’ amount of electricity 

for sale. The provisions in the NPR and 

the SNPR concerning cogeneration units 

are discussed below.

2. Definition of Fossil Fuel-Fired 

The EPA is finalizing the proposed 

definition of fossil fuel-fired, i.e., where 

any amount of fossil fuel is used at any 

time. This is the same definition that is 

used in the Acid Rain Program. One 

commenter suggested that the proposed 

definition is too broad and that EPA 

should use in the CAIR Program the 

same definition that is used in the NOX

SIP Call, i.e., where a unit uses fossil 

fuel for at least 50 percent of its annual 

heat input during a specified period. 

The same commenter also proposed 

excluding large wood-fired boilers and 

black liquor recovery furnaces. The 

commenter’s definition would result in 

units already subject to the Acid Rain 

Program in a given State being excluded 

from the CAIR Program and the model 

cap and trade rules applicable in that 

State. Such exclusion would make it 

more difficult to coordinate the Acid 

Rain Program and the CAIR Program. 

Consequently, EPA rejects the 

commenter’s more restricted definition 

of fossil fuel-fired. 

The EPA recognizes that new (i.e., 

post-1990) units that are 25 MW or less 

and burn other than clean fuels are 

subject to the Acid Rain Program but not 

to the CAIR Program. However, there are 

very few such units, and EPA has 

decided to exclude any units that are 25 

MW or less on other grounds discussed 

above. 

3. Exemption for Cogeneration Units

As proposed, EPA is finalizing an 

exemption from the model cap and 

trade programs for cogeneration units, 

i.e., units having equipment used to 

produce electricity and useful thermal 

energy for industrial, commercial, 

heating, or cooling purposes through 

sequential use of energy and meeting 

certain operating and efficiency 

standards (discussed below). The EPA is 

adopting the proposed definition of 

cogeneration unit and the proposed 

criteria for determining which 

cogeneration units qualify for the 

exemption from the model cap and 

trade programs. 

The CAIR trading program has 

different applicability provisions for 

non-cogeneration units and 

cogeneration units. If a unit initially 

qualifies as a cogeneration unit, and for 

the exemption from the trading program 

for certain cogeneration units, but 

subsequently loses its cogeneration-unit 

status (e.g., due to changes in 

operation), such unit loses the 

cogeneration-unit exemption and 

becomes subject to the applicability 

criteria for non-cogeneration units, 

regardless of any future changes in the 

unit or its operations. If, under the noncogeneration unit applicability criteria, 

the unit becomes subject to the trading 

program, the unit will remain subject to 

the program in the future. Conversely if 

a unit initially does not qualify as a 

cogeneration unit, such unit becomes 

subject to the applicability criteria for 

non-cogeneration units, regardless of 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25277

127The range included solid fuel-fired 

cogeneration units from 25 MW to 250 MW.

any future changes in the unit. If, under 

such criteria, the unit is subject to the 

trading program, the unit will remain 

subject to the program in the future. 

This approach to applicability means 

that units (other than, in some cases, 

opt-in units) cannot go in and out of the 

trading program, which, if allowed, 

would make it difficult for EPA, States, 

and owners or operators to determine 

which units should be complying with 

trading program requirements, and 

during what years, and would likely 

result in more non-compliance 

problems. 

a. Efficiency Standard for Cogeneration 

Units 

The EPA proposed operating and 

efficiency standards (i.e., the useful 

thermal energy output of the unit must 

be no less than a certain percent of the 

total energy output and, in some cases, 

useful power must be no less than a 

certain percent of total energy input) in 

the SNPR that a unit must meet in order 

to qualify as a cogeneration unit. If the 

unit qualifies as a cogeneration unit, 

then it may be eligible for exemption 

from the CAIR, depending upon 

whether it meets additional operating 

criteria, discussed below. As discussed 

in the NPR, EPA proposed the same 

operating and efficiency standards for 

all fossil fuel-fired units (regardless of 

whether they burn coal, oil, or gas). In 

addition, not applying the operating and 

efficiency standards to coal-fired units 

would be counter productive to EPA’s 

efforts to reduce SO2 and NOX

emissions under this proposed rule 

because of the relatively high SO2 and 

NOX emissions from coal-fired units. In 

particular, without application of the 

efficiency standards to coal-fired units, 

highly inefficient coal-fired units, which 

have particularly high emissions per 

MWhr generated, could be exempt from 

the CAIR Program. In addition, if coalfired units were not subject to the 

operating standard, the potential would 

exist for a coal-fired unit to provide only 

a token amount of useful thermal energy 

and still qualify for a cogeneration unit 

exemption from the CAIR Program, 

despite having relatively high 

emissions. 

One commenter suggested that EPA 

should not use the efficiency standards 

for solid fuel-fired cogeneration units, 

because it may require some coal-fired 

cogeneration units that were exempt 

from the Acid Rain Program to purchase 

CAIR allowances. However, the EPA 

analysis indicates that most existing 

solid fuel-fired cogeneration units 

affected by this rule will meet the 

proposed standard. See TSD entitled 

‘‘Cogeneration Unit Efficiency 

Calculations’’ in the docket. To the 

extent any solid fuel-fired cogeneration 

units cannot meet the efficiency 

standard and become affected units 

under the CAIR, EPA believes that, 

considering their relatively high 

emissions of SO2 and NOX compared to 

oil and gas-fired units, it is important to 

require these sources to meet the 

efficiency standards or be subject to the 

emission limits under the CAIR 

Program.

Another commenter suggested that 

the efficiency standards should not 

apply to solid fuel-fired cogeneration 

units because solid fuel-fired unit 

efficiency is based on HHV (higher 

heating value) while gas, or oil-fired 

unit efficiency is based on LHV (lower 

heating value). The EPA analyzed a 

range 127 of solid fuel-fired cogeneration 

units and calculated their efficiencies to 

see if they would meet the minimum 

efficiency standard. All of the units 

selected satisfied the proposed 

efficiency standard. See TSD entitled 

‘‘Cogeneration Unit Efficiency 

Calculations’’ in the docket. As a result, 

EPA believes that most solid fuel-fired 

cogeneration units will meet the 

proposed efficiency standard. The 

efficiency standard EPA is adopting is 

the Public Utility Regulatory Act 

(PURPA) of thermal efficiency of 42.5 

percent. See TSD entitled, 

‘‘Cogeneration Unit Efficiency 

Calculations’’ for further discussion, is 

based on LHV. If the efficiency of a 

solid-fuel-fired unit is expressed in 

terms of HHV, it can easily be converted 

to LHV for purposes of determining 

whether it meets the efficiency 

standard. Therefore, the reason given by 

the commenter (that solid fuel-fired unit 

efficiency is expressed in terms of HHV) 

is not grounds for not applying an 

efficiency standard to these units. One 

commenter supported applying the 

same efficiency standard to solid fuelfired units as EPA proposed. The EPA 

is finalizing its proposed cogeneration 

unit definition, which applies the same 

operating and efficiency standards to all 

units regardless of the type of fossil fuel 

burned.

b. One-third Potential Electric Output 

Capacity 

The EPA is finalizing the 1⁄3 potential 

electric output capacity criteria in the 

NPR and SNPR. Under the proposals, 

the following cogeneration units are 

EGUs: Any cogeneration unit serving a 

generator with a nameplate capacity of 

greater than 25 MW and supplying more 

than 1⁄3 potential electric output 

capacity and more than 219,000 MW-hrs 

annually to any utility power 

distribution system for sale. These 

criteria are similar to those used in the 

Acid Rain Program to determine 

whether a cogeneration unit is a utility 

unit and the NOX SIP Call to determine 

whether a cogeneration unit is an EGU 

or a non-EGU. The primary difference 

between the proposed criteria and the 1⁄3

potential electric criteria for the Acid 

Rain and NOX SIP Call Programs is that 

these programs applied the criteria to 

the initial operation of the unit and then 

to 3-year rolling average periods while 

the proposed CAIR criteria are applied 

to each individual year starting with the 

commencement of operation. The EPA 

believes that using an individual year 

approach would streamline the 

application and administration of this 

exemption. No adverse comments were 

received on using an individual year 

approach as opposed to a 3-year rolling 

average. In addition, the criteria under 

the Acid Rain Program and the NOX SIP 

Call are applied somewhat differently to 

units commencing construction on or 

before November 15, 1990 and units 

commencing construction after 

November 15, 1990. Several 

commenters suggested exempting all 

cogeneration units under the PURPA 

instead of using the proposed criteria 

and cite the high efficiency of 

cogeneration as a reason for a complete 

exemption. The EPA believes it is 

important to include in the CAIR 

Program all units, including 

cogeneration units, that are substantially 

in the business of selling electricity. The 

proposed 1⁄3 potential electric output 

criteria described above are intended to 

do that. 

Inclusion of all units substantially in 

the electricity sales business minimizes 

the potential for shifting utilization, and 

emissions, from regulated to 

unregulated units in that business and 

thereby freeing up allowances, with the 

result that total emissions from 

generation of electricity for sale exceed 

the CAIR emissions caps. The fact that 

units in the electricity sales business are 

generally interconnected through their 

access to the grid significantly increases 

the potential for utilization shifting. 

One commenter suggested that the 1⁄3

of potential electric output capacity 

criteria be applied on an annual basis. 

The EPA agrees that the criteria should 

be applied annually. The proposed and 

final model cap and trade rules adopt 

that approach. 

c. Clarifying ‘‘For Sale’’

Several commenters requested EPA 

confirm that, for purposes of applying 

the 1⁄3 potential electric output criteria, 

25278 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

128 If the deadline for States to submit SIPs is 

September of 2006, then this would result in 

notification period of less than 3 years for the first 

year of CAIR.

simultaneous purchases and sales of 

electricity are to be measured on a ‘‘net’’

basis, as is done in the Acid Rain 

Program. At least one commenter 

suggested that the net approach also be 

applied to purchase and sales that are 

not simultaneous. For purposes of 

applying the 1⁄3 potential electric output 

criteria in the CAIR Program and the 

model cap and trade rules, EPA 

confirms that the only electricity that 

counts as a sale is electricity produced 

by a unit that actually flows to a utility 

power distribution system from the unit. 

Electricity that is produced by the unit 

and used on-site by the electricityconsuming component of the facility 

will not count, including cogenerated 

electricity that is simultaneously 

purchased by the utility and sold back 

to such facility under purchase and sale 

agreements under the PURPA. However, 

electric purchases and sales that are not 

simultaneous will not be netted; the 1⁄3

potential electric output criteria will be 

applied on a gross basis, except for 

simultaneous purchase and sales. This 

is consistent with the approach taken in 

the Acid Rain Program. 

d. Multiple Cogeneration Units 

Some commenters suggested 

aggregating multiple cogeneration units 

that are connected to a utility 

distribution system through a single 

point when applying the 1⁄3 potential 

electric output capacity criteria. These 

commenters suggested that it is not 

feasible to determine which unit is 

producing the electricity exported to the 

outside grid. The EPA proposed to 

determine whether a unit is affected by 

the CAIR on an individual-unit basis. 

This unit-based approach is consistent 

with both the Acid Rain Program and 

the NOX SIP Call. The EPA considers 

this approach to be feasible based on 

experience from these existing 

programs, including for sources with 

multiple cogeneration units. The EPA is 

unaware of any instances of 

cogeneration unit owners being unable 

to determine how to apply the 1⁄3

potential electric output capacity 

criteria where there are multiple 

cogeneration units at a source.

In a case where there are multiple 

cogeneration units with only one 

connection to a utility power 

distribution system, the electricity 

supplied to the utility distribution 

system can be apportioned among the 

units in order to apply the 1⁄3 potential 

electric output capacity criteria. A 

reasonable basis for such apportionment 

must be developed based on the 

particular circumstances. The most 

accurate way of apportioning the 

electricity supplied to the utility power 

distribution system seems to be 

apportionment based on the amount of 

electricity produced by each unit during 

the relevant period of time. 

Exemption for Independent Power 

Production (IPP) Facilities: Some 

commenters stated that certain IPP 

facilities are exempt from the Acid Rain 

Program and that they should also be 

exempt from the CAIR Program and 

model-cap and trade rules. Under the 

Acid Rain Program, an IPP facility that 

has, as of November 15, 1990, a 

qualifying power purchase commitment 

(including a sales price) to sell at least 

15 percent of planned net output 

capacity and has installed net output 

capacity not exceeding 130 percent of 

planned net output capacity is exempt. 

However, if the power purchase 

commitment changes after November 

15, 1990 in a way that allows the cost 

of compliance with the Acid Rain 

Program to be shifted to the purchaser, 

then the IPP facility loses the 

exemption. For example, expiration or 

termination of the power purchase 

commitment or modification so that the 

price is increased (e.g., changed to a 

market price) results in loss of the 

exemption. The purpose of the 

exemption is to protect IPP facilities 

subject to contract prices that were set 

before passage of the CAA Amendments 

of 1990 (including the Acid Rain 

Program in title IV) and that did not 

allow passthrough of the costs of Acid 

Rain Program compliance. However, 

EPA maintains that this exemption was 

aimed at easing the transition of such 

facilities into the Acid Rain Program 

and that there is no basis for 

maintaining this exemption for every 

subsequent cap and trade program. In 

addition, this exemption was not used 

in the NOX SIP Call. 

D. How Are Emission Allowances 

Allocated to Sources? 

It is important to have consistency on 

a State-by-State basis with the basic 

requirements of the cap and trade 

approach when implementing a multiState cap and trade program. This will 

ensure that: The integrity of the cap and 

trade approach is preserved so that the 

required emissions reductions are 

achieved; the compliance and 

administrative costs are minimized; and 

source owners and operators are 

equitably treated. However, EPA 

believes that some limited differences, 

such as allowance allocation 

methodologies for NOX allowances, are 

possible without jeopardizing the 

environmental and other goals of the 

program. 

1. Allocation of NOX and SO2

Allowances 

Each State participating in EPAadministered cap and trade programs 

must develop a method for allocating 

(i.e., distributing) an amount of 

allowances authorizing the emissions 

tonnage of the State’s CAIR EGU budget. 

For NOX allowances, each State has the 

flexibility to allocate its allowances 

however they choose, so long as certain 

timing requirements are met. 

For SO2, as noted in the January 2004 

proposal, States will have no discretion 

in their allocation approach since the 

CAIR SO2 cap and trade program uses 

title IV SO2 allowances, which have 

been already allocated in perpetuity to 

individual units by title IV of the CAA. 

a. Required Aspects of a State NOX

Allocation Approach 

While it is EPA’s intent to provide 

States with as much flexibility as 

possible in developing allocation 

approaches, there are some aspects of 

State allocations that must be consistent 

for all States. All State allocation 

systems are required to include specific 

provisions that establish when States 

notify EPA and sources of the unit-byunit allocations. These provisions 

establish a deadline for each State to 

submit to EPA its unit-by-unit 

allocations for processing into the 

electronic allowance tracking system. 

Since the Administrator will then 

expeditiously record the submitted 

allowance allocations, sources will 

thereby be notified of, and have access 

to, allocations with a minimum lead 

time (about 3 years) before the 

allowances can be used to meet the NOX

emission limit. 

Today’s action finalizes the proposal 

to require States to submit unit-by-unit 

allocations of allowances for a given 

year no less than 3 years prior to 

January 1 of the allowance vintage year, 

which approach was supported by 

commenters.128 Requiring States to 

submit allocations and thereby provide 

a minimum lead time before the 

allowances can be used to meet the NOX

emission limit ensures that an affected 

source—regardless of the State in the 

CAIR region in which the unit is 

located—will have sufficient time to 

plan for compliance and implement 

their compliance planning. Allocating 

allowances less than 3 years in advance 

of the compliance year may reduce a 

CAIR unit’s ability to plan for and 

implement compliance and, 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25279

consequently, increase compliance 

costs. For example, a shorter lead time 

would reduce the period for buying or 

selling allowances and could prevent 

sources from participating in allowance 

futures markets, a mechanism for 

hedging risk and lowering costs.

Further, requiring a uniform, 

minimum lead-time for submission of 

allocations allows EPA to perform its 

allocation-recordation activities in a 

coordinated and efficient manner in 

order to complete expeditiously the 

recordation for the entire CAIR region 

and thereby promote a fair and 

competitive allowance market across the 

region. 

These minimum requirements apply 

to the NOX allocation approach and are 

not relevant for the SO2 cap and trade 

program, which relies on title IV 

allowances. 

b. Flexibility and Options for a State 

NOX Allowance Allocations Approach 

Allowance allocation decisions in a 

cap-and-trade program raise essentially 

distributional issues, as economic forces 

are expected to result in economically 

efficient and environmentally similar 

outcomes regardless of the manner in 

which allowances are initially 

distributed. Consequently, for CAIR 

NOX allowances, States are given 

latitude in developing their allocation 

approach. NOX allocation methodology 

elements for which States will have 

flexibility include: 

A. The cost of the allowance 

distribution (e.g., free distribution or 

auction); 

B. The frequency of allocations (e.g., 

permanent or periodically updated); 

C. The basis for distributing the 

allowances (e.g., heat-input or power 

output); and, 

D. The use of allowance set-asides 

and their size, if used (e.g., new unit setasides or set-asides for energy 

efficiency, for development of Integrated 

Gasification Combined Cycle (IGCC) 

generation, for renewables, or for small 

units). 

Some commenters have argued 

against giving States flexibility in 

determining NOX allocations, citing 

concerns about complexity of operating 

in different markets and about the 

robustness of the trading system. The 

EPA maintains that offering such 

flexibility, as it did in the NOX SIP Call, 

does not compromise the effectiveness 

of the trading program. 

A number of commenters have argued 

against allowing (or requiring) the use of 

allowance auctions, while others did 

not believe that EPA should recommend 

auctions. For today’s final action, while 

there are some clear potential benefits to 

using auctions for allocating allowances 

(as noted in the SNPR), EPA believes 

that the decision regarding utilizing 

auctions should ultimately be made by 

the States. Therefore, EPA is not 

requiring, restricting, or barring State 

use of auctions for allocating 

allowances. 

A number of commenters supported 

allowing the use of allowance set-asides 

for various purposes. In today’s final 

action, EPA is leaving the decision on 

using set-asides up to the States, so that 

States may craft their allocation 

approach to meet their State-specific 

policy goals. 

i. Example Allowance Allocation 

Methodology 

In the SNPR, EPA included an 

example (offered for informational 

guidance) of an allocation methodology 

that includes allowances for new 

generation and is administratively 

straightforward. In today’s preamble, 

EPA is including in today’s preamble, 

this ‘‘modified output’’ example 

allocations approach, as was outlined in 

the SNPR. 

The EPA maintains that the choice of 

allocation methodology does not impact 

the achievement of the specific 

environmental goals of the CAIR 

Program. This methodology is offered 

simply as an example, and individual 

States retain full latitude to make their 

own choices regarding what type of 

allocation method to adopt for NOX

allowances and are not bound in any 

way to adopt EPA’s example. 

This example method involves inputbased allocations for existing fossil 

units, with updating to take into 

account new generation on a modifiedoutput basis. It also utilizes a new 

source set-aside for new units that have 

not yet established baseline data to be 

used for updating. Providing allowances 

for new sources addresses a number of 

commenter concerns about the negative 

effect of new units not having access to 

allowances.

Under the example method, 

allocations are made from the State’s 

EGU NOX budget for the first five 

control periods (2009 through 2013) of 

the model cap and trade program for 

existing sources on the basis of historic 

baseline heat input. Commenters 

expressed some concern regarding the 

proposed January 1, 1998 cut-off on-line 

date for considering units as existing 

units. The cut-off on-line date was 

selected so that any unit meeting the 

cut-off date would have at least 5 years 

of operating data, i.e., data for 1998 

through 2002 (which was the last year 

for which annual data was available). 

The EPA is still concerned with 

ensuring that particular units are not 

disadvantaged in their allocations by 

having insufficient operating data on 

which to base the allocations. The EPA 

believes that a 5 year window, starting 

from commencement of operation, gives 

units adequate time to collect sufficient 

data to provide a fair assessment of their 

operations. Annual operating data is 

now available for 2003. The EPA is 

finalizing January 1, 2001 as the cut-off 

on-line date for considering units as 

existing units since units meeting the 

cut-off date will have at least 5 years of 

operating data (i.e., data for 2001 

through 2005). 

The allowances for 2014 and later will 

be allocated from the State’s EGU NOX

budget annually, 6 years in advance, 

taking into account output data from 

new units with established baselines 

(modified by the heat input conversion 

factor to yield heat input numbers). As 

new units enter into service and 

establish a baseline, they are allocated 

allowances in proportion to their share 

of the total calculated heat input (which 

is existing unit heat input plus new 

units’ modified output). Allowances 

allocated to existing units slowly 

decline as their share of total calculated 

heat input decreases with the entry of 

new units. 

After 5 years of operation, a new unit 

will have an adequate operating 

baseline of output data to be 

incorporated into the calculations for 

allocations to all affected units. The 

average of the highest 3 years from these 

5 years will be multiplied by the heatinput conversion factor to calculate the 

heat input value that will be used to 

determine the new unit’s allocation 

from the pool of allowances for all 

sources. 

Under the EPA example method, 

existing units as a group will not update 

their heat input. This will eliminate the 

potential for a generation subsidy (and 

efficiency loss) as well as any potential 

incentive for less efficient existing units 

to generate more. This methodology will 

also be easier to implement since it will 

not require the updating of existing 

units’ baseline data. Retired units will 

continue to receive allowances 

indefinitely, thereby creating an 

incentive to retire less efficient units 

instead of continuing to operate them in 

order to maintain the allowances 

allocations. 

Moreover, new units as a group will 

only update their heat input numbers 

once—for the initial 5-year baseline 

period after they start operating. This 

will eliminate any potential generation 

subsidy and be easier to implement, 

since it will not require the collection 

25280 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

129Energy Information Administration, ‘‘Annual 

Energy Outlook 2004, With Projections to 2025’’, 

January 2004. Assumptions for the NEMS model. 

http://www.eia.doe.gov/oiaf/archive/aeo04/

assumption/tbl38.html.

130Some commenters stated that, if allocations 

were provided for non-emitting new generation, 

they also should be provided to all such generation, 

including nuclear units.

and processing of data needed for 

regular updating. 

The EPA believes that allocating to 

existing units based on a baseline of 

historic heat input data (rather than 

output data) is desirable, because 

accurate protocols currently exist for 

monitoring this data and reporting it to 

EPA, and several years of certified data 

are available for most of the affected 

sources. The EPA expects that any 

problems with standardizing and 

collecting output data, to the extent that 

they exist, can be resolved in time for 

their use for new unit calculations. 

Given that units keep track of electricity 

output for commercial purposes, this is 

not likely to be a significant problem. 

A number of commenters expressed 

support for EPA’s proposal in the SNPR 

that the heat input data for existing 

units be adjusted by multiplying it by 

different factors based on fuel-type. 

Contrary to some commenters’ claims, 

determining allocations with fuel factors 

would not create disincentives for 

efficiency. With the use of a single 

baseline for existing units, neither 

adjusted input, nor input, nor output 

based allocations would provide 

additional incentives for energy 

efficiency. All sources have incentives 

to reduce emissions (improving 

efficiency is a way of doing this) as a 

result of the cap and trade program, not 

because of the choice of an allocation 

based on a single historic baseline. 

The EPA acknowledges that since 

allowances have value, different 

allocations of allowances clearly do 

impact the distribution of wealth among 

different generators. However, in 

general, the economics of power 

generation dictate that generators selling 

power will seek to operate (and burn 

fuel) to meet energy demand in a leastcost manner. The cost of the power 

generated (reflecting the bid price per 

megawatt hour) will include the cost of 

allowances to cover emissions, whether 

the generator uses allowances that it 

already owns, or whether it needs to 

purchase additional allowances. With a 

liquid market for allowances, 

allocations for existing sources (whose 

baseline does not change) are a sunk 

benefit or sunk cost, not impacting the 

existing generator’s behavior on the 

margin. Thus, the use of fuel factors in 

our allocating method would not be 

expected to result in changes in 

generators’ choices for fuel efficiency.

In its example allocation approach, 

EPA is including adjustments of heat 

input by fuel type based on average 

historic NOX emissions rates by three 

fuel types (coal, natural gas, and oil) for 

the years 1999–2002. As noted in the 

SNPR, such calculations would lead to 

adjustment factors of 1.0 for coal, 0.4 for 

gas and 0.6 for oil. The factors would 

reflect the inherently different 

emissions rates of different fossil-fired 

units (and consequently also reflect the 

different burdens to control emissions. 

However, allocating to new (not 

existing) sources on the basis of input 

(and particularly fuel-adjusted heat 

input) would serve to subsidize lessefficient new generation. For a given 

amount of generation, more efficient 

units will have the lower fuel input or 

heat input. Allocating to new units 

based on heat input could encourage the 

building of less efficient units since they 

would get more allowances than an 

equivalent efficient, lower heat-input 

unit. The modified output approach, as 

described below, will encourage new, 

clean generation, and will not reward 

less efficient new coal units or less 

efficient new gas units. 

Under the example method, 

allowances will be allocated to new 

units of each fuel-type with an 

appropriate baseline on a ‘‘modified 

output’’ basis. The new unit’s modified 

output will be calculated by multiplying 

its gross output by a heat rate 

conversion factor of 7,900 btu/kWh for 

coal units and 6,675 btu/kWh for oil and 

gas units. The 7,900 btu/kWh value for 

the conversion factor for new coal units 

is an average of heat-rates for new 

pulverized coal plants and new IGCC 

coal plants (based upon assumptions in 

EIA’s Annual Energy Outlook (AEO) 

2004 129). The 6,675 btu/kWh value for 

the conversion factor for new gas units 

is an average of heat-rates for new 

combined cycle gas units (also based 

upon assumptions in EIA’s AEO 2004). 

A single conversion rate for each fueltype will create consistent and level 

incentives for efficient generation, 

rather than favoring new units with 

higher heat-rates.

For new cogeneration units, their 

share of the allowances will be 

calculated by converting the available 

thermal output (btu) of useable steam 

from a boiler or useable heat from a heat 

exchanger to an equivalent heat input 

by dividing the total thermal output 

(btu) by a general boiler/heat exchanger 

efficiency of 80 percent. 

New combustion turbine cogeneration 

units will calculate their share of 

allowances by first converting the 

available thermal output of useable 

steam from a heat recovery steam 

generator (HRSG) or useable heat from 

a heat exchanger to an equivalent heat 

input by dividing the total thermal 

output (btu) by the general boiler/heat 

exchanger efficiency of 80 percent. To 

this they will add the electrical 

generation from the combustion turbine, 

converted to an equivalent heat input by 

multiplying by the conversion factor of 

3,413 btu/kWh. This sum will yield the 

total equivalent heat input for the 

cogeneration unit. 

Steam and heat output, like electrical 

output, is a useable form of energy that 

can be utilized to power other 

processes. Because it would be nearly 

impossible to adequately define the 

efficiency in converting steam energy 

into the final product for all of the 

various processes, this approach focuses 

on the efficiency of a cogeneration unit 

in capturing energy in the form of steam 

or heat from the fuel input. 

Commenters expressed concern about 

a single conversion factor, arguing for 

different factors for different fuels and 

technologies. The EPA recognizes these 

concerns and agrees that different new 

fossil-generation units have inherently 

different heat rates, largely dictated by 

the technology needed to burn different 

fuels. A single conversion rate for all 

units would provide new gas-fired 

combined cycle units with relatively 

more allowances, relative to their 

emissions, than it would for new coalfired units. 

The EPA maintains that providing 

each new source an equal amount of 

allowances per MWh of output, given 

the fuel it is burning, is an equitable 

approach. Since electricity output is the 

ultimate product being produced by 

EGUs, a single conversion factor for 

each fuel, based on output, ensures that 

all new sources burning a particular fuel 

will be treated equally.

Some commenters support allocating 

allowances to all new generation, not 

just fossil fuel-fired CAIR units. The 

EPA notes that including new non-CAIR 

and non-fossil units in the allowance 

distribution would raise issues, about 

which EPA lacks sufficient information 

for resolution at this time for EPA’s 

example method. It would be necessary 

to clearly define what types of 

generating facilities that could 

participate and what would constitute 

‘‘new’’ non-fossil generation.130

Commenters did not provide any 

analysis of the impact of possible 

definitions on generation mix, or 

electricity markets. Further, in order to 

include all generation, there would be a 

need to establish application and data 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25281

131For instance, would the addition of a single 

new wind turbine at a wind-farm constitute a ‘‘new 

unit’’? 132As noted earlier in this section, EPA is now 

considering new units to be those that went online 

after January 1, 2001 rather than 1998.

133With the alternate approach from the NOX SIP 

Call. States could distribute a new source set-aside 

for a control period based on full utilization rates, 

at the end of the year the actual allowance 

allocation would be adjusted to account for actual 

unit utilization/output, and excess allowances 

would be returned and redistributed, first taking 

into account new unit requests that were not able 

to be addressed.

134Auctions could provide States with a nondistortionary source of revenue.

135 5 percent of the allowances would go to a new 

source set-aside.

collections procedures and determine 

appropriate size cut-offs and boundaries 

of this generation—since in many such 

instances there is no clear analog to 

discrete fossil ‘‘units.’’ 131 There also are 

associated issues about developing 

appropriate measurement and data 

reporting requirements for such sources. 

Commenters supporting this approach 

did not address any of these matters in 

any detail. However, EPA encourages 

States that are interested in including 

such units in their updating allocations 

to consider potential solutions and 

include them in their SIPs. Under the 

example method, new units that have 

entered service, but have not yet started 

receiving allowances through the 

update, will receive allowances each 

year from a new source set-aside. The 

new source allowances from the setaside will be distributed based on their 

actual emissions from the previous year. 

Such an allocation approach will 

generally provide new units sufficient 

allowances to cover their emissions 

during the interim period before the 

units are allocated allowances on the 

same basis as existing units. 

Today’s example method includes a 

new source set-aside equal to 5 percent 

of the State’s emission budget for the 

years 2009–2013 and 3 percent of the 

State’s emission budget for the 

subsequent years. In the SNPR, EPA 

proposed a level 2 percent set-aside for 

all years.

Commenters noted their concern that 

the amount of the set-aside in the early 

years of the program should be higher 

to reflect the fact that the set-aside will 

initially need to accommodate all new 

units entering into service from 1998 

through 2010.132 In order to estimate the 

need for allocations for new units, EPA 

looked at the NOX emissions from units 

that went online starting in 1999 as 

projected by the Integrated Planning 

Model (IPM) runs modeling CAIR for 

the years 2010 and 2015. These IPM 

emissions projections indicated over 

57,000 tons of NOX emissions in 2010 

and about 74,000 tons of NOX emission 

by 2015 from new sources need to be 

covered under set-asides throughout the 

CAIR region. The 2010 number 

represents almost 4 percent of the Phase 

I NOX regional cap, while the 2015 

number represents about 6 percent of 

the Phase I regional cap. Consequently, 

today’s example method includes a 5 

percent set-aside for the initial period 

(2009–2013). It should be noted that by 

2014, the set-aside would need to cover 

new sources from the entire period 

2004–2013.

The choice of a 3 percent new source 

set-aside, starting in 2014, reflects 

concerns that adequate allowances be 

provided for the 10 years of new units 

to be covered by the set-aside in 2014 

and subsequent years. (The set-aside in 

2014, for example, would need to 

accommodate all units that went on-line 

between 2004 and 2013).

Individual States using a version of 

the example method may want to adjust 

this initial 5 year set-aside amount to a 

number higher or lower than 5 percent 

to the extent that they expect to have 

more or less new generation going online during the 2001–2013 period. They 

may also want to adjust the subsequent 

set-aside amount to a number higher or 

lower than 3 percent to the extent that 

they expect more or less new generation 

going on-line after 2004. States may also 

want to set this percentage a little higher 

than the expected need, since, in the 

event that the amount of the set-aside 

exceeds the need for new unit 

allowances, the State may want to 

provide that any unused set-aside 

allowances will be redistributed to 

existing units in proportion to their 

existing allocations. 

For the example method, EPA is 

finalizing the approach that new units 

will begin receiving allowances from the 

set-aside for the control period 

immediately following the control 

period in which the new unit 

commences commercial operation, 

based on the unit’s emissions for the 

preceding control period. Thus, a source 

will be required to hold allowances 

during its start-up year, but will not 

receive an allocation for that year. 

States will allocate allowances from 

the set-aside to all new units in any 

given year as a group. If there are more 

allowances requested than in the setaside, allowances will be distributed on 

a pro-rata basis. Allowance allocations 

for a given new unit in following years 

will continue to be based on the prior 

year’s emissions until the new unit 

establishes a baseline, is treated as an 

existing unit, and is allocated 

allowances through the State’s updating 

process. This will enable new units to 

have a good sense of the amount of 

allowances they will likely receive—in 

proportion to their emissions for the 

previous year. This methodology will 

not provide allowances to a unit in its 

first year of operation; however it is a 

methodology that is straightforward, 

reasonable to implement, and 

predictable. 

In the SNPR, the example method 

from the NOX SIP Call model rule was 

proposed as an alternate approach.133

However, the EPA has found this 

approach to be complicated for both the 

States and the EPA to implement. 

Additionally, the NOX SIP Call 

approach would introduce a higher 

level of uncertainty for sources in the 

allocation process than necessary.

While the EPA is offering an example 

allocation method with accompanying 

regulatory language, the EPA reiterates 

that it is giving States’ flexibility in 

choosing their NOX allocations method 

so they may tailor it to their unique 

circumstances and interests. Several 

commenters, for instance, have noted 

their desire for full output-based 

allocations (in contrast to the hybrid 

approach in the example above). In the 

past, EPA had sponsored a work group 

to assist States wishing to adopt outputbased NOX allocations for the NOX SIP 

Call and believes it is a viable approach 

worth considering. Documents from 

meetings of this group and the resulting 

guidance report (found at http://

www.epa.gov/airmarkets/fednox/

workgrp.html) together with additional 

resources such as the EPA-sponsored 

report ‘‘Output-Based Regulations: A 

Handbook for Air Regulators’’ (found at 

http://www.epa.gov/cleanenergy/pdf/

output_rpt.pdf) can help States, should 

they choose to adopt any output-based 

elements in their allocation plans. 

As an another alternative example, 

States could decide to include elements 

of auctions into their allowance 

allocation programs.134 An example of 

an approach where CAIR NOX

allowances could be distributed to 

sources through a combination of an 

auction and a free allocation is provided 

below.

During the first year of the trading 

program, 94 percent of the NOX

allowances could, for example, be 

allocated to affected units with an 

auction held for the remaining 1 percent 

of the NOX allowances 135. Each 

subsequent year, an additional 1 percent 

of the allowances (for the first 20 years 

of the program), and then an additional 

2.5 percent thereafter, could be 

auctioned until eventually all the 

allowances are auctioned. With such a 

system, for the first 20 years of the 

25282 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

trading programs, the majority of 

allowances would be distributed for free 

via the allocation. Allowances allocated 

for these earlier years are generally more 

valuable than allowances allocated for 

later years because of the time value of 

money. Thus, most emitting units 

would receive relatively more 

allowances in the early years of the 

program, when they are facing the 

expenses of taking actions to control 

their emissions. Even though the 

proportion of allowances allocated to 

existing sources declines in the later 

years of the program, these sources 

receive for free a very significant share 

of the total value of allowances (because 

the discounted present value of 

allowances allocated in the early years 

of the program is greater than the 

discounted present value of the 

allowances auctioned later).

Auctions could be designed by the 

State to promote an efficient 

distribution of allowances and a 

competitive market. Allowances would 

be offered for sale before or during the 

year for which such allowances may be 

used to meet the requirement to hold 

allowances. States would decide on the 

frequency and timing of auctions. Each 

auction would be open to any person, 

who would submit bids according to 

auction procedures, a bidding schedule, 

a bidding means, and by fulfilling 

requirements for financial guarantees as 

specified by the State. Winning bids, 

and required payments, for allowances 

would be determined in accordance 

with the State program and ownership 

of allowances would be recorded in the 

EPA Allowance Tracking System after 

the required payment is received. 

The auction could be a multipleround auction. Interested bidders would 

submit before the auction, one or more 

initial bids to purchase a specified 

quantity of NOX allowances at a reserve 

price specified by the State, specifying 

the appropriate account in the 

Allowance Tracking System in which 

such allowances would be recorded. 

Each bid would be guaranteed by a 

certified check, a funds transfer, or, in 

a form acceptable to the State, a letter 

of credit for such quantity multiplied by 

the reserve price. For each round of the 

auction, the State would announce 

current round reserve prices for NOX

and determine whether the sum of the 

acceptable bids exceeds the quantity of 

such allowances, available for auction. 

If the sum of the acceptable bids for 

NOX allowances exceeds the quantity of 

such allowances the State would 

increase the reserve price for the next 

round. After the auction, the State 

would publish the names of winning 

and losing bidders, their quantities 

awarded, and the final prices. The State 

would return payment to unsuccessful 

bidders and add any unsold allowances 

to the next relevant auction. 

In summary, today’s action provides, 

for States participating in the EPAadministered CAIR NOX cap and trade 

program, the flexibility to determine 

their own methods for allocating NOX

allowances to their sources. 

Specifically, such States will have 

flexibility concerning the cost of the 

allowance distribution, the frequency of 

allocations, the basis for distributing the 

allowances, and the use and size of 

allowance set-asides. 

E. What Mechanisms Affect the Trading 

of Emission Allowances? 

1. Banking 

a. The CAIR NPR and SNPR Proposal for 

the Model Rules and Input From 

Commenters

Banking is the retention of unused 

allowances from 1 calendar year for use 

in a later calendar year. Banking allows 

sources to make 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 

reductions goals. When sources reduce 

their SO2 and NOX emissions in the 

early phases, the cap and trade program 

creates an emissions ‘‘glide path’’ that 

provides earlier environmental benefits 

and lower cost of compliance. This 

‘‘glide path’’ does allow emissions to 

exceed the cap and trade program 

budget—especially in the initial years 

after the adoption of a more stringent 

cap. The use of banked allowances from 

the Acid Rain and NOX SIP Call 

Programs in the CAIR NOX and SO2 cap 

and trade programs is discussed below 

in section VIII.F of this preamble. 

The January 30, 2004 CAIR NPR and 

June 10, 2004 CAIR SNPR proposed that 

the CAIR NOX and SO2 cap and trade 

programs allow banking and the use of 

banked allowances without restrictions. 

Allowing unrestricted banking and the 

use of banked allowances is consistent 

with the existing Acid Rain SO2 cap and 

trade program. The NOX SIP Call cap 

and trade program, however, has some 

restrictions on the use of banked 

allowances, a procedure called ‘‘flow 

control,’’ described in detail in the June 

10, 2004 CAIR SNPR. 

Comments Regarding Unrestricted 

Banking After the Start of the CAIR NOX

and SO2 Cap and Trade Programs 

Many commenters supported the 

EPA’s proposal to allow unrestricted 

banking and the use of banked 

allowances for both SO2 and NOX, 

agreeing that flow control is a complex 

and confusing procedure with 

undemonstrated environmental benefit. 

Further, they agreed that banking with 

no restrictions on use will encourage 

early emissions reductions, stimulate 

the trading market, encourage efficient 

pollution control, and provide 

flexibility to affected sources in meeting 

environmental objectives. 

Other commenters objected to the 

EPA’s proposal to allow unrestricted use 

of banked allowances. All of these 

commenters supported some use of flow 

control in the CAIR cap and trade 

programs, most supporting its use for 

both SO2 and NOX. 

Some commenters disagreed with the 

EPA’s assessment that the use of flow 

control in the Ozone Transport 

Commission (OTC) cap and trade 

program was complicated to understand 

and implement and caused market 

complexity. One commenter further 

elaborated that flow control was 

accepted by industry. Another 

commenter claimed that the EPA has 

not analyzed the impact of the flow 

control mechanism. 

Some commenters supportive of flow 

control stated that flow control was 

‘‘successful’’ in the OTC and NOX SIP 

Call trading programs and ‘‘worked 

well’’ and ‘‘achieved the desired effect,’’

without supporting those statements. 

b. The Final CAIR Model Rules and 

Banking 

The EPA acknowledges that the OTC 

NOX cap and trade program has 

functioned for several years despite the 

complexity introduced by the flow 

control procedures. Industry and other 

allowance traders have adapted to these 

complex procedures, yet there are 

ongoing questions from the regulated 

community about how the procedures 

actually work. As an example, one 

commenter, while disagreeing with the 

EPA’s assertion that flow control is 

overly complex, goes on to describe 

incorrectly the implementation of flow 

control. The NOX SIP Call cap and trade 

program includes similar procedures 

but flow control was not triggered in the 

first 2 years of the program (2003 and 

2004), so there is no experience to be 

drawn from that program. 

The EPA maintains that the benefits 

of utilizing these complex procedures is 

questionable. The EPA has analyzed the 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25283

use of the flow control procedures in a 

paper released in March 2004, 

‘‘Progressive Flow Control in the OTC 

NOX Budget Program: Issues to Consider 

at the Close of the 1999 to 2002 Period.’’

The lessons learned from this analysis 

were as follows: 

(1) Flow control can create market 

pricing complexity and uncertainty. The 

need for implementation of flow control 

for a particular control period is not 

known more than a few months in 

advance, and the value of banked 

allowances varies from year to year, 

depending on whether flow control has 

been triggered for the particular year. 

Therefore, when deciding how much to 

control, a source has some increased 

uncertainty about the value of any 

excess allowances it generates. 

(2) Flow control can have a bigger 

impact on small entities than on large 

entities. Large firms with multiple 

allowance accounts can shift banked 

allowances among those accounts to 

minimize the number of banked 

allowances surrendered at a discounted 

rate. 

(3) Flow control does not directly 

affect short-term emissions, so it may 

not serve the environmental goals for 

which it was created. 

Incorporating these lessons learned, 

the EPA is finalizing the CAIR NOX and 

SO2 cap and trade programs with no 

flow control mechanism. 

2. Interpollutant Trading Mechanisms 

a. The CAIR NPR Proposal for the Model 

Rules and Input From Commenters

Mechanisms for interpollutant trading 

allow reduced emissions of one 

pollutant to be exchanged for increased 

emissions of another pollutant where 

both pollutants cause the same 

environmental problem (e.g., are 

precursors of a third pollutant). 

Interpollutant trading mechanisms are 

typically based upon each precursor’s 

contribution to a particular 

environmental problem and are often 

controversial and scientifically difficult 

to design because of the complexities of 

environmental chemistry. 

Determination of conversion factors 

(i.e., transfer ratios that relate the impact 

of one pollutant to the impact of another 

pollutant) can be dependent upon 

location, the presence of other 

pollutants that are necessary for 

chemical reactions, the time of 

emissions, and other considerations. 

The January 30, 2004 CAIR NPR did 

not propose a specific interpollutant 

trading mechanism but rather took 

comment on interpollutant trading in 

general as well as the following specific 

issues: 

(1) What would be the exchange rate 

(i.e., the transfer ratio) for the two 

pollutants, 

(2) How can the transfer ratio best 

achieve the goals of PM2.5 and ozone 

reductions in downwind States and, 

(3) How would the interpollutant 

trading accommodate the different 

geographic regions of the PM2.5 and 

ozone programs? 

Comments Regarding the Potential 

Interpollutant Trading 

The EPA received several comments 

on interpollutant trading with the most 

commenters generally opposed to 

including provisions to allow for the 

interchangability of SO2 and NOX

allowances. 

Several commenters pointed out that 

the CAIR ozone attainment benefits 

result from the NOX emissions 

reductions, and contend that the EPA 

has not shown that SO2 emissions 

impact ozone. Therefore, the 

commmenters conclude that it would be 

inappropriate for SO2 allowances to be 

traded and used for compliance with the 

NOX cap. Some commenters supported 

the consideration or use of 

interpollutant trading if it was onedirectional, i.e., NOX allowances could 

be used for compliance with the SO2

allowance holding requirements, but not 

vice versa. This could result in fewer 

NOX emissions and more SO2

emissions. 

Some commenters supported the 

consideration or use of interpollutant 

trading and emphasized the scientific 

difficulty in developing accurate 

transfer ratios. Of these commenters, 

some added that interpollutant trading 

would be appropriate if the EPA 

conducted a thorough analysis of the 

potential impacts that interpollutant 

trading would have on: nonattainment 

areas’ ability to come into attainment; 

the allowance markets and prices; and 

the integrity of the NOX caps in light of 

the potentially large SO2 allowance 

bank that might be carried forward into 

the CAIR trading programs. 

A few commenters noted that the EPA 

is directed by the CAA to study 

interpollutant trading and has approved 

SIPs that allow the trading of ozone 

precursors under specific 

circumstances. 

b. Interpollutant Trading and the Final 

CAIR Model Rules 

Interpollutant trading can provide 

some additional compliance flexibility, 

and potentially lower compliance costs, 

if appropriately applied to multiple 

pollutants that have reasonably well 

known impacts on the same 

environmental problem. The EPA 

acknowledges that it has the authority to 

create interpollutant trading programs 

and has done so, in other regulatory 

contexts, in the past. However, for 

several reasons, the EPA determined 

that direct interpollutant trading is not 

appropriate in the CAIR. 

The final CAIR includes separate 

annual SO2 and annual NOX model 

rules to address PM2.5 precursor 

emissions, and an ozone-season NOX

model rule to address summertime 

ozone precursor emissions. The EPA 

believes it is not appropriate for the 

CAIR model rules to allow annual SO2

or NOX allowances to be used for 

compliance with ozone-season NOX

allowance holding requirements 

because this has the potential to 

adversely impact the ozone-season 

emissions reductions and ozone air 

quality improvements from CAIR. This 

is significant because the EPA, as 

required by the CAA, has promulgated 

a national air quality standard for 8-

hour ozone based on a determination 

that the standard is necessary to protect 

public health. Section 110(a)2(D) 

requires States to prohibit emissions in 

amounts that will significantly 

contribute to nonattainment in, or 

interfere with maintenance by, any 

other State with respect to any air 

quality standard, including ozone. In 

this rule, EPA has designed the annual 

(SO2 and NOX) and ozone-season (NOX) 

emission caps to achieve the emissions 

reductions necessary to address each 

State’s significant contribution to 

downwind PM2.5 and ozone 

nonattainment, respectively, and to 

prevent interference with maintenance. 

If sources were permitted to use annual 

SO2 or annual NOX allowances for 

compliance with ozone-season NOX

allowance holding requirements (i.e., 

the ozone-season NOX cap), then there 

would be no assurance that upwind 

States’ ozone-season NOX reduction 

obligations would be met, and CAIR’s 

projected ozone improvements in 

downwind nonattainment areas could 

be significantly reduced. As a result, 

should interpollutant trading be 

permitted between the annual and 

ozone-season programs, the EPA could 

not demonstrate that the use of a CAIR 

ozone-season cap and trade program 

would result in the emissions 

reductions necessary to satisfy upwind 

States’ obligations under section 

110(a)2(D)to reduce NOX for ozone 

purposes.

The EPA believes it is also 

inappropriate to use annual NOX

allowances for compliance with the 

annual SO2 allowance holding 

requirements, and vice versa. The EPA 

agrees with commenters that emphasize 

25284 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

that the chemical interactions for PM2.5

precursors are scientifically complex 

and must be accurately reflected in any 

transfer ratio in order to maintain the 

integrity of the market. For example, 

EPA analysis has shown (see January 30, 

2004 NPR) that PM2.5 precursors, such 

as NOX and SO2, may have non-linear 

interactions in the formation of PM2.5. 

Any uniform, interpollutant transfer 

ratio would have to be an average and 

would introduce significant variability 

concerning the impact of interpollutant 

trading on emissions and significant 

uncertainty concerning the achievement 

of the CAIR Program’s emission 

reduction goals. The EPA did not 

receive a response to the request in the 

January 30, 2004 NPR for information 

on an appropriate value for a potential 

transfer ratio. While the EPA did receive 

one comment that recommended the use 

of a trading ratio of two NOX allowances 

for one SO2 allowance, no comments 

presented supporting analysis that 

could be used to develop transfer ratios. 

While many commenters supportive 

of allowing interpollutant trading in the 

CAIR claimed that it would provide 

additional compliance flexibility to 

sources, the EPA contends that use of 

the newly created CAIR trading markets 

is sufficiently flexible. Sources may 

develop integrated, multi-pollutant 

control strategies and use the separate 

allowance markets to mitigate 

differences in control costs (within the 

boundaries of emissions caps). In other 

words, a source can choose the level to 

which they can cost effectively control 

one pollutant and, if necessary, buy or 

sell emission allowances of the other 

pollutant to compensate for any 

expensive or inexpensive control cost. 

When markets are used to provide for 

trading of multiple pollutants, sources 

benefit from the additional compliance 

flexibility while the caps assure the 

achievement of the overarching 

environmental goals. 

In the June 10, 2004 SNPR, the EPA 

solicited comment on how an 

interpollutant trading mechanism might 

accommodate the slightly different 

geographic regions found to be 

significant contributors for PM2.5 and 

ozone under the CAIR. No commenters 

provided supporting analysis or input 

on this issue. 

In summary, the EPA received 

comments that generally opposed 

including a specific interpollutant 

trading mechanism. No commenters 

provided analysis to demonstrate the 

benefit of including a specific 

interpollutant trading mechanism nor 

was there analysis provided in response 

to the EPA’s solicitation in the June 10, 

2004 SNPR for input on: Transfer ratios, 

addressing two different environmental 

issues, and having slightly different 

annual NOX and ozone season NOX

control regions. Furthermore, because 

the NOX and SO2 markets provide very 

flexible mechanisms for trading of the 

two pollutants, the EPA does not believe 

there is a compelling need to go further 

at this time. Therefore, EPA is not 

finalizing provisions in the CAIR model 

rules that specifically address 

interpollutant trades. 

F. Are There Incentives for Early 

Reductions? 

When sources reduce their SO2 and 

NOX emissions prior to the first phase 

of a multi-phase cap and trade program, 

it creates the emissions ‘‘glide slope’’ of 

a cap and trade approach that provides 

early environmental benefit and lowers 

the cost of compliance. Early reduction 

credits (ERCs) can provide an incentive 

for sources to install and/or operate 

controls before the implementation 

dates. Allowing emission allowances 

from existing programs to be used for 

compliance in the new program is 

another mechanism to encourage early 

reductions prior to the start of a cap and 

trade program. This section discusses 

the potential use of mechanisms to 

provide incentives for early reductions 

in the CAIR. 

1. Incentives for Early SO2 Reductions 

a. The CAIR NPR and SNPR Proposal for 

the Model Rules and Input From 

Commenters

The January 30, 2004 CAIR NPR and 

June 10, 2004 CAIR SNPR acknowledge 

the benefit of early reductions and 

provide for the use of title IV SO2

allowances of vintage years 2009 and 

earlier to be used for compliance in the 

CAIR at a one-to-one ratio. In other 

words, title IV allowances can be 

banked into the CAIR Program. This 

provides incentive for title IV sources to 

reduce their emissions in years 2009 

and earlier because these allowances 

may be used for CAIR compliance 

without being discounted by the 

retirement ratios applied to the 2010 

and later SO2 allowances. No other 

mechanism, such as SO2 ERCs were 

proposed by the EPA. 

Comments Regarding the Incentives for 

Early SO2 Reductions 

The EPA received comments on 

incentives for early SO2 reductions with 

the majority supporting the EPA 

proposal to encourage early emission 

reductions by allowing the CAIR 

sources to use 2009 and earlier vintage 

title IV SO2 allowances for CAIR 

compliance. Some supporters noted 

concerns in meeting the CAIR’s 

stringent Phase I SO2 requirements as 

another reason to allow the banking of 

undiscounted, title IV allowances into 

the CAIR. 

Some commenters expressed concern 

that achieving the SO2 caps would be 

delayed if a large number of SO2

allowances were being banked into the 

CAIR. Based upon experience with 

implementing the Acid Rain Program, 

the EPA acknowledged in the SNPR that 

crediting early reductions does create a 

glide slope—where emissions are 

reduced below the baseline before the 

implementation date and ‘‘glide’’ down 

to the ultimate cap level sometime after 

the program begins. This gradual 

reduction in emissions is a key 

component to cap and trade programs 

having lower cost of compliance than 

command-and-control approaches. One 

commenter proposed that the EPA 

needs to assess the likelihood that 

allowing the banking of undiscounted 

title IV allowances would delay the 

attainment of the Phase I SO2 cap until 

Phase II. Because the EPA included this 

mechanism (i.e., the use of 2009 and 

earlier vintage SO2 allowances for 

compliance in the CAIR) in the policy 

case modeled as part of this rulemaking, 

EPA analysis includes the benefits and 

costs that would result from the level of 

SO2 reductions that would take place 

with banking of undiscounted title IV 

allowances. 

One commenter advocated the use of 

SO2 ERCs. It was not clear whether 

these would be awarded in addition to 

banking title IV allowances into the 

CAIR or the ERC mechanism would take 

the place of banking SO2 allowances 

into the CAIR. 

b. SO2 Early Reduction Incentives in the 

Final CAIR Model Rules 

The CAIR SO2 model rule allows 

CAIR sources to use title IV SO2

allowances of vintage 2009 and earlier 

for compliance with the CAIR at a oneto-one ratio. This approach was part of 

the CAIR policy case assumptions used 

in the rulemaking modeling and the 

EPA has shown that the SO2 cap and 

trade program, with this early incentive 

mechanism, will achieve the level of 

SO2 reductions needed to meet the CAIR 

goals. These reductions take place on a 

glide slope that includes early emissions 

reductions as well as some use of the 

SO2 allowance bank as sources 

gradually reduce emissions toward the 

cap levels. 

The EPA did not include SO2 ERCs 

because the Acid Rain Program cap and 

trade program, which affects a large 

segment of the CAIR source universe, 

makes it impossible to determine 

whether sources are reducing their SO2

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25285

emissions below levels required by 

existing (i.e., the Acid Rain Program) 

programs. Furthermore, given that most 

sources with substantial emissions 

receive SO2 emission allowances under 

the Acid Rain Program, a significant 

number of SO2 allowances are expected 

to be banked into the CAIR. These 

banked allowances would be available 

to CAIR sources in the early years of the 

program and make ERCs largely 

unnecessary. 

2. Incentives for Early NOX Reductions 

a. The CAIR NPR and SNPR Proposal for 

the Model Rules and Input From 

Commenters 

In the June 10, 2004 SNPR, the EPA 

proposed to provide incentives for early 

NOX reductions by allowing the use of 

NOX SIP Call allowances of vintage 

2009 and earlier to be used for 

compliance in the CAIR. Further, the 

EPA did not propose, but solicited 

comment on the potential use of NOX

ERCs to provide an additional incentive 

for sources to reduce NOX emissions 

prior to CAIR implementation. In 

addition to the general solicitation for 

comment on NOX ERCs, the EPA 

solicited input on the following specific 

approaches that could be utilized: (1) 

The EPA could maintain the NOX SIP 

Call requirements and allow sources to 

use ERCs only for compliance with the 

annual limitation, to ensure that ozoneseason NOX limitations are met. Under 

this scenario, the additional States 

subject to the CAIR that have been 

found to significantly contribute to 

ozone nonattainment may also have to 

be included in the ozone season cap; (2) 

the EPA could limit the period of time 

during which ERCs could be created 

and banked; (3) the EPA could cap the 

amount of ERCs that can be created; and 

(4) the EPA could apply a discount rate 

to ERCs. 

Comments Regarding the Incentives for 

Early NOX Reductions 

The EPA did not receive comment on 

the proposed use of NOX SIP Call 

allowances of vintage years 2009 and 

earlier for compliance in the CAIR. In 

fact, several commenters characterized 

the CAIR proposal as not including any 

incentives for early NOX emissions 

reductions.

The EPA received several comments 

on the potential use of NOX ERCs with 

the majority in favor of some sort of ERC 

mechanism. Several commenters 

advocated the use of ERCs to mitigate 

concerns that they would not be able to 

meet the stringent Phase I CAIR 

reduction requirements. One commenter 

wanted early reductions to facilitate the 

ozone attainment in 2010 but believed 

2010 attainment could only be helped if 

there were some restrictions on the 

number of ERCs that could be created. 

Some ERC supporters wanted credit 

for wintertime emissions reductions 

only, while a few believed that credit 

should be given for reductions at any 

time of year. One commenter advocated 

providing ERCs for wintertime 

reductions only as part of a broader 

proposal to create a bifurcated NOX

trading system (i.e., separate wintertime 

and summertime allowances and 

trading markets). 

Many of the commenters supporting 

the use of ERCs advocated that they be 

distributed from a pool of allowances 

similar to the CSP used in the NOX SIP 

Call. (The NOX SIP Call CSP was a fixed 

pool of NOX allowances that were 

distributed on a first come-first serve, 

prorated, or need basis, depending upon 

the State). Commenters noted that the 

CSP approach has already been part of 

a litigated rulemaking and provides the 

added benefit of limiting the total 

number of allowances that can be 

distributed for early reductions. Other 

commenters proposed that should the 

final approach use a pool of allowances, 

this pool should not remove allowances 

from the existing State NOX budget. 

Another commenter suggested that 

allowances from a CSP could be 

distributed based upon a NOX emission 

rate, such as 0.25 lbs/mmBtu. 

Allowances could be distributed to any 

source emitting below the target 

emission rate. 

Several commenters were concerned 

that too many NOX ERCs (as well as 

NOX SIP Call allowances) could be 

introduced into the CAIR and the ability 

of the NOX cap and trade program to 

meet the annual and ozone-season 

reduction goals could be compromised. 

Some commenters suggested that 

crediting early reductions at a discount 

(e.g., 2 tons of NOX reductions earn 1 

ERC) could mitigate this concern. Other 

commenters noted that a CSP-style 

mechanism also provides safeguards 

against an overabundance of ERCs. 

Another commmenter noted that 

restrictions on the use of ERCs similar 

to the progressive flow control (PFC) 

mechanism used in the NOX SIP Call—

PFC restricts the use of banked NOX

allowances for compliance in years 

where the NOX bank is greater than 10 

percent of the allocations—could help 

to ease concerns of flooding the market 

with NOX ERCs. 

One commenter believed that the 

EPA’s projection that the potential pool 

of NOX ERCs could be as large as 3.7 

million tons (presented in the June 10, 

2004 SNPR) is unrealistically high. The 

commenter contended that technical 

limitations of Selective Catalytic 

Reduction (SCR) operation would not 

permit facilities to simply run all of 

their SCRs year-round. More 

specifically, the commenter believes the 

lower operating loads, typically of the 

wintertime dispatch, would not meet 

the minimum conditions necessary for 

SCR operation (i.e., at lower capacity the 

stack gas temperatures will not support 

the use of the catalyst). Fewer 

wintertime opportunities to operate the 

SCRs is believed by the commenter to 

result in a smaller projected ERC 

estimate. This was an estimate used for 

discussion purposes and was not 

directly used in the development of the 

CSP. 

A few commenters advocated 

providing credits to any source that 

reduced emission rates below those 

used to determine the CAIR State 

budgets. One commenter suggested that 

the rates be based on those rates used to 

determine the NOX SIP Call caps. 

A few commenters proposed that the 

EPA should develop a strategy for 

crediting NOX reductions from sources 

that have implemented control 

measures in response to State-level 

regulations that are more stringent than 

the NOX SIP Call. Another commenter 

advocated only providing ERCs in States 

subject to both the NOX SIP Call and the 

CAIR.

Some commenters did not support the 

use of NOX ERCs in any form. These 

commenters believe that the use of ERCs 

would delay attainment of the CAIR 

emission caps. 

b. NOX Early Reduction Incentives in 

the Final CAIR Model Rules 

The CAIR ozone-season NOX cap and 

trade rule will allow the proposed use 

of NOX SIP Call allowances of vintage 

years 2008 and earlier for compliance in 

the CAIR. This mechanism would 

provide incentive for sources in NOX

SIP Call States to reduce their ozoneseason NOX emissions and bank 

additional allowances into the CAIR. 

Because today’s final ozone-season cap 

and trade rule includes a mandatory 

ozone-season NOX cap in 2009 (this 

modification is discussed in section IV), 

the provisions to allow the banking of 

NOX SIP Call allowances into the CAIR 

are adjusted to reflect this 

implementation date. 

The CAIR annual NOX cap and trade 

rule will provide additional incentives 

for early annual NOX reductions by 

creating a CSP for CAIR States from 

which they can distribute allowances 

for early, surplus NOX emissions 

reductions in the years 2007 and 2008. 

The earning of CAIR CSP allowances for 

25286 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

136The 200,000 ton pool includes the 1,503 tons 

that would be DE and NJ’s share. Section V of 

today’s action describes in detail the State-by-State 

apportionment of the total CSP.

NOX emission reductions does not begin 

until 2007 because this is the first year 

after the State SIP submittal deadlines. 

The CAIR CSP will provide a total of 

200,000 136 CAIR annual NOX

allowances of vintage 2009 in addition 

to the annual CAIR NOX budgets.

The CAIR’s CSP is patterned after the 

NOX SIP Call’s CSP, which is part of an 

established and extensively litigated 

rulemaking. Similarities include: 

Limiting the total number of allowances 

that can be distributed; limiting the 

years in which CSP allowances can be 

earned; populating the CSP with 

allowances vintaged the first 

compliance year; and using distribution 

criteria of early reductions and need. 

The EPA will apportion the CSP to 

the States based upon their share of the 

final, regionwide NOX CAIR reductions. 

Similar to the NOX SIP Call, States may 

distribute these CAIR NOX allowances 

to sources based upon either: (1) A 

demonstration by the source to the State 

of NOX emissions reductions in surplus 

of any existing NOX emission control 

requirements; or (2) a demonstration to 

the State that the facility has a ‘‘need’’

that would affect electricity grid 

reliability. Sources that wish to receive 

CAIR CSP allowances based upon a 

demonstration of surplus emissions 

reductions will be awarded one CAIR 

annual NOX allowance for every ton of 

NOX emissions reductions. (Should a 

State receive more requests for 

allowances than their share of the CAIR 

CSP, the State would pro-rate the 

allowance distribution.) Determination 

of surplus emissions must use emissions 

data measured using part 75 monitoring. 

The EPA elected to include the CSP 

in response to several comments noting 

the benefit of early NOX reductions and 

some commenters concerns in 

complying with the stringent Phase I 

CAIR NOX cap. While EPA analysis has 

shown that sources had sufficient time 

to install NOX emission controls, the 

EPA does believe that it would be 

appropriate to provide some mechanism 

to alleviate the concerns of some 

sources which may have unique issues 

with complying with the 2009 

implementation deadline. In addition to 

mitigating some of the uncertainty 

regarding the EPA projections of 

resources to comply with CAIR, the 

CAIR CSP also effectively provides 

incentives for early, surplus NOX

reductions. 

The EPA agrees with the comments 

that advocate allowing sources to earn 

CAIR annual NOX allowances only for 

those reductions that are in surplus of 

the sources’ existing NOX reduction 

requirements. By allowing sources in 

NOX SIP Call and non-NOX SIP Call 

States to demonstrate that their yearround early reductions are truly 

‘‘surplus’’ and, therefore, deserving of 

CSP allowances, the EPA is responding 

to comments that the EPA should allow 

sources in non-NOX SIP Call States to 

receive credit for early reductions. Some 

commenters advocated crediting sources 

in the ozone-season NOX cap and trade 

program that emitted below the 

emission rate used to determine the 

ozone-season budget. The EPA did not 

accept this recommendation because a 

source that is allowed to bank NOX SIP 

Call allowances into the CAIR ozoneseason NOX program and receive early 

reduction credit from CAIR’s CSP would 

be essentially ‘‘double-counting’’ that 

emission reduction.

The EPA did not restrict the use of the 

NOX allowances awarded from the CSP 

because several aspects of the CSP 

already address concerns that too many 

total credits would be distributed and 

that they would flood the markets. First, 

the CSP is a finite pool of NOX

allowances. Second, by requiring 

sources to reduce one ton of NOX

emissions for every NOX allowance 

awarded from the CSP ensures that 

significant reductions are made prior to 

the CAIR implementation date. 

G. Are There Individual Unit ‘‘Opt-In’’

Provisions? 

In the SNPR, EPA described a 

potential approach for allowing certain 

units to voluntarily participate in, or 

‘‘opt-in,’’ to the CAIR. Originally, EPA 

proposed to have no opt-in provision 

but included language in the SNPR on 

what a potential opt-in provision may 

look like. This ‘‘potential’’ opt-in 

provision would have allowed non-EGU 

boilers and turbines that exhaust to a 

stack or duct and monitor and report in 

accordance with part 75 to opt into the 

CAIR. The opt-in unit would have been 

required to opt-in for both SO2 and 

NOX. The allocation method for opt-ins 

assumed a percentage SO2 reduction 

from a baseline and for NOX, allocations 

were equal to a baseline heat input 

multiplied by a specified NOX

emissions rate, the same NOX emissions 

rate EGUs were subject to in the 

assumed EGU budgets. Allocations were 

updated annually and after opting in 

units would have had to stay in the 

CAIR for a minimum of 5 years. The 

EPA received many comments in favor 

of and very few comments against 

including an opt-in provision in the 

final rule. As a result, EPA is including 

an opt-in provision in this final rule that 

is based on the approach described in 

the SNPR but includes several 

modifications and additions in response 

to comments as described below. In 

general, EPA believes there is value to 

including an opt-in provision but 

believes that sources that opt-in should 

be responsible for a certain level of 

reduction below its baseline because of 

the additional flexibility provided to 

that source by opting into a regional 

trading program and because of the 

possibility that participation in the 

CAIR may reduce or eliminate future 

potential required reductions. 

Therefore, the following opt-in 

approach has as its goals to provide 

more flexibility to the units opting in as 

well as to potentially provide more costeffective reductions for the affected 

EGUs but also to ensure a certain level 

of reduction from the units opting into 

the program. 

1. Applicability 

Some commenters suggested that the 

opt-in provision not be limited to 

boilers and turbines but should be open 

to any unit. The EPA strongly believes 

that any unit participating in an 

emissions trading program be subject to 

accurate and reliable monitoring and 

reporting requirements. This is the 

purpose of part 75. The EPA has 

developed criteria for boilers and 

turbines to satisfy the requirements of 

part 75 but has not developed criteria 

for all non-boilers and turbines and, 

therefore, cannot be confident their 

emissions can be monitored with the 

high degree of accuracy and reliability 

required by a cap-and-trade program. 

Continuous Emissions Monitoring 

Systems or ‘‘CEMS’’ are typically what 

is required by EPA to participate in a 

cap-and-trade program. 

In response to comments received 

suggesting that non-boilers and turbines 

be allowed to opt-in, EPA is expanding 

applicability of the opt-in provision to 

include, in addition to boilers and 

turbines, other fossil fuel-fired 

combustion devices that vent all 

emissions through a stack and meet 

monitoring, recordkeeping, and 

recording requirements of part 75.

2. Allowing Single Pollutant 

Some commenters suggested that 

sources should be allowed to opt-in for 

only one pollutant instead of requiring 

the source to opt-in for both SO2 and 

NOX as EPA proposed. These 

commenters argued that some sources 

may only emit significant amounts of 

one of the two regulated pollutants and 

that it would not make sense to require 

reductions in both pollutants from such 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25287

a source. The EPA agrees with this 

comment and will allow units to opt-in 

for one pollutant, i.e., NOX, SO2, or 

both. Another commenter suggested that 

EPA allow non-EGUs subject to the NOX

SIP Call to opt into the CAIR for NOX

only without requiring any reductions 

in SO2. This commenter argued that 

these non-EGUs could simply turn on 

their SCRs during the non-ozone season 

and easily achieve significant NOX

reductions. The EPA agrees that the 

relatively small number of non-EGUs 

subject to the NOX SIP Call that have 

SCRs could achieve significant NOX

reductions by operating their SCRs 

during the non-ozone season. As stated 

above, EPA is allowing sources to optin for one pollutant and thus non-EGUs 

subject to the NOX SIP call may opt-in 

for NOX only. 

3. Allocation Method for Opt-Ins 

In the SNPR, EPA proposed allocating 

allowances to opt-in units on a yearly 

basis. The amount of allowances 

allocated would be calculated by 

multiplying an emission rate by the 

lesser of a baseline heat input or the 

actual heat input monitored at the unit 

in the prior year. 

The baseline heat input would be 

calculated by using the most recent 3 

years of quality-assured part 75 

monitoring data. When less than 3 years 

of quality-assured part 75 monitoring 

data is available, the heat input would 

be based on quality-assured part 75 

monitoring data from the year before the 

unit opted in. 

For SO2, EPA proposed that the 

emission rate used to calculate 

allocations would be the lesser of, the 

most stringent State or Federal SO2

emission rate that applied in the 

preceding year or the emission rate 

representing 50 percent of the unit’s 

baseline SO2 emission rate (in lbs/

mmBtu) for the years 2010 through 2014 

and 35 percent of the unit’s baseline 

SO2 emission rate (in lbs/mmBtu) for 

2015 and beyond. For NOX, EPA 

proposed that the emission rate would 

be the lower of the unit’s baseline 

emission rate, the most stringent State 

or Federal NOX emission limitation that 

applies to the opt-in unit at any time 

during the calender year prior to opting 

into the CAIR Program, or 0.15 lb/

mmBtu for the years 2010 through 2014 

and 0.11 lbs/mmBtu for the years 2015 

and beyond. 

In today’s final rule, EPA is making a 

number of changes to its proposed 

methodology for calculating allocations 

for opt-in units. 

With regards to baseline heat input, 

EPA is requiring that sources may only 

use part 75 monitored data for years in 

which they have maintained at least a 

90 percent monitor availability. The 

EPA is making this change because part 

75 contains missing data provisions that 

require substitution of data when 

monitors are unavailable. When units 

have low monitor availability, units are 

required to report more conservative 

(e.g., higher) heat input values. This is 

to provide an incentive to maintain high 

monitor availability (since under a cap 

and trade program sources would be 

required to turn in more allowances if 

they reported higher emissions). When 

setting baselines, sources have the 

opposite incentive, reporting a higher 

heat input would result in a higher 

baseline and thus a greater allocation. 

With regards to the SO2 emission rate 

used to calculate allocations, EPA is 

requiring that the emission rate used to 

calculate allocations would be the lesser 

of, the most stringent State or Federal 

SO2 emission rate that applies to the 

unit in the year that the unit is being 

allocated for, or the emission rate 

representing 70 percent of the unit’s 

baseline SO2 emission rate (in lbs/

mmBtu). The EPA is changing the 

percentage emission reduction upon 

which allocations are based because 

some commenters suggested that instead 

of using percentage emission reduction 

requirements that are the same as the 

requirements for EGUs as a basis for 

allocating to opt-ins, EPA should 

require emissions reductions based on 

similar marginal cost of control. The 

EPA agrees with the basic concept that 

emissions reductions for opt-ins should 

be based on similar marginal costs. One 

commenter submitted results from a 

study of industrial boiler NOX and SO2

control costs that indicated the use of 

similar marginal cost of control would 

result in approximately a 30 percent 

reduction in NOX and SO2 by 2010. 

While the commenter provided limited 

data to allow EPA to evaluate the 

commenter’s estimates, EPA is using 

this percentage reduction requirement 

for the opt-in provision. The same 

commenter stated that it may be 

possible to achieve more than a 30 

percent reduction in SO2 and NOX by 

2015 by employing future unspecified 

technology advances. Because these 

future technology advances are not 

specified nor demonstrated, EPA is not 

requiring more than a 30 percent 

reduction in SO2 and NOX in 2015 and 

beyond for opt-ins. The EPA is changing 

the requirement to use the lowest 

required emission rate for the year 

preceding the year in which allowances 

are being allocated to the lowest 

emission rate for the year in which 

allowances are being allocated. The EPA 

is making this change because EPA 

believes that such data should be 

available and that this more accurately 

reflects the intent of the rule to ensure 

that the source is not being allocated a 

greater number of allowances than the 

emissions a source would be allowed to 

emit under the regulations it is subject 

to in the year the allocations are being 

made. The EPA is finalizing parallel 

provisions with respect to NOX.

4. Alternative Opt-In Approach 

Some commenters suggested that EPA 

include an alternative approach to 

opting into the CAIR. This alternative 

would allow units to opt-in as early as 

2009 for NOX and 2010 for SO2 and 

receive allocations at their current 

emission levels in return for a 

commitment to make deeper reductions 

by 2015 than would be required under 

the general opt-in provision described 

above. Therefore, for the years 2010 

through 2014, the unit would be 

allocated allowances based on the same 

heat input used under the general optin provision (e.g., the lesser of the 

baseline heat input or the heat input for 

the year preceding the year in which 

allocations are being made) multiplied 

by an emission rate. This emission rate 

would be the lower of the emission rate 

for the year or years before the unit 

opted in or the most stringent State or 

Federal emission rate required in the 

year that the unit opts in. For SO2 for 

the years 2015 and beyond, the unit 

would be allocated allowances based on 

the same heat input multiplied by an 

emission rate. This emission rate would 

be the lower of a 90 percent reduction 

from the baseline emission rate or the 

most stringent State or Federal emission 

rate required in the baseline year. For 

NOX, the same methodology would be 

used, except that the emission rate used 

for the years 2015 and beyond would be 

the lower of 0.15 lbs/mmBtu or the most 

stringent State or Federal emission rate 

required in the baseline year. The EPA 

believes the environmental benefit of 

achieving deeper emissions reductions 

in the future (2015) from sources that 

may otherwise not make such deep 

emissions reductions is worth including 

in this final rule. 

5. Opting Out 

In the SNPR, EPA proposed that optin units be required to remain in the 

program a minimum of 5 years after 

which time they could voluntarily 

withdraw from the CAIR. Some 

commenters expressed concern over this 

proposed approach, arguing that 

because EGUs affected by the CAIR are 

not allowed to voluntarily withdraw 

from the CAIR that opt-in sources 

should not be allowed to voluntarily 

25288 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

withdraw either. The EPA recognizes 

that opt-in sources such as industrial 

boilers and turbines tend to be more 

sensitive to changing market forces than 

EGUs. As a result, EPA believes it is 

appropriate to allow opt-in sources who 

voluntarily participate in an emissions 

reductions program to be able to end 

their participation or (‘‘opt-out’’) after a 

specified period of time. As proposed, 

EPA believes a period of 5 years is 

appropriate and is finalizing a rule to 

allow opt-in sources to opt-out after 

participating in the CAIR for 5 years. 

This option to opt-out after 5 years does 

not apply to sources that opt-in under 

the alternative approach. Sources that 

opt-in under the alternative approach 

may not opt-out at any time.

6. Regulatory Relief for Opt-In Units 

The CAIR does not offer relief from 

other regulatory requirements, existing 

or future, for units that opt-in to the 

CAIR cap and trade program. Any 

revision of requirements for other, nonCAIR programs would be done under 

rulemakings specific to those programs. 

As discussed above, EPA is including 

two different approaches for opt-in units 

to follow, a general and an alternative 

approach. The EPA is including both 

approaches in this final rule in response 

to comments supportive of including an 

alternative means and to provide greater 

flexibility for sources to participate in 

the CAIR trading program. Opt-in 

sources may select which approach is 

more appropriate for their particular 

situation. An opt-in source may not 

switch from one approach to the other 

once in the program. States have the 

flexibility to choose to include both of 

these approaches, one of these 

approaches, or none of them in their 

SIPs. EPA is not requiring States to 

include an individual unit opt-in 

provision because the participation of 

individual opt-in units is not required to 

meet the goals of the CAIR. However, 

States cannot choose to have an 

individual unit opt-in approach 

different than what EPA has finalized in 

this rule and still participate in the 

inter-State trading program 

administered by EPA. 

H. What Are the Source-Level Emissions 

Monitoring and Reporting 

Requirements? 

In the NPR, the EPA proposed that 

sources subject to the CAIR monitor and 

report NOX and SO2 mass emissions in 

accordance with 40 CFR part 75. 

The model trading rules incorporate 

part 75 monitoring and are being 

finalized as proposed. The majority of 

CAIR sources are measuring and 

reporting SO2 mass emissions year 

round under the Acid Rain Program, 

which requires part 75 monitoring. Most 

CAIR sources are also reporting NOX

mass emissions year round under the 

NOX SIP Call. The CAIR-affected Acid 

Rain sources that are located in States 

that are not affected by the NOX SIP Call 

currently measure and report NOX

emission rates year round, but do not 

currently report NOX mass emissions. 

These sources will need to modify only 

their reporting practices in order to 

comply with the proposed CAIR 

monitoring and reporting requirements. 

Because so many sources are already 

using part 75 monitoring, there were 

very few comments on the source-level 

monitoring requirements in this 

rulemaking. The comments the EPA 

received related to sources not currently 

monitoring under part 75. Commenters 

suggested that alternative forms of 

monitoring (e.g., part 60 monitoring) 

would be appropriate for these sources. 

The EPA disagrees. Consistent, 

complete and accurate measurement of 

emissions ensures that each allowance 

actually represents one ton of emissions 

and that one ton of reported emissions 

from one source is equivalent to one ton 

of reported emissions from another 

source. Similarly, such measurement of 

emissions ensures that each single 

allowance (or group of SO2 allowances, 

depending upon the SO2 allowance 

vintage) represents one ton of emissions, 

regardless of the source for which it is 

measured and reported. This establishes 

the integrity of each allowance, which 

instills confidence in the underlying 

market mechanisms that are central to 

providing sources with flexibility in 

achieving compliance. Part 75 has 

flexibility relating to the type of fuel and 

emission levels as well as procedures 

for petitioning for alternatives. The EPA 

believes this provides the requested 

flexibility. 

Should a State(s) elect to use the 

example allocation approach, the EPA 

would modify the part 75 monitoring 

and reporting requirements to collect 

information used in determining the 

allowance allocations for Combined 

Heat and Power (CHP) units. More 

specifically, provisions for the 

monitoring and reporting of the BTU 

content of the steam output would be 

added to the existing requirements. The 

information on electricity output 

currently reported under part 75 would 

not need to be revised to allow States to 

implement the example allowance 

allocation approach. 

In the SNPR, the EPA proposed 

continuous measurement of SO2 and 

NOX emissions by all existing affected 

sources by January 1, 2008 using part 75 

certified monitoring methodologies. 

New sources have separate deadlines 

based upon the date of commencement 

of operation, consistent with the Acid 

Rain Program. These deadlines are 

finalized as proposed. 

I. What Is Different Between CAIR’s 

Annual and Seasonal NOX Model Cap 

and Trade Rules? 

Today’s action finalizes not only the 

proposed CAIR annual NOX program 

and annual SO2 program, but also a 

CAIR ozone-season NOX program. 

Because the CAIR ozone-season NOX

program is the only ozone-season NOX

cap and trade program that the EPA will 

administer, NOX SIP Call States wishing 

to meet their NOX SIP Call obligations 

through an EPA-administered regional 

NOX program will also use the CAIR 

ozone-season rule. The EPA believes 

that States and affected sources will 

benefit from having a single, consistent 

regional NOX cap and trade program. 

This section of today’s action highlights 

any key differences between the CAIR 

ozone-season NOX model rule and the 

NOX SIP Call model rule, as well as the 

CAIR annual and ozone-season NOX

model rules.

Differences Between the CAIR OzoneSeason NOX Model Rule and the NOX

SIP Call Model Rule 

While the CAIR ozone-season NOX

model rule closely mirrors the NOX SIP 

Call rule (as does the other CAIR rules), 

the EPA has incorporated into the CAIR 

model rules its experience with 

implementing trading programs 

(including seasonal NOX programs). 

These modifications include the 

following. 

A. Unrestricted banking: The CAIR 

ozone-season NOX model rule will not 

include any restrictions on the banking 

of NOX SIP Call allowances (vintages 

2008 and earlier) or CAIR ozone-season 

NOX allowances. The NOX SIP Call 

rules include ‘‘progressive flow control’’

provisions that reduce the value of 

banked allowances in years where the 

bank is above a certain percentage of the 

cap. (See section VIII.E.1 of today’s rule 

for a detailed discussion). 

B. Facility level compliance: The 

CAIR ozone-season NOX model rule will 

allow sources to comply with the 

allowance holding requirements at the 

facility level. The NOX SIP Call rules 

required unit-by-unit level compliance 

with certain types of allowance 

accounts providing some flexibility for 

sources with multiple affected units. 

(See the June 2004 SNPR, section IV for 

a detailed discussion).

The EPA believes that these changes 

improve the programs and that both 

CAIR and NOX SIP Call affected sources 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25289

will benefit from complying with a 

single, regionwide cap and trade 

program. 

Differences Between the CAIR OzoneSeason and Annual NOX Model Rules 

The CAIR ozone-season and annual 

NOX model rules are designed to be 

identical with the exception of (1) 

provisions that relate to compliance 

period and (2) the mechanism for 

providing incentives for early NOX

reductions. For compliance related 

provisions, the EPA attempted to 

maintain as much consistency as 

possible between the CAIR annual and 

ozone-season NOX model rules. For 

example, reporting schedules remain 

synchronized (i.e., quarterly reporting) 

for both of the CAIR NOX model rules. 

For the annual and ozone-season NOX

model rules, the EPA did define 12 

month and 5 month compliance 

periods, respectively. 

Incentives for early NOX reductions 

differ between the CAIR annual and 

ozone-season programs. For the annual 

NOX program, early reductions may be 

rewarded by States through a CSP. (See 

section VIII.F.2 of today’s action for a 

detailed discussion.) The CAIR ozoneseason NOX model rule provides 

incentive for early emissions reductions 

by allowing the banking of pre-2009 

NOX SIP Call allowances into the CAIR 

ozone-season program. 

J. Are There Additional Changes to 

Proposed Model Cap and Trade Rules 

Reflected in the Regulatory Language? 

The proposed and final rules are 

modeled after, and are largely the same 

as, the NOX SIP Call model trading rule. 

Today’s final rule includes some 

relatively minor changes to the model 

rules’ regulatory text that improve the 

implementability of the rules or clarify 

aspects of the rules identified by the 

EPA or commenters. (Note that sections 

VIII.B through VIII.H of today’s action 

highlight the more significant 

modifications included in the final 

model rules). 

One example of a relatively minor 

change is the inclusion of language in 

the SO2 model rule that implements the 

retirement ratio (2.00) used for 

allowances allocated for 2010 to 2014 

and the retirement ratio (2.86) used for 

allowances allocated for 2015 and later, 

that clarifies the compliance deduction 

process and that provides for roundingup of fractional tons to whole tons of 

excess emissions. More specifically, the 

definition of ‘‘CAIR SO2 allowance’’

states that an allowance allocated for 

2010 to 2014 authorizes emissions of 

0.50 tons of SO2 and that an allowance 

allocated for 2015 or later authorizes 

emissions of 0.35 tons of SO2—which 

corresponds with the 2.86 retirement 

ratio.

Other, less significant modifications 

were also included in the regulatory text 

of the final model rules. These include: 

C. Units and sources are identified 

separately for NOX and SO2 programs 

(e.g., CAIR NOX units, CAIR Nox ozone 

season units, and CAIR SO2 units) since 

States can participate in one, two, or 

three trading programs; 

D. The definition of ‘‘nameplate 

capacity’’ is clarified; 

E. The language on closing of general 

accounts is clarified; and, 

F. Process of recordation of CAIR SO2

allowance allocations and transfers on 

rolling 30-year periods is added to make 

it consistent with Acid Rain regulations. 

Another example of where today’s 

final model trading rules incorporate 

relatively minor changes from the 

proposed model trading rules involves 

the provisions in the standard 

requirements concerning liability under 

the trading programs. The proposed 

CAIR model NOX and SO2 trading rules 

include, under the standard 

requirements in § 96.106(f)(1) and (2) 

and § 96.206(f)(1) and (2), provisions 

stating that any person who knowingly 

violates the CAIR NOX or SO2 trading 

programs or knowingly makes a false 

material statement under the trading 

programs will be subject to enforcement 

action under applicable State or Federal 

law. Similar provisions are included in 

§ 96.6(f)(1) and (2) of the final NOX SIP 

Call model trading rule. The final CAIR 

model NOX and SO2 trading rules 

exclude these provisions for the 

following reasons. First, the proposed 

rule provisions are unnecessary 

because, even in their absence, 

applicable State or Federal law 

authorizes enforcement actions and 

penalties in the case of knowing 

violations or knowing submission of 

false statements. Moreover, these 

proposed rule provisions are 

incomplete. They do not purport to 

cover, and have no impact on, liability 

for violations that are not knowingly 

committed or false submissions that are 

not knowingly made. Applicable State 

and Federal law already authorizes 

enforcement actions and penalties, 

under appropriate circumstances, for 

non-knowing violations or false 

submissions. Because the proposed rule 

provisions are unnecessary and 

incomplete, the final CAIR model NOX

and SO2 trading rules do not include 

these provisions. However, the EPA 

emphasizes that, on their face, the 

provisions that were proposed, but 

eliminated in the final rules, in no way 

limit liability, or the ability of the State 

or the EPA to take enforcement action, 

to only knowing violations or knowing 

false submissions. 

IX. Interactions With Other Clean Air 

Act Requirements

A. How Does This Rule Interact With the 

NOX SIP Call? 

A majority of States affected by the 

CAIR are also affected by the NOX SIP 

Call. This section addresses the 

interactions between the two programs. 

The EPA proposed that States 

achieving all of the annual NOX

reductions required by the CAIR from 

only EGUs would not need to continue 

to impose seasonal NOX limitations on 

EGUs from which they required 

reductions for purposes of complying 

with the NOX SIP Call. Also, EPA 

proposed that States would have the 

option of retaining such seasonal NOX

limitations. The EPA also proposed to 

keep the NOX SIP Call in place for nonEGUs currently subject to the NOX SIP 

Call and to continue working with 

States to run the NOX SIP Call Budget 

Trading Program for all sources that 

would remain in the program. In 

response to commenters, EPA is making 

several modifications to its proposed 

approach. 

States Affected by the CAIR for Ozone 

and PM2.5 Will Be Subject to a Seasonal 

and an Annual NOX Limitation 

A number of commenters 

recommended leaving the current NOX

SIP Call ozone season NOX limitation in 

place as a way to ensure that ozone 

season NOX reductions from EGUs 

required by the NOX SIP Call would 

continue to be achieved. Some 

commenters argued this would also help 

non-EGUs currently subject to the NOX

SIP Call by allowing them to continue 

trading with EGUs in a seasonal NOX

program. Many of the same commenters 

suggested a dual-season or bifurcated 

CAIR trading program as a mechanism 

for maintaining an ozone season NOX

limitation for EGUs under the CAIR. In 

response to these commenters, EPA is 

requiring that States subject to the CAIR 

for PM2.5 be subject to an annual 

limitation and that States subject to the 

CAIR for ozone be subject to an ozone 

season limitation. This means that 

States subject to the CAIR for both PM2.5

and ozone are subject to both an annual 

and an ozone season NOX limitation. 

The annual and ozone season NOX

limitations are described in section IV. 

States subject to the CAIR for ozone 

only are only subject to an ozone season 

NOX limitation. To implement these 

NOX limitations, EPA will establish and 

operate two NOX trading programs, i.e., 

25290 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

a CAIR annual NOX trading program 

and a CAIR ozone season NOX trading 

program. The CAIR ozone season NOX

trading program will replace the current 

NOX SIP Call as discussed in more 

detail later in this section. 

What Will Happen to Non-EGUs 

Currently in the NOX SIP Call? 

A number of commenters were 

concerned that the cost of compliance 

for non-EGUs in the NOX SIP Call 

would increase if they were not allowed 

to continue to trade with EGUs. In 

response to these commenters, EPA is 

modifying its proposed approach. The 

EPA is allowing States affected by the 

NOX SIP Call that wish to use EPA’s 

model trading rule to include non-EGUs 

currently covered by the NOX SIP Call 

in the CAIR ozone season NOX trading 

program. This will ensure that nonEGUs in the NOX SIP Call will continue 

to be able to trade with EGUs as they 

currently do under the NOX SIP Call. 

This will not require States to get 

additional reductions from non-EGUs. 

Budgets for these units would remain 

the same as they are currently under the 

NOX SIP Call. States will, however, be 

required to modify their existing NOX

SIP Call regulations to reflect the 

replacement of the NOX SIP Call with 

the CAIR ozone season NOX trading 

program. The EPA will continue to 

operate the NOX SIP Call trading 

program until implementation of the 

CAIR begins in 2009. The EPA will no 

longer operate the NOX SIP Call trading 

program after the 2008 ozone season 

and the CAIR ozone season NOX trading 

program will replace the NOX SIP Call 

trading program. If States affected by the 

NOX SIP Call do not wish to use EPA’s 

CAIR ozone season NOX trading 

program to achieve reductions from 

non-EGU boilers and turbines required 

by the NOX SIP Call, they would be 

required to submit a SIP Revision 

deleting the requirements related to 

non-EGU participation in the NOX SIP 

Call Budget Trading Program and 

replacing them with new requirements 

that achieve the same level of reduction.

Compliance With the NOX SIP Call for 

States That Are Subject to Both the 

CAIR Ozone Season NOX Reduction 

Requirements and the NOX SIP Call 

If the only changes a State makes with 

respect to its NOX SIP Call regulations 

are: (1) To bring non-EGUs that are 

currently participating in the NOX SIP 

Call Budget Trading Program into the 

CAIR ozone season program using the 

same non-EGU budget and applicability 

requirements that are in their existing 

NOX SIP Call Budget Trading Program; 

and (2) to achieve all of the emissions 

reductions required under the CAIR 

from EGUs by participating in the CAIR 

ozone season NOX trading program, EPA 

will find that the State continues to 

meet the requirements of the NOX SIP 

Call. 

If the only changes a State makes with 

respect to its NOX SIP Call regulations 

are not those described above, see 

section VII for a discussion of how the 

State would satisfy its NOX SIP Call 

obligations. 

States in the NOX SIP Call But Not 

Affected by the CAIR (Rhode Island) 

Rhode Island is the only State in the 

NOX SIP Call that is not affected by the 

CAIR. To continue meeting its NOX SIP 

Call obligations in 2009 and beyond, 

Rhode Island will have two choices. It 

may either modify its NOX SIP Call 

trading rule to conform to the new CAIR 

ozone season NOX trading rule if it 

wishes to allow its sources to continue 

to participate in an interstate NOX

trading program run by EPA or, it will 

need to develop an alternative method 

for obtaining the required NOX SIP Call 

reductions. In either case, Rhode Island 

must continue to meet the budget 

requirements of the existing NOX SIP 

Call. 

Use of Banked SIP Call Allowances in 

the CAIR Program 

As explained earlier in today’s final 

rule, banked allowances from the NOX

SIP Call may be used in the CAIR ozone 

season NOX trading program. 

Other Comments and EPA’s Responses 

One commenter wrote that because 

attainment demonstrations for early 

action compacts were made based on 

having EGUs and non-EGUs together in 

the NOX SIP Call, EPA could not allow 

EGUs to leave the NOX SIP Call and still 

have valid early action compacts 

(EACs). As discussed above, EPA is 

allowing States to keep EGUs and nonEGUs in the NOX SIP Call together in 

one ozone season program (CAIR ozone 

season trading program). The NOX

reductions required by the CAIR ozone 

season trading program are slightly 

more stringent than the reductions 

required by the NOX SIP Call. As a 

result, the attainment demonstrations 

for EACs would remain valid under the 

CAIR. Having said that, the EAC 

program will have ended (April 2008) 

before the CAIR rule is implemented. 

Thus, the compacts will no longer be 

applicable when the CAIR takes effect. 

Another commenter proposed to have 

non-EGUs under the NOX SIP Call 

subject to an annual NOX cap similar to 

EGUs under the CAIR so that non-EGUs 

could continue to trade with EGUs. By 

adopting a CAIR ozone season trading 

program that includes non-EGUs 

covered by the NOX SIP Call, non-EGUs 

will be able to continue to trade with 

EGUs. 

B. How Does This Rule Interact With the 

Acid Rain Program? 

As EPA developed this regulatory 

action, much consideration was given to 

interactions between the existing title IV 

Acid Rain Program and today’s action 

designed to achieve significant 

reductions in SO2 emissions beyond 

title IV. Requiring sources to reduce 

emissions beyond what title IV 

mandates has both environmental and 

economic implications for the existing 

title IV SO2 cap and trade program. In 

the absence of an approach for taking 

account of the title IV program, a new 

program (i.e., the CAIR) that imposes a 

significantly tighter cap on SO2

emissions for a region encompassing 

most of the sources and most of the SO2

emissions covered by title IV would 

likely result in a significant excess in 

the supply of title IV allowances, a 

collapse of the price of title IV 

allowances, disruption of operation of 

the title IV allowance market and the 

title IV SO2 cap and trade system, and 

the potential for increased SO2

emissions. The potential for increased 

emissions would exist in the entire 

country for the years before the CAIR 

implementation deadline and would 

continue after implementation for States 

not covered by the CAIR. These negative 

impacts, particularly those on the 

operation of the title IV cap and trade 

system, would undermine the efficacy 

of the title IV program and could erode 

confidence in cap and trade programs in 

general. 

Title IV has successfully reduced 

emissions of SO2 using the cap and 

trade approach, eliminating millions of 

tons of SO2 from the environment and 

encouraging billions of dollars of 

investments by companies in pollution 

controls to enable the sale of allowances 

reflecting excess emissions reductions 

and in allowance purchases for 

compliance. In view of these already 

achieved reductions and existing 

investments under title IV, the 

likelihood of disruption of the 

allowance market and the title IV cap 

and trade system, and the potential for 

SO2 emission increases, it is necessary 

to consider ways to preserve the 

environmental benefits achieved under 

title IV and maintain the integrity of the 

market for title IV allowances and the 

title IV cap and trade system. The EPA 

maintains that it is appropriate to 

provide States the opportunity to 

achieve the SO2 emission reductions 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25291

137The EPA’s interpretation is based on the 

language of section 403(f) and the legislative history 

of the provision. The language in CAA section 

403(f) contrasts with language that was in section 

503(f) of the House bill—but was excluded from the 

final version of the CAA Amendments of 1990—

referring to the authority of the ‘‘United States’’ to 

terminate or limit such authorization ‘‘by Act of 

Congress’’ and stating that ‘‘[a]llowances under this 

title may not be extinguished by the 

Administrator.’’ U.S. Senate Committee on 

Environment and Public Works, A Legislative 

History of The Clean Air Act Amendments of 1990

(Legis. Hist. of CAAA), S. Prt. 38, 103d Cong., 1st 

Sess., Vol. II at 2224 (Nov. 1993). Further, unlike 

CAA section 403(f), the House bill did not state that 

an allowance did not constitute a property right. 

Section 403(f) of the Senate bill that was 

considered, along with the House bill, in conference 

committee had language different than both CAA 

section 403(f) and the House bill and stated that 

‘‘allowances may be limited, revoked or otherwise 

modified in accordance with the provisions of this 

title or other authority of the Administrator’’ and 

that an allowance ‘‘does not constitute a property 

right.’’ Legis. Hist. of CAAA, Vol. III at 4598. While 

the scope of the reference to the ‘‘United States’’ in 

CAA section 403(f) is not clear, EPA maintains that 

the term is clearly broad enough to include the 

Administrator. Moreover, even if the term were 

considered ambiguous with regard to the 

Administrator, EPA believes that interpreting the 

term to include the Administrator is reasonable. 

Specifically, EPA maintains that, by eliminating the 

explicit House bill language that required 

Congressional action and including the general 

reference to the ‘‘United States’’ and the ‘‘not a 

property right’’ language, CAA section 403(f) 

Continued

required under today’s action by 

building on, and avoiding undermining, 

this existing, successful program. 

The EPA has developed, in the model 

SO2 cap and trade rule, an approach to 

build on and coordinate with the title IV 

SO2 program to ensure that the required 

reductions under today’s action are 

achieved while preserving the efficacy 

of the title IV program. The EPA’s 

approach provides States the 

opportunity to impose more stringent 

control requirements for EGUs’ SO2

emissions than under title IV through an 

EPA-administered cap and trade 

program that requires the use of title IV 

allowances for compliance at a ratio of 

2 allowances per ton of emissions for 

allowances allocated for 2010 through 

2014 and 2.86 allowances per ton of 

emissions for allowances allocated for 

2015 or thereafter. (The program also 

allows the use of banked title IV 

allowances allocated for years before 

2010 to be used at a ratio of 1 allowance 

per ton of emissions.) Title IV 

allowances continue to be freely 

transferable among sources covered by 

the Acid Rain Program and sources 

covered by the model SO2 cap and trade 

program under CAIR. However, each 

title IV allowance used to comply with 

a source’s allowance-holding 

requirement in the CAIR model SO2 cap 

and trade program is removed from the 

source’s allowance tracking system 

account and cannot be used again for 

compliance, either in the CAIR model 

SO2 cap and trade program or the Acid 

Rain Program.

In addition, as discussed above, if a 

State wants to achieve the SO2

emissions reductions required by 

today’s action through more stringent 

EGU emission limitations only but 

without using the model cap and trade 

program, then EPA is requiring that the 

State include in its SIP a mechanism for 

retiring the excess title IV allowances 

that will result from imposition of these 

more stringent EGU requirements. In 

this case, the State must retire an 

amount of title IV allowances equal to 

the total amount of title IV allowances 

allocated to the units in the State minus 

the amount of title IV allowances 

equivalent to the tonnage cap set by the 

State on SO2 emissions by EGUs, and 

the State can choose what retirement 

mechanism to use. 

Further, as discussed above, if a State 

wants to meet the SO2 emissions 

reductions requirement in today’s action 

through reductions by both EGUs and 

non-EGUs, then EPA is also requiring 

the State’s SIP to include a mechanism 

for retiring excess title IV allowances. In 

that case, the amount of title IV 

allowances that must be retired equals 

the total amount of title IV allowances 

allocated to the units in the State minus 

the amount of title IV allowances 

equivalent to the tonnage cap set by the 

State on EGU SO2 emissions, and the 

State can choose what retirement 

mechanism to use. 

Finally, as discussed above, if the 

State wants to achieve the SO2

emissions reductions requirement in 

today’s action through reductions by 

non-EGUs only, then EPA is not 

imposing any requirement to retire title 

IV allowances. 

1. Legal Authority for Using Title IV 

Allowances in CAIR Model SO2 Cap and 

Trade Program 

The EPA maintains that it has the 

authority to approve and administer, if 

requested by a State in the SIP 

submitted in response to today’s action, 

the new CAIR model SO2 cap and trade 

program meeting the SO2 emission 

reduction requirement in today’s action 

that requires use of title IV allowances 

to comply with the more stringent 

allowance-holding requirement of the 

new program and retirement under the 

CAIR SO2 cap and trade program and 

the Acid Rain Program of title IV 

allowances used for such compliance. 

Some commenters claim that EPA’s 

establishment of such a cap and trade 

program using title IV allowances that 

sources must hold generally at a ratio of 

greater than one allowance per ton of 

SO2 emissions is contrary to title IV. 

Most of these commenters prefer the 

approach of allowing States to use a 

new EPA-administered cap and trade 

program to meet lawful emission 

reduction requirements under title I and 

of allowing (but not requiring) sources 

to use title IV allowances in the new 

program. However, these commenters 

argue that title IV prohibits requiring 

sources to use title IV allowances in 

such a program, whether at the same 

tonnage authorization (i.e., one 

allowance per ton of emissions) 

established in title IV or at a different 

tonnage authorization. Other 

commenters state that title IV does not 

bar EPA from establishing a new cap 

and trade program that requires the use 

of title IV allowances. 

The EPA maintains that it has the 

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

title IV to establish a new cap and trade 

program requiring the use of title IV 

allowances at a different tonnage 

authorization than under the Acid Rain 

Program and the retirement of such 

allowances for purposes of both 

programs. First, as discussed in section 

V above, EPA has the authority under 

section 110(a)(2)(D) to establish a new 

SO2 cap and trade program, 

administered by EPA if requested in a 

State’s SIP, to prohibit emissions that 

contribute significantly to 

nonattainment, or interfere with 

maintenance, of the PM2.5 NAAQS. 

Further, EPA notes that under section 

402(3), a title IV allowance is:

An authorization, allocated to an affected 

unit by the Administrator under this title 

[IV], to emit, during or after a specified 

calendar year, one ton of sulfur dioxide. 42 

U.S.C. 7651(a)(3).

However, section 403(f) states that:

An allowance allocated under this title is 

a limited authorization to emit sulfur dioxide 

in accordance with the provision of this title 

[IV]. Such allowance does not constitute a 

property right. Nothing in this title [IV] or in 

any other provision of law shall be construed 

to limit the authority of the United States to 

terminate or limit such authorization. 

Nothing in this section relating to allowances 

shall be construed as affecting the 

application of, or compliance with, any other 

provision of this Act to an affected unit or 

source, including the provisions related to 

applicable National Ambient Air Quality 

Standards and State implementation plans. 

42 U.S.C. 7651b(f).

The EPA interprets the reference in 

section 403(f) to the authority of the 

‘‘United States’’ to terminate or limit the 

authorization otherwise provided by a 

title IV allowance to mean that EPA 

(acting in accordance with its authority 

under other provisions of the CAA), as 

well as Congress, has such authority.137

25292 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

essentially adopted the Senate’s approach and 

allows the United States—either through 

Congressional or administrative (i.e., EPA) action—

to terminate or limit the allowance authorization. 

See Legis. Hist. of CAAA, Vol. I at 754, 1034, and 

1084 (Oct. 27, 2000 floor statements of Sen. Symms, 

Sen. Baucus, and Sen. McClure indicating EPA has 

authority to take such action); but see Cong. Rec. 

at E 3672 (Nov. 1, 2000)(extension of remarks of 

Cong. Oxley indicating that only Congress has such 

authority).

138As discussed below, today’s action revises the 

Acid Rain Program regulations to provide for 

source-based, instead of unit-based, compliance 

with the allowance-holding requirement. These 

revisions are adopted for reasons independent of 

the adoption of the CAIR model SO2 cap and trade 

program, as well as to facilitate the coordination of 

these two SO2 trading programs.

139The commenters’ assertion that the sources in 

a State that does not participate in the CAIR SO2

cap and trade program will be cut off from the Acid 

Rain cap and trade program is incorrect on its face. 

Such a source will continue to be subject to the 

allowance-holding requirement and the compliance 

process in § 73.35 and will not be subject to the 

allowance-holding requirement and the compliance 

process in the CAIR model SO2 cap and trade rule.

140The commenters also seem to argue that the 

allowance definition itself bars EPA from requiring 

use of Acid Rain allowances in the CAIR SO2

trading program even on a one-allowance-per-tonof-emissions basis. However, as noted above, the 

definition is silent on whether title IV allowances 

may or may not be used outside the Acid Rain 

Program.

Therefore, EPA maintains that it has the 

authority to establish a new cap and 

trade program in accordance with 

section 110(a)(2)(D) that requires: the 

holding of title IV allowances under a 

more limited authorization (i.e., 2 or 

2.86 allowances per ton of emissions) by 

sources in States participating in the 

new program; and the termination of the 

authorization through retirement under 

the new program and the Acid Rain 

Program of those title IV allowances 

used to meet the allowance-holding 

requirement of the new program.

Commenters’ Arguments Based on Title 

IV 

The commenters claiming that EPA is 

barred by title IV from requiring use of 

title IV allowances at a reduced tonnage 

authorization in a new cap and trade 

program rely on the above-noted 

provision in section 402(3) stating that 

an allowance is an authorization to emit 

one ton of SO2. However, this provision 

does not bar EPA from requiring either: 

use of title IV allowances in a new cap 

and trade program under a different title 

of the CAA at a reduced tonnage 

authorization; or retirement in this new 

program and the Acid Rain Program of 

allowances used in this manner. 

At the outset, it should be noted that 

the CAIR model SO2 cap and trade 

program does not change the tonnage 

authorization of individual title IV 

allowances for purposes of the Acid 

Rain Program until such an allowance is 

used to meet the allowance-holding 

requirement of the CAIR SO2 program. 

The authorization provided by each title 

IV allowance for a source to emit one 

ton of SO2 emissions, as well as the 

requirement that each source hold title 

IV allowances covering annual SO2

emissions, continue to be in effect in the 

Acid Rain Program whether or not the 

source is also covered by the CAIR SO2

program. In fact, the Acid Rain Program 

regulations continue to reflect both this 

tonnage authorization and this 

allowance-holding requirement.138 See 

final revisions to 40 CFR § 73.35 

adopted in today’s action. Moreover, the 

CAIR model SO2 cap and trade rule 

coordinates the determinations—made 

by EPA for sources subject to both title 

IV and the CAIR—of compliance with 

the title IV and CAIR allowance-holding 

requirements so that such 

determinations are made in a multi-step, 

end-of-year process of comparing 

allowances held and emissions. First, 

EPA determines whether the source 

holds sufficient title IV allowances to 

comply with the one-allowance-per-tonof-emissions requirement in the Acid 

Rain Program as provided in § 73.35; 

and subsequently EPA determines 

whether the source holds the additional 

title IV allowances that, when added to 

those held for Acid Rain Program 

compliance, are sufficient to meet the 

CAIR allowance-holding requirement. 

Violations of the Acid Rain allowanceholding requirement will result in 

imposition of the penalty for excess 

emissions (i.e., the one-allowance offset 

plus $2,000 (inflation-adjusted) per ton 

of excess emissions) under CAA section 

411 and §§ 73.35(d) and 77.4. See final 

§ 96.254(b)(1) adopted in today’s action. 

Thus, the Acid Rain allowance-holding 

requirement continues as a separate 

requirement and reflects the oneallowance-per-ton-of-emissions 

authorization under section 402(3).139

In contrast with the one-allowanceper-ton-of-emissions requirement under 

the Acid Rain Program, the CAIR SO2

cap and trade program requires each 

source generally to hold 2 or 2.86 Acid 

Rain allowances for each ton of SO2

emissions. Contrary to the commenters’

claim, this CAIR allowance-holding 

requirement is not barred by the 

definition of the term ‘‘allowance’’ in 

section 402(3). While section 402(3) 

defines the term ‘‘allowance’’ as an 

authorization to emit one ton of SO2, 

this provision expressly applies the 

definition to the term ‘‘[a]s used in this 

title [IV]’’ and therefore does not apply 

to the treatment of title IV allowances in 

a different program under a different 

title of the CAA. Moreover, as noted 

above, section 403(f) allows EPA to limit 

(or terminate) the authorization to emit 

that an allowance otherwise provides 

under section 402(3). Consequently, the 

allowance definition in section 402(3) 

does not bar the treatment of a title IV 

allowance as authorizing less than one 

ton of SO2 emissions under the CAIR 

SO2 cap and trade program established 

under title I.140

Once a title IV allowance is used to 

meet the more stringent allowanceholding requirement in the CAIR SO2

program, that allowance is deducted 

from the source’s allowance tracking 

system account and cannot be used 

again, either in the CAIR SO2 program 

or the Acid Rain Program. As noted 

above, EPA has the authority under 

section 403(f) to require this termination 

of such a title IV allowance’s tonnage 

authorization for purposes of the Acid 

Rain Program. 

In addition to referencing section 

402(3) to support claims that EPA is 

barred from adopting the CAIR model 

cap and trade program provisions on the 

use of title IV allowances, the 

commenters rely on other title IV 

provisions that they characterize as 

setting a ‘‘title IV cap’’ on SO2

emissions. Stating that the requirement 

to use title IV allowances in the CAIR 

model SO2 cap and trade program has 

the effect of reducing the ‘‘title IV cap,’’

these commenters indicate, with little 

explanation, that such requirement is 

unlawful. In mentioning the title IV cap, 

the commenters are apparently referring 

to the fact that section 403(a)(1) 

(requiring allowance allocations 

resulting in emissions not exceeding 

8.90 million tons of SO2) and section 

405(a)(3) (requiring additional 

allocations of 50,000 allowances) 

require EPA to allocate annually, 

starting in 2010, a total amount of 

allowances authorizing no more than 

8.95 million tons of SO2 emissions. The 

commenters’ argument about how the 

CAIR model SO2 cap and trade program 

effectively reduces the ‘‘title IV cap’’

appears to be that elimination of the 

ability to use, in the Acid Rain Program, 

title IV allowances that will be used for 

compliance in the CAIR model SO2 cap 

and trade program has the effect of 

reducing the annual 8.95 million ton 

cap on SO2 emissions. This effective 

reduction of the ‘‘title IV cap’’ seems to 

occur when title IV allowances are used 

in the CAIR SO2 trading program with 

a reduced tonnage authorization so that 

more title IV allowances are deducted 

per ton of emissions than would be 

deducted for compliance with the Acid 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25293

141Similarly, to the extent title IV allowances are 

used in the CAIR SO2 trading program by non-Acid 

Rain sources, the ‘‘title IV cap’’ seems to be 

effectively reduced because more allowances are 

used in the CAIR SO2 trading program and 

effectively removed from use in the Acid Rain 

Program.

142 In light of this provision, the statement in the 

NPR (particularly as it is interpreted by the 

commenters) that EPA lacks authority to tighten the 

requirements of title IV (69 FR 4618, col. 1) is 

overly broad and is not repeated or adopted in 

today’s preamble.

143While section 403(b) (as well as section 

403(d)) refer specifically to the allowance system 

regulations required to be promulgated by the EPA 

Administrator within 18 months of November 15, 

1990 (the enactment date of the CAA), the EPA 

Administrator has authority under section 301 to 

amend such regulations ‘‘as necessary to carry out 

his functions under [the CAA].’’ 42 U.S.C. 7601.

Rain Program.141 The commenters claim 

that such a reduction in the 8.95 million 

ton cap is contrary to title IV.

In asserting an overarching principle 

that EPA is barred from adopting any 

requirement that would have the effect 

of reducing the 8.95 million ton cap 

under title IV, the commenters do not 

point to any specific statutory provision 

in support. The EPA maintains that not 

only are there no such supporting 

provisions, but also certain title IV 

provisions contradict this purported 

principle. Specifically, while sections 

403 and 405 require annual allowance 

allocations authorizing no more than 

8.95 million tons of emissions, section 

403(f) provides, as noted above, that 

EPA may terminate or limit the oneallowance-per-ton-of-emissions 

authorization for a title IV allowance.142

Because any termination or limitation of 

the tonnage authorization provided by a 

title IV allowance for purposes of the 

Acid Rain Program would have the 

effect of reducing the total tonnage of 

emissions allowed by the allowance 

allocations (i.e., the 8.95 million ton 

cap) under sections 403 and 405, the 

commenters’ claim that EPA is barred 

from adopting any provision that has 

such an effect is wrong on its face.

Commenters’ Argument Based on Clean 

Air Markets Group Case 

The commenters also state that the 

CAIR model SO2 cap and trade program 

is unlawful under the court’s holding in 

Clean Air Markets Group v. Pataki, 338 

F.3d 82 (2d Cir. 2003). According to the 

commenters, the required use of title IV 

allowances in the CAIR SO2 program 

constitutes an unlawful interference 

with the operation of the interstate title 

IV SO2 trading program, presumably 

similar to the unlawful interference 

found by the court in Clean Air Markets 

Group. However, the commenters 

provide little explanation of how such 

use of title IV allowances (with or 

without a reduced tonnage 

authorization) purportedly interferes 

with interstate operation of the Acid 

Rain Program and how the holding in 

Clean Air Markets Group applies to the 

CAIR SO2 program.

In Clean Air Markets Group, the Court 

reviewed a State law that imposed a 

monetary assessment on any title IV 

allowance sold by a New York utility to 

a utility in any of 14 specified States or 

subsequently transferred to such a 

utility, with the assessment equaling the 

proceeds received in the allowance sale. 

The law also required that each 

allowance sold include a covenant 

barring subsequent transfer of the 

allowance to a utility in any of those 

States. The Court held that the State law 

was pre-empted by title IV because the 

State law impermissibly interfered with 

the method chosen by Congress in title 

IV to reduce utilities’ SO2 emissions, 

i.e., the opportunity for nationwide 

trading of title IV allowances. Id. at 87–

88. In particular, the Court found that 

the assessment of 100 percent of sale 

proceeds ‘‘effectively bans’’ sales of any 

allowance by New York utilities to 

utilities in the specified States and that 

the restrictive covenant ‘‘indisputedly 

decreases’’ the value of the allowances. 

Id. at 88. 

The EPA maintains that today’s action 

is distinguishable from the facts and 

holding in Clean Air Markets Group. In 

particular, EPA believes that the 

exercise of its explicit authority under 

section 403(f) to limit the tonnage 

authorization of a title IV allowance in 

the CAIR SO2 cap and trade program 

and to terminate the tonnage 

authorization in the Acid Rain Program 

once the allowance is used in the CAIR 

SO2 program is consistent with—and 

necessary to preserve—the operation of 

the Acid Rain Program. Therefore, EPA 

concludes that its approach of limiting 

and terminating of the tonnage 

authorization of title IV allowances does 

not impermissibly interfere with the 

interstate operation of the Acid Rain 

Program and is reasonable. 

Unlike the circumstances in Clean Air 

Markets Group, under EPA’s approach 

in today’s action, each title IV allowance 

is freely transferable nationwide unless 

and until a source uses the allowance to 

meet the allowance-holding 

requirements of the CAIR SO2 program, 

at which time the allowance is deducted 

from the source’s allowance tracking 

system account and retired for purposes 

of both the CAIR SO2 program and the 

Acid Rain Program. Further, EPA 

expects that the ability to use title IV 

allowances to meet the more stringent 

emission limitation under the CAIR SO2

program to maintain or increase (not 

decrease) the value of each title IV 

allowance, until the allowance is used 

to meet the CAIR SO2 program 

allowance-holding requirement and is 

retired. 

Of course, this retirement of title IV 

allowances once they are used to meet 

the CAIR allowance-holding 

requirement means that they cannot 

thereafter be transferred to any person 

or be used again, e.g., to meet the Acid 

Rain Program allowance-holding 

requirement. As noted by the Court in 

Clean Air Markets Group, section 403(b) 

provides that title IV allowances ‘‘may 

be transferred among designated 

representatives of owners or operators of 

affected sources under [title IV] and any 

other person who holds such 

allowances, as provided by the 

allowance system regulations’’

promulgated by EPA.143 42 U.S.C. 

7651b(b). Moreover, section 403(d)(1) 

requires that the allowance system 

regulations ‘‘specify all necessary 

procedures and requirements for an 

orderly and competitive functioning of 

the allowance system.’’ 42 U.S.C. 

7651b(d). In the context of these 

statutory requirements, EPA maintains 

that, on balance, the retirement of title 

IV allowances used for compliance in 

the CAIR model SO2 cap and trade 

program does not constitute 

impermissible interference with the 

interstate operation of the Acid Rain 

Program, but rather is consistent with, 

and necessary to preserve, the operation 

of the Acid Rain Program.

As noted above, the imposition of an 

SO2 emission limitation (such as in 

today’s action) that is significantly more 

stringent than the one under title IV and 

covers most of the sources and 

emissions covered by title IV—but 

without addressing the impact on the 

Acid Rain Program—would likely have 

several adverse consequences. These 

adverse consequences would be: A 

significant excess of title IV allowances; 

a collapse of the price of title IV 

allowances; disruption of the title IV 

allowance market and the title IV SO2

cap and trade system; and potential SO2

emission increases, particularly in 

States outside the CAIR SO2 region. The 

EPA modeling indicates that, in 2010, 

EGU SO2 emissions in States not 

affected by the CAIR SO2 program 

would increase by about 260,000 tons 

(or about 29 percent of the 

approximately 0.9 million tons of SO2

emissions projected for the non-CAIR 

SO2 region in 2010) in the absence of an 

approach for addressing the impact of 

the CAIR SO2 program on title IV. This 

25294 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

144The surpluses for 2010 and 2015 respectively 

are calculated as: 7.3 million allowances minus 

((100 percent minus the percentage reduction 

requirement for the year) times 7.3 million 

allowances).

145The 4.8 million ton figure is the sum of: 3.65 

million tons of emissions (equal to the tonnage 

equivalent of the allowance allocations in the CAIR 

SO2 region); plus about 0.9 million tons of 

emissions in the non-CAIR SO2 region with the 

retirement of surplus title IV allowances; plus 

260,000 tons of increased non-CAIR SO2 region 

emissions if the surplus title IV allowances are not 

retired.

146See Sen. Rep. No. 101–228, 101st Cong., 1st 

Sess. at 324 (Dec. 20, 1989) (stating that 

‘‘[a]llowances are intended to function like a 

currency that is sufficiently valuable to stimulate 

efforts to acquire it through innovative and 

aggressive efforts to reduce emissions more than 

required’’ and that, in the event of ‘‘inflation in the 

currency,’’ the incentives to ‘‘reduce pollution 

* * * will be seriously weakened.’’ In the instant 

case, without a requirement to retire excess title IV 

allowances, the currency would be inflated to a 

value of zero. See also Legis. Hist. of CAAA, Vol. 

I at 1033 (Oct. 27, 1990 floor statement of Sen. 

Baucus explaining that ‘‘[s]ince units can gain cash 

revenues from the sale of allowances they do not 

use, they will have a financial incentive both to 

make greater-than-required reductions and/or 

reductions earlier than required’’ and that 

‘‘incentives created by the allowance market should 

stimulate innovations in the technologies and 

strategies used to reduce emissions’’ including 

energy efficiency).

is because, with the imposition of the 

more stringent CAIR SO2 emission 

limitation in the CAIR SO2 region, this 

more stringent limitation becomes the 

binding limitation for sources in that 

region. These CAIR SO2 sources must 

comply with, and cannot use title IV 

allowances to exceed, the CAIR SO2

emission limitation. Consequently, the 

portion of the title IV allowances that 

equals the difference between the CAIR 

and the title IV emission limitations is 

excess and would be available for use 

only by Acid Rain sources that are 

outside the CAIR SO2 region.

This excess amount of title IV 

allowances is potentially very 

significant. Today’s action requires that 

the States in the CAIR SO2 region 

achieve an amount of SO2 emission 

reductions in 2010 and 2015 equal to 50 

percent and 65 percent, respectively, of 

the amount of title IV allowances (about 

7.3 million allowances out of the total 

nationwide allocation of 8.95 million 

allowances) allocated to the units in the 

CAIR SO2 region. If the States achieve 

all the required CAIR SO2 reductions 

through emission reductions by EGUs 

(which are largely the same units that 

are subject to the Acid Rain Program) 

and if EGUs held only one title IV 

allowance for each ton of SO2 emissions 

as required in the Acid Rain Program, 

the amount of surplus allowances 

allocated to the States in the CAIR SO2

region would be about 3.65 million 

allowances and 4.75 million allowances, 

respectively in 2010 and 2015.144

Moreover, the vast majority of EGUs 

nationwide (about 90 percent) and of 

EGU SO2 emissions nationwide (about 

90 percent) are covered by the CAIR SO2

program. The net result would be a large 

surplus of title IV allowances that 

would not be usable in the CAIR SO2

region and would be usable only by the 

small subset of EGUs (about 10 percent) 

located in non-CAIR SO2 region States. 

Looking at the nation as a whole (both 

CAIR and non-CAIR SO2 States) in 2010, 

there would be total allocations in the 

Acid Rain Program of 8.95 million title 

IV allowances but, according to EPA 

modeling and analysis of the CAIR 

without a requirement to retire surplus 

title IV allowances, total projected SO2

emissions for EGUs of only about 4.8 

million tons.145 Based on the principles 

of supply and demand, EPA concludes 

that, with the amount of allowances 

allocated nation wide exceeding SO2

emissions for EGUs nationwide in 2010 

by about 86 percent (i.e., 8.95 million 

allowances minus 4.8 million tons 

divided by 4.8 million tons), the value 

of title IV allowances would fall to zero, 

and all but 260,000 of the surplus 

allowances would have no market and 

so, as a practical matter, would not be 

transferable.

The EPA notes that this effect on 

allowances would occur no matter how 

the State implements the more stringent 

SO2 emission limitation required under 

the CAIR, e.g., whether implementation 

is through a new cap and trade program 

(like in the model rule) or through a 

fixed (command and control) tonnage 

emission limit imposed on each 

individual source. Consequently, the 

alternatives faced by EPA are either: (1) 

To establish a CAIR model cap and 

trade program (or allow States to use 

another means of achieving CAIR SO2

emissions reductions) that does not 

retire the 3.65 million surplus 

allowances and that results in the 

devaluation of all title IV allowances to 

zero and the effective non-transferability 

of all but 260,000 of the 3.65 million 

surplus allowances in 2010; or, as 

provided in today’s action, (2) to adopt 

a CAIR SO2 model cap and trade 

program (or another means of achieving 

reductions) that retires the 3.65 million 

surplus allowances and that results in 

the non-transferability of the entire 3.65 

million surplus of title IV allowances 

and ensures the remaining, unused title 

IV allowances have market value. Thus, 

with regard to the impact on the 

transferability of title IV allowances, 

EPA’s decision to adopt the second 

alternative of retiring the surplus 

allowances adversely affects the 

transferability of only a relatively small 

amount (260,000 out of 8.95 million per 

year) of allowances, as compared to the 

amount of allowances whose 

transferability would be adversely 

affected under the first alternative.

Moreover, with the total collapse of 

the title IV allowance price in the Acid 

Rain Program, the nationwide cap and 

trade system under title IV—which 

would be the binding cap and trade 

system only for sources in the States 

outside the CAIR SO2 region—would 

lose all efficacy. The title IV cap and 

trade system operates by: Making 

owners of sources pay for the 

authorization to emit SO2 by 

surrendering, to EPA, allowances that 

have a market value; and by allowing 

owners (e.g., those who choose to 

reduce emissions) to sell unused 

allowances. Whether the sources’

allowances were originally allocated to 

the sources or were purchased, the 

owners must decide the extent to which 

it is more efficient to give up the market 

value of such allowances or to reduce 

emissions. If title IV allowances were to 

have no market value, the title IV cap 

and trade system would no longer affect 

the choice of whether to emit or to 

reduce emissions.146

The EPA maintains that such a result 

is contrary to Congressional intent. The 

purposes of title IV include not only 

reductions of annual SO2 emissions 

from 1980 levels, but also the 

encouragement of ‘‘energy conservation, 

use of renewable and clean alternative 

technologies, and pollution prevention 

as a long-range strategy, consistent with 

the provisions of this title, for reducing 

air pollution and other adverse impacts 

of energy production and use.’’ 42 

U.S.C. 7651(b). Reflecting these 

purposes, Congress required EPA to 

promulgate allowance system 

regulations for the Acid Rain Program 

that would promote ‘‘an orderly and 

competitive functioning of the 

allowance system.’’ 42 U.S.C. 

7651b(d)(1). See Sen. Rep. No. 101–228, 

101st Cong., 1st Sess. at 320 (explaining 

that ‘‘the allowance system is intended 

to maximize the economic efficiency of 

the program both to minimize costs and 

to create incentives for aggressive and 

innovative efforts to control pollution’’). 

As discussed above, if title IV 

allowances were to have no market 

value, the cap and trade system under 

title IV would no longer affect owners’

decisions on whether to emit or to 

control emissions and so would no 

longer provide encouragement (e.g., 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25295

147While the title IV cap and trade system could 

be replaced by a new CAIR SO2 cap and trade 

system that did not address the problems caused by 

surplus title IV allowance, that new cap and trade 

system would not be nationwide like the title IV 

cap and trade system and so would not cover 

sources outside the CAIR SO2 region.

148The EPA notes that the potential for increased 

emissions within the CAIR SO2 region would occur 

before the implementation of the CAIR SO2 program 

and is addressed by allowing pre-2010 banked title 

IV allowances to be used to meet the CAIR 

allowance holding requirement beginning in 2010.

149While the potential for increased emissions 

outside the CAIR SO2 region supports EPA’s 

conclusion, EPA maintains that, even in the 

absence of any such increase, the other 

considerations discussed above are sufficient to 

justify the conclusion that the retirement of title IV 

allowances does not impermissibly interfere with 

the Acid Rain Program and is reasonable.

incentives for innovation) for avoidance 

or reduction of SO2 emissions.147

In addition, EPA is concerned that 

such disruption of the title IV allowance 

market and the title IV SO2 cap and 

trade system would significantly erode 

confidence in cap and trade programs in 

general and the CAIR model cap and 

trade programs in particular. As noted 

above, under the Acid Rain Program, 

companies have made billions of dollars 

of investments in emission controls in 

order to be able to sell excess title IV 

allowances and in purchasing title IV 

allowances for future compliance (e.g., 

under annual, 1-day allowance auctions 

held by EPA, one as recently as March 

22, 2004 when title IV allowances were 

purchased for about $50 million). While 

in a market-based program like the Acid 

Rain Program, investments are 

necessarily subject to the vagaries of the 

market, EPA believes that it should try, 

to the extent possible consistent with 

statutory requirements, to avoid taking 

administrative actions that would cause 

such extensive disruption of the Acid 

Rain Program. Allowing such disruption 

to occur could significantly reduce the 

willingness of owners of sources in new 

cap and trade programs to invest in 

measures that would result in excess 

allowances for sale or to purchase 

allowances for compliance. To the 

extent owners would ignore the 

allowance-trading option and simply 

control emissions to the level equal to 

their source’s allocations, this would 

obviate the incentives for innovation, 

and hamper realization of the potential 

for cost savings, that would otherwise 

be provided by new cap and trade 

programs (such as the CAIR model cap 

and trade programs).

Finally, as noted above, such 

disruption of the Acid Rain Program 

would potentially result in significantly 

increased SO2 emissions (about 29 

percent in 2010) in States covered by 

the Acid Rain Program but outside the 

CAIR SO2 region.148 This would have 

the effect of reversing, at least in part, 

the beneficial effect that the Acid Rain 

Program has had on SO2 emissions in 

those States, even though the overall 

goal of nationwide SO2 emissions 

reductions would still be met. See 42 

U.S.C. (a)(1) (Congressional finding that 

‘‘the presence of acidic compounds and 

their precursors in the atmosphere and 

in deposition from the atmosphere 

represents a threat to natural resources, 

ecosystems, materials, visibility, and 

public health’’).

In light of these considerations,149

EPA concludes, on balance, that 

structuring the CAIR model SO2 cap and 

trade program in a way that avoids such 

extensive disruption of the Acid Rain 

Program (i.e., by requiring retirement 

from the Acid Rain Program of title IV 

allowances used for compliance in the 

CAIR SO2 program) does not constitute 

impermissible interference with the 

interstate operation of the Acid Rain 

Program. Rather, this approach in the 

model SO2 cap and trade rule is 

consistent with, and preserves, such 

operation—while providing States a tool 

for imposing the more stringent SO2

emission limitations required under title 

I—and is a reasonable exercise of EPA’s 

authority under section 403(f) to 

terminate or limit the tonnage 

authorization of title IV allowances.

2. Legal Authority for Requiring 

Retirement of Excess Title IV 

Allowances if State Does Not Use CAIR 

Model SO2 Cap and Trade Program 

As discussed above, a State has the 

additional options of achieving the SO2

emissions reductions required by 

today’s actions through: EGU emission 

reductions only but without using the 

model SO2 cap and trade rule; some 

EGU and some non-EGU emissions 

reductions; or non-EGU reductions only. 

The requirement to retire excess title IV 

allowances applies only in the first and 

second of these three additional options. 

The State must retire an amount of title 

IV allowances equal to the total amount 

of title IV allowances allocated to units 

in the State minus the amount of 

allowances equivalent to the tonnage 

cap set by the State on EGUs’ SO2

emissions and can choose what 

mechanism to use to achieve such 

retirement. The EPA has the authority to 

require that the State include in its SIP 

a mechanism for retiring the excess title 

IV allowances that will result under 

these two options. 

As discussed above, EPA has the 

authority under section 403(f) to 

terminate or limit the authorization to 

emit otherwise provided by a title IV 

allowance. Specifically, EPA has the 

authority to: require that any EGU SO2

emission reduction program, chosen by 

a State to meet (in full or in part) the 

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

include provisions for retiring excess 

title IV allowances resulting from the 

implementation of the more stringent 

emission reduction requirement under 

the State program; and to require that 

such retired title IV allowances cannot 

be used in the Acid Rain Program. As 

discussed above, the commenters’

claims that such a retirement 

requirement is barred by title IV (relying 

on, e.g., the section 402(3) definition of 

‘‘allowance’’ and on the ‘‘title IV cap’’) 

lack merit. Also, for the reasons 

discussed above, the retirement 

requirement is not unlawful under 

Clean Air Markets Group and is a 

reasonable exercise of EPA’s authority 

under section 403(f) to terminate or 

limit the tonnage authorization of title 

IV allowances. 

Some commenters also claim that the 

retirement requirement unlawfully 

constrains the States’ authority to 

determine in the first instance the 

control measures to use in meeting 

emission reduction requirements 

necessary to comply with section 

110(a)(2)(D). According to the 

commenters, since only EGUs are 

subject to title IV, the requirement to 

retire title IV allowances is in effect a 

mandate that the State control EGU 

emissions.

However, EPA is imposing the 

requirement for a State mechanism to 

retire title IV allowances only if the 

State decides in the first instance to 

require any EGU SO2 emissions 

reductions to meet the emission 

reduction requirements under today’s 

action. A State that decides not to 

require any EGU SO2 emissions 

reductions for this purpose is not 

required to retire title IV allowances. 

Further, the amount of the required 

allowance retirement is limited to the 

amount of EGU SO2 emissions 

reductions that the State decides in the 

first instance to require from EGUs (i.e., 

the total title IV allowance allocations in 

the State minus the tonnage amount of 

the cap set by the State for EGUs’ SO2

emissions). In short, the allowance 

retirement requirement echoes the 

State’s decision in the first instance 

concerning the amount of SO2 emissions 

reductions to require from EGUs in the 

State. The EPA simply requires the State 

to implement the State’s EGU–SO2-

emission-reduction-requirement 

decision in a manner that avoids the 

otherwise likely, extreme disruption of 

the title IV SO2 cap and trade system 

that is described above. Further, the 

25296 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

State may choose what mechanism to 

include in its SIP revision for achieving 

the required allowance retirement, and 

EPA will review the effectiveness of the 

mechanism in achieving such 

retirement, and approve and adopt the 

mechanism if appropriate, in an EPA 

rulemaking concerning the SIP revision. 

Therefore, EPA concludes that the 

allowance-retirement requirement is 

lawful and is a reasonable condition for 

EPA approval of those State SIPs that 

require EGU SO2 emission reductions 

without using the CAIR model SO2

trading program. 

The EPA notes that the requirement to 

retire excess title IV allowances—where 

a State adopts the CAIR model SO2

trading program or where a State SIP 

obtains EGU emissions reductions 

through some other means—is reflected 

in provisions in both the proposed rules 

in the SNPR (i.e., in proposed 

§§ 51.124(p) and 96.254(b)) and in the 

final rules adopted by today’s action 

(i.e., in final §§ 51.124(p) and 96.254(b)). 

In reviewing the proposed rules in light 

of the comments received, EPA has 

concluded that, for consistency and 

clarity, the Acid Rain Program 

regulations should also reference this 

same retirement requirement. 

Consequently, today’s action adds a new 

paragraph (a)(3) to § 73.35 of the Acid 

Rain Program regulations that reiterates 

the requirement—addressed in the 

preamble and regulations in both the 

SNPR and today’s action—that title IV 

allowances previously used to meet the 

allowance-holding requirement in the 

CAIR model trading program in 

§ 96.254(b) or otherwise retired in 

accordance with § 51.124(p) cannot be 

used to meet the allowance-holding 

requirement in the Acid Rain Program. 

Additional revisions of the Acid Rain 

Program regulations are discussed 

below. 

3. Revisions to Acid Rain Regulations 

In the SNPR, EPA proposed to revise 

the Acid Rain Program regulations, 

effective July 1, 2005, to implement the 

allowance-holding requirement on a 

source-by-source, rather than on a unitby-unit, basis. Instead of requiring each 

unit to hold an amount of allowances in 

its Allowance Tracking System account 

(as of the allowance transfer deadline) at 

least equal to the tonnage of SO2

emissions for the unit in the preceding 

calendar year, the proposal required 

each source to hold an amount of 

allowances in its Allowance Tracking 

System account at least equal to the 

tonnage of SO2 emissions for all affected 

units at the source for such calendar 

year. Because language reflecting or 

referencing the unit-by-unit compliance 

approach is included in many 

provisions of the Acid Rain Program 

regulations, a significant number of 

proposed rule revisions were necessary 

to implement source-by-source 

allowance holding. 

In today’s final rule, EPA is adopting, 

with minor modifications, the proposed 

rule revisions implementing source-bysource compliance with the allowanceholding requirement. As explained in 

detail in the SNPR (69 FR 32698–

32701), EPA finds that: Title IV is 

ambiguous with regard to whether unitby-unit compliance is required and so 

EPA has discretion in this matter; it is 

important to provide additional 

compliance flexibility by allowing a 

unit at a source to use allowances from 

any other unit at the same source; and 

many other, non-allowance-holding 

provisions of title IV evidence a unit-byunit orientation. Further, as discussed 

in the SNPR, EPA concludes that the 

adoption of source-level compliance 

reasonably balances these 

considerations. In balancing these 

considerations, EPA also concludes that 

company-level compliance is not 

appropriate because it represents too 

much of a deviation from the unit-byunit orientation in the non-allowanceholding provisions of title IV and is 

likely to require much more dramatic 

changes in the operation of the Acid 

Rain Program. See 69 FR 32699–700. It 

is important to note that the final rule 

revisions, like the proposed revisions, 

change only the allowance-holding 

requirement and not the emissions 

monitoring and reporting requirements, 

which continue to be applied unit by 

unit.

In today’s action, EPA is making the 

source-level-compliance rule revisions 

effective July 1, 2006, which is 1 year 

later than proposed. The shift from unitlevel to source-level compliance will 

require software changes and testing to 

ensure that the Allowance Tracking 

System operates properly. Currently, 

EPA is in the process of conducting a 

general review and re-engineering of the 

Allowance Tracking System and 

Emissions Tracking System and 

anticipates completing the process in 

2006. The process of shifting the 

Allowance Tracking System to sourcelevel compliance will be much more 

efficient and less likely to have adverse 

results on the system if the shift is 

coordinated with the general review and 

re-engineering and therefore 

implemented starting July 1, 2006. 

Further, as discussed below, this delay 

of implementation for 1 additional year 

will give owners additional time to 

make changes that they determine are 

necessary in order to adapt to sourcelevel compliance. 

Some commenters support the shift to 

source-by-source allowance holding, 

and some oppose the change. One 

commenter opposing the change claims 

that a source-by-source allowanceholding requirement is ‘‘contrary to 

market-based principles.’’ According to 

the commenter, market-based systems 

give operators the tools for achieving 

compliance through allowance transfers, 

but with source-level compliance the 

operators do not have to take any action 

to maintain sufficient allowances 

because EPA will move the allowances 

around for them. 

The commenter’s argument is based 

on an incorrect premise. Whether 

compliance is unit-by-unit or source-bysource, the owner or owners of the 

affected units at each source must take 

the same types of actions in order to 

comply with the applicable allowanceholding requirement. In particular, 

under source-level compliance, such 

owner or owners must reduce 

emissions, retain allowances allocated 

to such units, obtain additional 

allowances, or take a combination of 

these actions to ensure that the 

Allowance Tracking System account for 

the source holds enough allowances to 

cover the total emissions of the affected 

units at the source. The owner or 

owners also have the option of reducing 

emissions below allocations so that 

there are extra allowances available to 

hold for future use or sale. If the owner 

or owners do not have enough 

allowances to cover the emissions from 

the source, EPA will not move, on its 

own initiative, allowances into the 

source’s compliance account from other 

sources’ accounts or from general 

accounts, even if there are extra 

allowances in the other accounts. The 

only difference between the types of 

actions owners must take under the 

unit-level and source-level approaches 

is that, under unit-level compliance, the 

owners must transfer allowances from 

one unit at a source to a second unit at 

that source in order to use the first 

unit’s allowances for compliance by the 

second unit while, under source-level 

compliance, any allowance held for 

compliance for the first unit can be 

used—without a transfer—for 

compliance by the second unit. This 

difference is reflected in the Allowance 

Tracking System, which, under the unitlevel approach, includes a separate 

account for each unit and, under the 

source-level approach, includes a single 

account for all the affected units at a 

single source. 

In summary, the mechanism, and the 

owners’ responsibilities, for achieving 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25297

150This approach is consistent with the SNPR, 

where EPA proposed to convert all references, 

including any initially missed in the SNPR, from 

unit- to source-level compliance (69 FR 32700).

compliance with the allowance-holding 

requirements are analogous under unitby-unit and source-by-source 

compliance, except that, under sourceby-source compliance, allowances need 

not be transferred among units at the 

same source. The EPA does not believe 

that the source-by-source approach is 

any less market-based than the unit-byunit approach. Owners will still have 

the ability to reduce emissions or 

purchase or sell allowances and the 

responsibility to take actions (including 

the holding of extra allowances) to 

ensure they have enough allowances to 

cover emissions. Moreover, the marketprice of allowances will still play a 

crucial role in owners’ decisions on 

what actions to take. The EPA’s 

adoption of source-by-source 

compliance preserves market-based 

principles, while reasonably balancing 

of the ambiguity of title IV, the need for 

additional compliance flexibility, and 

the unit-by-unit orientation of many 

provisions in title IV. See 69 FR 32699–

700.

The commenter also argues that 

having a source-level allowance-holding 

requirement in the Acid Rain Program 

(and the CAIR model cap and trade 

program) is inconsistent with unit-level 

compliance in the NOX SIP Call cap and 

trade program. However, other than 

pointing out this difference, the 

commenter fails to explain why the 

programs must be identical in this 

regard. Based on experience with the 

Acid Rain Program (as well as the NOX

SIP Call trading program), EPA 

concludes that a source-level allowanceholding requirement will result in a 

somewhat less complicated program 

and a reduced likelihood of inadvertent, 

minor errors, while achieving the 

program’s environmental goals. See 69 

FR 32699–700. 

The commenter suggests that, instead 

of adopting source-level compliance, 

EPA revise the Acid Rain Program 

regulations to allow for source overdraft accounts, like those allowed in the 

NOX SIP Call cap and trade program. 

Under the NOX SIP Call program, each 

source may have a source over-draft 

account, in which may be held extra 

allowances that may be used for 

compliance by any affected unit at the 

source. However, EPA believes that 

source-level compliance is a better 

approach than unit-level compliance 

with over-draft accounts. Relatively few 

owners in the NOX SIP Call cap and 

trade program actually put allowances 

in over-draft accounts, and achievement 

of compliance is made more 

complicated by the ability of all units at 

a source to draw on the over-draft 

account (if any allowances are put in it) 

but the inability of any unit to use extra 

allowances held instead by another unit 

at the source. Consequently, rather than 

adopting in the Acid Rain Program the 

unit-level approach with over-draft 

accounts, EPA is today adopting the 

source-level approach in the Acid Rain 

Program and may consider in the future, 

as appropriate, adopting the sourcelevel approach in other programs using 

unit-level compliance. 

One commenter states that EPA 

should revise the Acid Rain Program 

regulations to allow owners, each year, 

the option of choosing whether to use 

unit-level or source-level compliance. 

According to the commenter, significant 

investments have been made to monitor 

and report emissions and surrender 

allowances under the existing Acid Rain 

Program regulations, and shifting to 

source-level compliance will require 

substantial resources and time. The 

commenter also states that unit-based 

compliance should be retained as an 

option ‘‘to accommodate joint 

ownership and other special 

arrangements that may not affect an 

entire facility.’’

The EPA rejects the suggestion of 

allowing each owner the option, for 

each year and for each source, of 

choosing between unit-level and sourcelevel compliance. Such an approach 

would significantly complicate the 

achievement by sources, and the 

determination by EPA, of compliance. 

The potential for error (e.g., due to 

erroneous assumptions about whether 

unit-or source-level compliance would 

be applicable to a particular source for 

a particular year) on the part of owners 

or EPA would be significantly 

increased. Moreover, this complicated 

approach would result in inconsistent 

treatment from source to source and 

year-to-year. Further, the commenter 

provided only vague assertions about 

the benefits of unit-based compliance in 

certain circumstances and did not 

assert—much less show—that sourcelevel compliance cannot be 

accommodated under those 

circumstances. The EPA maintains that 

the only reasonable options for the 

allowance-holding requirement in the 

Acid Rain Program are either generally 

requiring compliance by all sources 

each year on a unit-level basis (as in the 

existing regulations) or requiring 

compliance by all sources each year on 

a source-level basis (as in the proposed 

revisions to the regulations). For the 

reasons discussed above, EPA believes 

that source-level compliance for the 

allowance-holding requirement is 

preferable. By postponing until July 1, 

2006 the effective date of the rule 

revisions shifting to source-level 

compliance (with the result that 2006 is 

the first year of source-level 

compliance), EPA is providing owners a 

reasonable amount of time to make any 

necessary adjustments, such as those 

claimed by the commenter. Further, as 

noted above, the rule revisions change 

only the allowance-holding requirement 

and not the emissions monitoring and 

reporting requirements. This should 

limit the scope of adjustments necessary 

for owners to implement source-level 

compliance and will preserve the 

availability of reliable, unit-level 

emissions data.

Because unit-level compliance is 

reflected throughout the Acid Rain 

Program regulations, numerous 

revisions of the regulations are 

necessary to implement source-level 

compliance. (None of these changes are 

to the emissions monitoring and 

reporting provisions in part 75 since 

monitoring and reporting continue to be 

on a unit basis.) One commenter 

requested that EPA provide ‘‘more indepth detail’’ on the proposed revisions. 

However, in the SNPR, EPA described 

the types of, and reasons for, revisions 

that are necessary for source-level 

compliance (69 FR 32700–01) and set 

forth all of the specific, proposed 

changes (69 FR 3273–41). Moreover, no 

commenters stated that they did not 

understand any specific, proposed 

revision or the reason for any specific 

revision. The EPA notes that in 

reviewing the proposed Acid Rain rule 

revisions in light of the comments, EPA 

found some additional references in the 

Acid Rain rule to unit-level compliance 

that should be revised to reflect sourcelevel compliance. In today’s action, EPA 

is adopting revisions of these additional 

references (e.g., changing references to a 

‘‘unit’s account’’ or a ‘‘unit account’’ to 

a source’s ‘‘compliance account’’) that 

are analogous to the revisions 

specifically identified in the SNPR.150

Another commenter opposed the rule 

revisions implementing source-level 

compliance on several other grounds. 

The commenter claims, without citing 

any statutory support, that the Acid 

Rain Program is based on ‘‘control of 

emissions at the unit level’’ so that, in 

the event of excess emissions, the 

‘‘source as a whole would not be 

punished’’ and ‘‘corrective action could 

take place’’ at the particular unit. 

According to the commenter, sourcelevel compliance will: Make it harder to 

determine which unit caused excess 

emissions; make the existing Acid Rain 

25298 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

permits meaningless; make the 

individual unit allowance allocations 

meaningless; and cause confusion over 

which units at a source are affected 

units. 

While there are many non-allowanceholding provisions in title IV that have 

a unit-by-unit orientation, EPA 

disagrees with the commenter’s basic 

assertion that the purpose of the Acid 

Rain Program is to control emissions on 

a unit-by-unit basis and that there is a 

need to ‘‘distinguish’’ the compliance of 

each individual unit. The provisions 

concerning application of the 

allowance-holding requirement are 

ambiguous as to whether EPA must 

implement the requirement on a unitlevel or a source-level, and the 

environmental benefits of the Acid Rain 

Program will still be realized with 

source-level compliance. See 69 FR 

32699–700. Further, while EPA will 

determine compliance on a source-bysource basis, nothing in the regulations 

prevents owners (e.g., owners of units at 

sources with multiple units and 

multiple owners or owners of units with 

multiple owners and exhausting 

through a common stack) from 

determining by agreement which 

owners will bear any excess emissions 

penalties that occur at the plant and 

have to take correction actions. Indeed, 

owners are likely to already have these 

types of agreements in cases of units or 

sources with multiple owners. This is 

because the Acid Rain Program 

regulations already allow a unit at a 

multi-unit source to use some 

allowances from other units at the 

source (albeit to cover most but not all 

of the potential excess emissions) and 

already allow one unit exhausting from 

a common stack to use allowances from 

another unit at that stack (without any 

limitation on such use). See 40 CFR 

73.35(b)(3) and (e). In addition, while 

the Acid Rain permits will have to be 

revised in the future to reflect sourcelevel compliance, today’s rule does not 

make source-level compliance effective 

until 2006. Permits will not have to be 

revised until around the end of 2006, 

which should provide States a 

reasonable opportunity to amend the 

permits. Contrary to the claims of the 

commenter, source-level compliance 

does not make the unit-by-unit 

allocations meaningless; the unit-byunit allocations (set forth in Table 2 of 

§ 72.10) will determine the amount of 

allocations reflected in each Allowance 

Tracking System source account, which 

amount will equal the sum of the 

allocations for all affected units at the 

source. Finally, the commenter failed to 

explain how the source-level allowanceholding requirement could cause 

‘‘confusion’’ over which units are 

affected units. This source-level 

requirement does not change the 

applicability provisions, which are still 

applied unit by unit. 

As discussed in the SNPR, EPA 

proposed—in addition to the rule 

revisions to implement source-level 

compliance—other revisions of the Acid 

Rain Program regulations in order to 

facilitate coordination of the Acid Rain 

Program and the CAIR SO2 cap and 

trade program. These additional 

revisions were described and explained 

in the SNPR (69 FR 32701). The EPA is 

adopting these revisions for the reasons 

in the SNPR, as amplified below. Most 

of these revisions are supported, or not 

opposed, by commenters, but some 

commenters objected to certain 

revisions.

For example, EPA noted that it had 

recently changed the ‘‘cogeneration 

unit’’ definition in § 72.2 in June 2002 

(67 FR 40394, 40420; June 12, 2002). 

The original definition in § 72.2 had 

been used since the commencement of 

the Acid Rain Program. The only 

significant difference between the 

original and revised definitions is that 

the former refers to a unit ‘‘having the 

equipment used to produce’’ electricity 

and useful thermal energy through 

sequential use of energy, while the latter 

simply refers to a unit ‘‘that produces’’

electricity and useful thermal energy in 

that manner. The reason that EPA gave 

for revising the definition in June 2002 

was to conform with the definition in 

the Section 126 rule. However, the 

Section 126 rule (and the NOX SIP Call) 

did not actually specify a ‘‘cogeneration 

unit’’ definition. Consequently, there is 

no reason to use the June 2002 revised 

definition. Moreover, EPA is concerned 

that the change in the definition of 

‘‘cogeneration unit’’ as of June 2002 may 

cause confusion or raise question about 

what units qualify for exemptions for 

‘‘cogeneration units’’ from the Acid Rain 

Program. Under these circumstances, 

EPA concludes that the definition 

should be changed back to the original 

definition in § 72.2 and, in any event, 

intends to interpret the June 2002 

revised definition as having the same 

meaning as the original definition. One 

commenter raised concerns that EPA 

did not provide any ‘‘detailed analysis’’

of the implications of changing the 

‘‘cogeneration unit’’ definition. 

However, as discussed above, the 

change simply reinstates the definition 

that had been used in the Acid Rain 

Program from the initial promulgation 

of implementing regulations in 1993 

until 2002. No commenter asserted that 

reverting to the longstanding, original 

definition would be disruptive. 

Another Acid Rain Program rule 

revision proposed in the SNPR is the 

elimination of the requirement for 

owners and operators to submit an 

annual compliance certification report 

for each source. One commenter 

expressed concern, because the purpose 

of the annual certification is to ensure 

that the designated representative is 

‘‘aware and has assured the quality of 

the data’’ being submitted to EPA. 

However, as noted in the SNPR, 

designated representatives must 

evidence such awareness and 

compliance by submitting, with each 

quarterly emissions report, a 

certification that the monitoring and 

reporting requirements under part 75 of 

the Acid Rain Program regulations have 

been met. See 40 CFR 75.64(c). 

Quarterly emissions reports are 

available on-line to the public and the 

States. In addition, owners and 

operators of sources subject to the Acid 

Rain Program must submit, under title 

V of the CAA, annual compliance 

certification reports concerning all CAA 

requirements (including Acid Rain 

Program requirements). Under these 

circumstances, EPA maintains that the 

separate Acid Rain Program annual 

compliance certification reports are 

duplicative and unnecessary. The EPA 

notes that it appears that few, if any, 

requests for copies of these Acid Rain 

Program reports have been made by 

States or any other persons since the 

commencement of the Acid Rain 

Program. Apparently, other 

certifications and submissions required 

of owners and operators have been 

sufficient for the purposes cited by the 

commenter. 

The SNPR also included proposed 

revisions eliminating the requirement 

under the Acid Rain Program for a 1-day 

newspaper notice for designation of 

designated representatives and 

authorized account representatives. One 

commenter suggests that this notice 

should be replaced by a requirement to 

notify the State permitting authority. 

The EPA notes that information on 

designated representatives and 

authorized account representatives is 

already available to State permitting 

authorities through on-line access to the 

Allowance Tracking System. Moreover, 

EPA is in the process of developing, and 

anticipates establishing in the near 

future, the ability to send State 

permitting authorities (at their request) 

on-line notices of changes in designated 

representatives (who are also the 

authorized account representatives for 

affected sources’ accounts). 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25299

151 In reviewing the proposed Acid Rain Program 

rule revisions, EPA found some additional 

references to ‘‘subaccounts’’ that were not 

specifically noted in the SNPR. For consistency and 

clarity in the Acid Rain Program rules, EPA is 

adopting in today’s action revisions (e.g., chaning 

the term ‘‘subaccount’’ to ‘‘compliance account’’) of 

these additional references, which revisions are 

analogous to those specifically set forth in the 

SNPR. This approach is consistent with the SNPR, 

where EPA proposed to convert all references, 

including any initially missed in the SNPR, from 

subaccount to compliance account, (69 FR 32700).

152Arizona, California, Colorado, Oregon, Idaho, 

Nevada, New Mexico, Utah, and Wyoming. 153The trading program is referred to as a 

‘‘backstop’’ because under the WRAP Annex, States 

have the opportunity to achieve specified emission 

milestones using voluntary measures, with the 

trading program coming into effect only if those 

milestones are exceeded.

154The methodology is prescribed in 40 CFR 

51.308(e)(2) and incorporated into § 309 by 

reference at 40 CFR 51.309(f).

Other proposed Acid Rain Program 

rule revisions on which EPA received 

adverse comment are the removal of 

§ 73.32 (prescribing the contents of an 

allowance account) and § 73.51 

(prohibiting the transfer of allowances 

from a future year subaccount to a 

subaccount for an earlier year). Section 

73.32 sets forth a rather self-evident list 

of information that must be recorded in 

an allowance account in the Allowance 

Tracking System, such as the name of 

the authorized account representative, 

the persons represented by the 

authorized account representative, and 

the transfers of allowances in and out of 

the account. This section also references 

information on compliance or current 

year subaccounts and future year 

subaccounts, as well as emissions 

information. As discussed in the SNPR, 

several items on the list of informational 

contents for allowance accounts are outof-date in that they do not reflect how 

the electronic Allowance Tracking 

System operates or will operate in the 

near future. For example, the electronic 

Allowance Tracking System does not 

currently use or refer to subaccounts, 

which will continue to be unnecessary 

in the context of source-level 

compliance.151 See 69 FR 

32700–01. In addition, while § 73.32 

states that emissions data are reflected 

in the Allowance Tracking System 

account, such data are currently 

available instead through the electronic 

Emissions Tracking System. Because the 

information list in § 73.32 contains 

either self-evident items or items that 

are out-of-date and because the NOX

Allowance Tracking System has been 

operating successfully even though the 

model NOX Budget cap and trade rule 

and State cap and trade rules under the 

NOX SIP Call lack a provision analogous 

to § 73.32, EPA is removing § 73.32. EPA 

notes that the removal of the section 

will not mean that the information 

contained in allowance accounts ‘‘can 

be changed at will.’’ The format for 

allowance accounts is set forth in the 

electronic Allowance Tracking System 

and implements the requirements in the 

Acid Rain Program regulations 

concerning the holding, transferring, 

recording, and deducting of allowances.

Section 73.51 prohibits the transfer of 

allowances from a future year 

subaccount to a subaccount for an 

earlier year. The removal of this section 

is consistent with the elimination 

throughout the rest of the Acid Rain 

Program regulations, as discussed in the 

SNPR (id.), of any references to such 

subaccounts. Further, the prohibition on 

using allowances allocated for a year to 

meet the allowance-holding requirement 

for a prior year is retained in other 

provisions of the Acid Rain Program 

regulations. Consequently, EPA is 

removing § 73.51.

C. How Does the Rule Interact With the 

Regional Haze Program? 

This section discusses the 

relationship of the CAIR cap and trade 

program for EGUs with the regional 

haze program under sections 169A and 

169B of the CAA, in particular the 

requirements for Best Available Retrofit 

Technology (BART) for certain source 

categories including EGUs. The 

legislative and regulatory background of 

the BART provisions were presented in 

some detail in the SNPR. (See 69 FR 

32684, 32702–704, June 10, 2004). In 

brief, BART regulations consist of two 

components. The first, promulgated in 

1980, addresses visibility impairment 

that can be ‘‘reasonably attributed’’ to a 

single source or small group of sources. 

(45 FR 80085; December 2, 1980, 

codified at 40 CFR 51.302). The second 

component addresses BART in relation 

to regional haze (visibility impairment 

caused by a multitude of broadly 

distributed sources) and was 

promulgated as part of the Regional 

Haze Rule. (64 FR 35714; July 1, 1999). 

Certain parts of the BART provisions in 

that rule were vacated by the U.S. Court 

of Appeals for the DC Circuit in 

American Corn Growers et al. v. EPA,

291 F.3d 1 (DC Cir., 2002). To address 

that decision, in May 2004, EPA 

proposed changes to the Regional Haze 

Rule and reproposed the Guidelines for 

BART Determinations (originally 

proposed in 2001) (69 FR 25185, May 5, 

2004). 

On February 18, 2005, the DC Circuit 

decided another case dealing with 

BART and a BART alternative program, 

Center for Energy and Economic 

Development v. EPA, No. 03–1222, (DC 

Cir. Feb. 18, 2005) (‘‘CEED’’). In this 

case, the court granted a petition 

challenging provisions of the regional 

haze rule governing the optional 

emissions trading program for certain 

western States and Tribes (the ‘‘WRAP 

Annex Rule’’). The holdings of the case 

are relevant to today’s action in several 

respects. 

Most importantly for purposes of the 

CAIR, CEED affirmed EPA’s 

interpretation of CAA 169A(b)(2) as 

allowing for non-BART alternatives 

where those alternatives make greater 

progress than BART. (CEED, slip. op. at 

13) (finding that EPA’s interpretation of 

CAA 169(a)(2) as requiring BART only 

as necessary to make reasonable 

progress passes the two-pronged 

Chevron test). 

The particular provisions involved in 

CEED applied, on an optional basis, 

only to nine western States 152 (none of 

which are in the CAIR region) and the 

Tribes therein. The provisions, 

contained in 40 CFR 51.309 (‘‘section 

309’’) required among other things that 

States choosing to participate in a 

‘‘backstop’’ 153 cap and trade program 

must demonstrate that the emissions 

reductions under the program resulted 

in greater progress towards the national 

visibility goals than would BART. At 

issue was the particular methodology 

required for this demonstration. 

Specifically, EPA’s rule required that 

visibility improvements under sourcespecific BART—the benchmark for 

comparison to the cap and trade 

program—must be calculated based on 

the application of BART controls to all 

sources subject to BART.154 Although 

American Corn Growers had vacated 

this cumulative visibility approach in 

the context of determining BART for 

individual sources, EPA believed that it 

was still permissible to require this 

methodology in the context of a BARTalternative program. The DC Circuit in 

CEED held otherwise, stating: ‘‘EPA 

cannot under § 309 require states to 

exceed invalid emission reductions (or, 

to put it more exactly, limit them to a 

§ 309 alternative defined by an unlawful 

methodology).’’ (Id. at 14).

Thus, CEED firmly established two 

principles: (1) The CAA allows States to 

substitute other programs for BART 

where the alternative achieves greater 

progress, and (2) EPA may not require 

States to evaluate visibility 

improvement on a cumulative basis as 

a condition for approval of a BARTalternative. The first principle validates 

EPA’s proposal to allow the CAIR to 

substitute for BART. The second 

25300 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

155The SNPR preamble used the term 

‘‘exemption’’ in describing this policy. As clarified 

below, and as consistent with the proposed 

regulatory language, the better-than-BART policy is 

not actually an exemption but rather an alternative 

means of compliance.

principle is not at issue in the CAIR 

context, because EPA is not proposing 

to impose the cumulative visibility 

methodology upon States, nor to require 

States to treat the CAIR as having 

satisfied their BART obligations. 

Nonetheless, EPA has determined that 

it is premature to make a final 

determination regarding the sufficiency 

of the CAIR as a BART alternative, 

primarily because (1) the guidelines for 

source-specific BART determinations, in 

response to American Corn Growers

have not been finalized, and (2) there is 

now a need to revise the Regional Haze 

Rule and the guidelines for BARTalternative programs in response to 

CEED. The source-specific BART 

guidelines will be finalized on or before 

April 15, 2005, under a consent decree. 

The rule changes and revisions to the 

BART-alternative guidelines will be 

proposed soon thereafter. 

Therefore, we are making no final 

determination in today’s action with 

respect to BART. The EPA continues to 

believe, however, that the CAIR will 

result in greater progress in visibility 

improvement than BART, as explained 

below.

1. How Does This Rule Relate to 

Requirements for BART Under the 

Visibility Provisions of the CAA? 

a. Supplemental Notice of Proposed 

Rulemaking 

In the SNPR, we proposed that States 

which adopt the CAIR cap and trade 

program for SO2 and NOX would be 

allowed to treat the participation of 

EGUs in this program as a substitute for 

the application of BART controls for 

these pollutants to affected EGUs.155 To 

give this option effect, we proposed an 

amendment to the Regional Haze Rule 

which would add a section at 40 CFR 

51.308(e)(3), as follows:

(3) A State that opts to participate in the 

Clean Air Interstate Rule cap and trade 

program under part 96 AAA–EEE need not 

require affected BART-eligible EGUs to 

install, operate, and maintain BART. A State 

that chooses this option may also include 

provisions for a geographic enhancement to 

the program to address the requirement 

under § 51.302(c) related to BART for 

reasonably attributable impairment from the 

pollutants covered by the CAIR cap and trade 

program.

This proposal is consistent with 

currently existing provisions which 

allow States to develop cap and trade 

programs or other alternative measures 

in lieu of the application of BART on a 

source specific basis. (See 40 CFR 

51.308(e)(2) and 64 FR 35714, 35741–

35743, July 1, 1999). The proposal was 

based on the application of the 

proposed two-pronged test for whether 

an alternative to BART is ‘‘better than 

BART’’ which was proposed in the 2001 

BART guidelines and reproposed 

without changes in our May, 2004 

proposed guidelines for BART 

determinations (69 FR 25184, May 5, 

2004). 

Specifically, the re-proposed BART 

Guidelines provide that if the 

geographic distribution of emissions 

reductions is anticipated to be similar 

under both programs, the trading 

program (or other alternative measure) 

must be shown to achieve greater 

overall emissions reductions than the 

application of source-specific BART. If 

the trading program is anticipated to 

result in a different geographic 

distribution of emissions reductions 

than would source-specific BART, the 

trading program must be shown to result 

in no decline in visibility at any Class 

I area, and in an overall improvement in 

visibility on an average basis over all 

affected Class I areas (69 FR 25184, 

25231). Because we had not yet 

determined whether there is a difference 

in the geographic distribution of 

emissions reductions between the CAIR 

and the application of source-specific 

BART in the CAIR region, we assessed 

the difference between the two 

programs by evaluating the visibility 

impacts of each program, using this 

proposed two-pronged test. 

The emissions projections and air 

quality modeling used to demonstrate 

that the CAIR satisfies this proposed 

two-pronged test were presented in a 

document entitled Supplemental Air 

Quality Modeling Technical Support 

Document (TSD) for the Clean Air 

Interstate Rule (May 4, 2004). In brief, 

we found that the CAIR would not 

result in a degradation of visibility from 

current conditions at any Class I Area 

nationwide. Within the CAIR-affected 

States and New England, EPA found 

that the CAIR would produce greater 

visibility benefits—specifically, an 

average improvement of 2.0 deciviews, 

as compared to 1.0 for BART. The EPA 

also found that average visibility 

improvement for Class I areas 

nationwide would be 0.7 deciviews 

under the CAIR, compared to 0.4 

deciviews under BART. The EPA noted 

in the SNPR and the TSD that because 

the emissions scenarios used in these 

analyses were developed for different 

purposes, the scenarios varied slightly 

from the scenarios which would be 

ideal for this test. The EPA committed 

to conduct additional analyses, and 

those analyses have now been done. The 

new modeling and results are discussed 

in more detail in section IX.C.2 below. 

b. Comments and EPA’s Responses 

Several commenters argued that a 

categorical exclusion of sources from 

BART would violate the CAA, as 

interpreted by the U.S. Court of Appeals 

for the DC Circuit in American Corn 

Growers v. EPA, 291 F.3d 1, 2002, by 

illegally constraining the discretion 

Congress conferred to States in making 

BART determinations and by depriving 

States of an adequate opportunity to 

evaluate the emissions reductions in 

light of the BART requirement. Some 

States also expressed a desire to retain 

their discretion to require BART. 

Additionally, some commenters 

asserted that EPA could not offer an 

exemption to BART unless the 

conditions for exemptions provided by 

CAA 169A(c) are met, including a 

showing that the source in question will 

not, alone or in combination with other 

sources, emit any pollutant which may 

reasonably be anticipated to cause or 

contribute to impairment at any Class I 

area, and the concurrence of the 

appropriate Federal Land Manager with 

the exemption determination.

The EPA agrees that under the CAA 

and the American Corn Growers case, 

EPA may not preclude a State from 

conducting its own BART analysis, nor 

from requiring BART controls at 

individual sources as determined 

appropriate through such analysis. 

Accordingly, as noted above, the 

proposed regulatory change to the 

Regional Haze Rule would provide that 

a CAIR affected State ‘‘need not require 

affected BART-eligible EGUs to install, 

operate, and maintain BART’’ if such 

State opts to participate in the CAIR cap 

and trade program. The optional nature 

of this language (‘‘need not’’ rather than 

‘‘may not’’) is consistent with the 

American Corn Growers decision, 

because it does not attempt to mandate 

that States must consider the CAIR as 

having met the requirements of BART. 

The SNPR preamble summarized the 

proposal by stating that ‘‘EPA proposes 

that BART-eligible EGUs in any State 

affected by CAIR may be exempted from 

BART controls for SO2 and NOX if that 

State complies with the CAIR 

requirements through adoption of the 

CAIR cap and trade programs for SO2

and NOX emissions.’’ (69 FR 3270). That 

statement accurately reflected the 

optional nature of the better-than-BART 

substitution policy, by providing that 

sources ‘‘may’’ be granted such 

regulatory flexibility. However, the use 

of the term ‘‘exempted’’ in this context 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25301

156CAIR is linked to visibility improvements 

insofar as it attempts to make progress towards 

attainment of the PM2.5 NAAQS, which would, 

among other things, improve visibility.

157See ‘‘2002 Base Year Emission Inventory SIP 

Planning: 8-hr Ozone, PM2.5 and Regional Haze 

Programs,’’ November 8, 2002, Guidance 

Memorandum, http://www.epa.gov/ttn/oarpg/t1/

memoranda/2002bye_gm.pdf.

158The purpose of providing a cut-off year for SIP 

measures to which the alternative must be surplus 

is to prevent an untenable situation where programs 

being developed simultaneously must be surplus to 

each other. Establishing a baseline year allows 

States to continue to make reductions between that 

baseline date and the submittal of regional haze 

SIPs without being ‘‘penalized’’ for those reductions 

by not being allowed to count them as contributing 

to reasonable progress towards the national 

visibility goal.

was somewhat imprecise. EPA agrees 

that sources may not be ‘‘exempt’’ from 

BART requirements unless the 

requirements of 169A(c) are fulfilled. 

The better-than-BART policy is not an 

‘‘exemption’’ from BART; it is an 

alternative regulatory program that 

would allow Congressionally required 

emissions reductions from BARTeligible sources to be made in a more 

cost-effective manner. Moreover, as 

explained elsewhere in the SNPR and 

again below, BART-eligible EGUs would 

not be ‘‘exempt’’ from BART because, 

until the emissions reductions required 

by the CAIR are fully realized, such 

sources would remain subject to the 

possibility of being required to install 

BART controls if deemed necessary to 

meet requirements regarding reasonably 

attributable visibility impairment, as 

provided by 40 CFR 51.302. 

Several commenters asserted that 

because Congress singled out 26 source 

categories for the application of BART, 

there is no basis in law for EPA to 

‘‘exempt’’ some of these categories. 

These comments amount to facial 

challenges of EPA’s authority to approve 

SIPs which contain alternative 

strategies, rather than source-specific 

BART requirements, for BART-eligible 

sources. 

The EPA’s authority to approve 

alternative measures to BART, where 

those measures achieve greater 

reasonable progress than would BART, 

was recently upheld by the DC Circuit. 

(CEED, slip. op. at 13). See also Central 

Arizona Water Conservation District v. 

EPA, 990 F.2d 1531, 1543, (1993) 

(Upholding EPA’s interpretation of CAA 

169A(b)(2)as providing discretion to 

adopt implementation plan provisions 

other than those provided by BART 

analyses in situations where the agency 

reasonably concludes that more 

reasonable progress will thereby be 

attained). 

Similarly, some commenters stated 

that the CAIR could not substitute for 

BART because the CAIR and BART are 

authorized by separate parts of the CAA. 

They argue that allowing reductions 

required by a provision of the CAA not 

linked to visibility improvement to 

substitute for BART would alter 

Congress’ ‘‘mandate’’ that certain source 

categories make reductions for visibility 

in excess of what other CAA provisions 

require of those sources.156 Commenters 

also point to Regional Haze Rule section 

308(e)(2), as evidence that reductions 

from other programs such as title IV and 

the NOX SIP Call must be achieved in 

addition to, and not as a substitute for, 

BART. Commenters also argue that EPA 

(and States) will need all available tools, 

including BART, to meet visibility and 

NAAQS requirements.

Again, under our interpretation of 

CAA section 169A(b)(2) as upheld in 

CEED and Central Arizona Water,

Congress did not ‘‘mandate’’ that 

emission reductions from certain source 

categories be obtained by the 

installation of BART controls. Instead, 

the CAA allows for alternative measures 

to BART—whether for EGUs or nonEGUs—where those measures result in 

greater reasonable progress, and as 

explained below, we have determined 

that greater reasonable progress can be 

obtained from the EGU sector through 

the use of the CAIR cap and trade 

program. However, if a State believes 

more progress can be made at affected 

Class I areas by utilizing BART, the 

State need not make the determination 

that the CAIR substitutes for BART in 

that State. Therefore, EPA is not 

eliminating any tools available to the 

States. 

With respect to Regional Haze Rule 

section 308(e)(2), EPA does not believe 

that this section provides any support 

for the notion that emissions reductions 

from other programs must necessarily be 

in addition to, not substitute, for BART. 

We first note that the decision in CEED 

necessitates revisions to 308(e)(2), at 

least in the provisions requiring 

visibility to be evaluated on a 

cumulative basis in defining the BART 

benchmark for comparison to BART 

alternative programs. It remains to be 

seen whether 308(e)(2)(iv), which 

requires that emissions reductions from 

the BART alternative be ‘‘surplus to 

reductions resulting from measures 

adopted to meet requirements as of the 

baseline date of the SIP,’’ will be 

changed. Even if that section remains 

unchanged, the CAIR complies with it. 

The baseline date of Regional Haze SIPs 

is 2002.157 Since any emissions 

reduction requirements to meet the 

CAIR would necessarily be adopted 

after 2002, CAIR-required reductions 

would clearly be surplus to measures 

adopted as of the baseline year.158

Several commenters argued that the 

question of whether BART is better than 

the CAIR is properly addressed in the 

BART rulemaking, not in today’s action, 

and that the better-than-BART 

determination is otherwise premature. 

While EPA believes that our current 

analysis demonstrates that the CAIR is 

better than BART (based on the criteria 

in our May 2004 BART proposal), and 

that the range of uncertainty regarding 

the presumptive BART controls for 

EGUs to be finalized in the BART 

guidelines is not likely to alter that 

demonstration, we agree that we cannot 

make a final determination that CAIR is 

better than BART until the changes to 

the regional haze regulations required 

by both American Corn Growers and 

CEED are finalized.

Several commenters felt the CAIR 

should be considered better than BART 

for a State whether or not that State 

participates in the CAIR cap and trade 

program, as long as the State achieves 

its emission reduction requirement 

under the CAIR. Conversely, one 

commenter felt that CAIR reductions 

should be considered better than BART 

only when a State does not participate 

in the cap and trade program, thereby 

ensuring that the reductions will occur 

in-State. 

Our preliminary demonstration that 

the CAIR results in more reasonable 

progress than BART for EGUs is based 

on a comparison of emissions 

reductions from EGUs, and attendant air 

quality effects, under the CAIR as 

compared to under BART as proposed 

in May, 2004. If emissions reductions 

are achieved from other source sectors, 

a similar analysis would have to be 

conducted for those sector(s) before it 

could be determined that the reductions 

were better than BART for affected 

source categories. For example, if a State 

either wants to use EGU emissions 

reductions under the CAIR to substitute 

for BART for non-EGUs, or use non-EGU 

emissions reductions to substitute for 

BART for EGUs, that could be allowed 

as an alternative measure to BART 

provided a similar ‘‘better-than-BART’’

determination is made for the sectors 

involved. 

A few commenters believed EPA 

should not limit the substitution of the 

CAIR for BART to States that are 

required to meet CAIR for both SO2 and 

NOX on an annual basis, but rather 

should also allow it for States which are 

only required to reduce NOX during the 

ozone season. Because the modeling 

scenarios were based on the pollutants 

25302 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

159The question of whether section 169A(b)(2) 

requires BART based on contribution to impairment 

at any Class I area is separate from the question of 

whether this section requires source-specific BART 

under all circumstances. As noted earlier, we 

interpret section 169A(b)(2) as requiring BART only 

as needed to make reasonable progress, thus 

allowing for alternative measures which make 

greater reasonable progress.

covered by the CAIR in each affected 

State, our better-than-BART 

demonstration is limited to those 

scenarios. A State subject to the CAIR 

for NOX purposes only would have to 

make a supplementary demonstration 

that BART has been satisfied for SO2, as 

well as for NOX on an annual basis. 

A few commenters believed that the 

CAIR should satisfy BART for purposes 

of reasonably attributable visibility 

impairment as well as BART for 

purposes of regional haze. Several 

others commented that it was 

appropriate or legally necessary to 

preserve the authority of Federal Land 

Managers (FLMs) and States to certify 

impairment and make reasonable 

attribution determinations, which could 

subject a source to BART requirements 

even if the source is a participant in the 

CAIR cap and trade program. These 

commenters supported the use of a 

strategy similar to that employed by the 

Western Regional Air Partnership, 

which relies upon a Memorandum Of 

Understanding (MOU) between the 

FLMs and the States regarding the 

criteria by which certifications of 

impairment may be made, along with 

the possibility of ‘‘geographic 

enhancements’’ to the cap and trade 

program to accommodate the imposition 

of source-specific BART control 

requirements on a source within the cap 

and trade program. 

As proposed in the SNPR, EPA 

continues to believe that reasonably 

attributable visibility impairment 

determinations under 40 CFR 51.302 

must continue to be a viable option in 

order to insure against any possibility of 

hot-spots. We believe that a certification 

of reasonably attributable visibility 

impairment is fairly unlikely, given that 

there have been few such certifications 

since 1980, and given that the 

reductions from the CAIR and other 

recent initiatives will make such 

certifications decreasingly likely. We 

believe sources can be given sufficient 

regulatory certainty to enable effective 

participation in a cap and trade program 

through the use of MOUs and 

geographic enhancement provisions. 

Some commenters believe that 

because section 169A(b)(2)(A) requires 

BART for an eligible source which may 

reasonably be anticipated to cause or 

contribute to any impairment of 

visibility in any Class I area, EPA is 

without basis in law or regulation to 

base a better-than-BART determination 

on an analysis that does not evaluate 

visibility improvement at each and 

every Class I area, or one that uses 

averaging of visibility improvement 

across different Class I areas. 

The criteria we applied in our present 

analysis—that greater reasonable 

progress is defined as no degradation at 

any Class I area, and greater overall 

average improvement—have not been 

finalized. However, we disagree with 

comments that 169A(b)(2)’s requirement 

of BART for sources reasonably 

anticipated to contribute to impairment 

at any Class I area 159 means that an 

alternative to the BART program must 

be shown to create improvement at each 

and every Class I area. Even if a BART 

alternative is deemed to satisfy BART 

for regional haze purposes, based on 

average overall improvement as 

opposed to improvement at each and 

every Class I Area, 169A(b)(2)’s trigger 

for BART based on impairment at any 

Class I area remains in effect, because a 

source may become subject to BART 

based on ‘‘reasonably attributable 

visibility impairment’’ at any area. (The 

EPA believes it is unlikely that a State 

or FLM will have need to certify 

reasonably attributable visibility 

impairment (RAVI) with respect to any 

EGU in the CAIR region, but 

nevertheless believes it is necessary to 

preserve this safeguard).

We also received a number of 

comments regarding the broader 

relationship between the CAIR and 

regional haze, including whether the 

CAIR meets reasonable progress 

requirements, as well as BART, for 

affected States; whether EPA should 

allow non-CAIR States to opt in to the 

CAIR cap and trade program to meet 

their BART requirements; and whether 

regional haze provisions should be used 

as a basis for expanding the CAIR rule 

to the rest of the States which were not 

included on the basis of contribution to 

PM2.5 and ozone nonattainment. The 

EPA’s responses to comments on these 

broader issues, which are not germane 

to the issue of whether the CAIR may 

substitute for BART for affected EGUs, 

are contained in the Response to 

Comment Document. 

c. Today’s Action 

As discussed above, EPA has the 

authority to approve SIPs which rely 

upon a cap and trade program as an 

alternative to BART. However, at this 

time, we are deferring a final 

determination that, in EPA’s view, the 

CAIR makes greater progress than BART 

for CAIR-affected States until such time 

as the BART guidelines for EGUs and 

the criteria for BART-alternative 

programs are finalized. At that time, 

contingent upon supporting analysis 

and our final rules governing the 

regional haze program, EPA will make 

a final determination as to whether the 

CAIR makes greater progress than 

BART, and can be relied on as an 

alternative measure in lieu of BART. 

2. What Improvements Did EPA Make to 

the Bart Versus the CAIR Modeling, and 

What Are the New Results? 

a. Supplemental Notice of Proposed 

Rulemaking 

For the better-than-BART analysis in 

the SNPR, we used the Integrated 

Planning Model (IPM) to estimate 

emissions expected after 

implementation of a source-specific 

BART approach and after 

implementation of the CAIR cap and 

trade program for EGUs. We then used 

the Regional Modeling System for 

Aerosols and Deposition (REMSAD) air 

quality model to project the visibility 

impact of these IPM emissions 

predictions for both the CAIR and the 

nationwide source-specific BART 

scenarios. Specifically, EPA evaluated 

the model results for the 20 percent best 

days (that is, least visibility impaired) 

and the 20 percent worst days at 44 

Class I areas throughout the country. 

Thirteen of these Class I areas are within 

States affected by the CAIR proposal, 

and 31 Class I areas are outside the 

CAIR region—29 in States to the west of 

the CAIR region, and 2 in New England 

States northeast of the CAIR region. 

As explained in the SNPR, the 

‘‘CAIR’’ scenario modeled was imperfect 

for purposes of this analysis in that it 

assumed SO2 reductions on a 

nationwide basis (rather than in the 

CAIR region only) and assumed NOX

reductions requirements in a slightly 

different geographic region than covered 

by the proposed CAIR. The ideal 

scenario would have correctly 

represented the geographic scope of the 

CAIR SO2 and NOX reduction 

requirements, and included sourcespecific BART controls in areas outside 

the CAIR region. (This corrected 

scenario has been modeled for the NFR, 

as explained below). 

The SNPR REMSAD modeling 

showed that under the proposed twopronged test, CAIR controls achieved 

equal or greater visibility improvement 

than the application of source-specific 

BART to EGUs nationwide. The 

modeling predicted that the CAIR cap 

and trade program will not result in 

degradation of visibility, compared to 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25303

160Because the presumptive controls in the BART 

guidelines are applicable to coal-fired EGUs, the 

BART analysis does not assume controls on oil- and 

gas-fired units. However, NOX emissions from all 

(not just BART-eligible) oil and gas steam plants 

and simple cycle turbines in the CAIR region in the 

2010 base case are projected to be about 40,000 

tons, or less than 1.5% of the projected total 2010 

EGU emissions. By comparison, the modeling of the 

scenario of the CAIR (with BART in the non-CAIR 

region) resulted in 640,000 tons of NOX per year 

less than the projected emissions under a 

nationwide BART scenario. Therefore, even if the 

40,000 tons of NOX emissions from oil and gas 

EGUs were reduced to zero under the BART 

scenario, the CAIR will still produce significantly 

greater emission reductions than BART. Also, not 

all of the oil and gas units associated with those 

40,000 tons would be eligible for BART. The IPM 

does not predict any difference in SO2 emissions 

from oil or gas-fired units between the CAIR and 

BART.

161See ‘‘Memo From Perrin Quarles Associates, 

Inc. Re Follow-Up on Units Potentially Affected by 

BART, July 19, 2004,’’ as Appendix A to the ‘‘Better 

than BART’’ TSD.

162Some Class I areas do not have IMPROVE 

monitors and are represented by nearby IMPROVE 

sites.

163This is the number of IMPROVE sites that are 

located at or represent Class I areas. There are 

additional IMPROVE protocol monitoring sites that 

are not located at Class I areas.

164There are 5 Class I areas in the East and 33 

Class I areas in the West (outside of the CAIR 

control region) that do not have complete IMPROVE 

data for 2001.

165 ‘‘Demonstration that CAIR Satisfies the ‘Betterthan-BART’ Test As Proposed in the Guidelines for 

Making BART Determinations,’’ March, 2005.

166See Better-than-BART TSD for results at each 

Class I Area.

existing (1998–2002) visibility 

conditions, at any of the 44 Class I areas 

considered. It also indicated that CAIR 

emissions reductions as modeled 

produce significantly greater visibility 

improvements than source-specific 

BART. Specifically, for the 15 Eastern 

Class I areas analyzed, the average 

visibility improvement (on the 20 

percent worst days) expected solely as 

a result of the CAIR was 2.0 deciviews, 

and the average degree of improvement 

predicted for source-specific BART was 

1.0 deciviews. Similarly, on a national 

basis, the visibility modeling showed 

that for all 44 Class I areas evaluated, 

the average visibility improvement, on 

the 20 percent worst days, in 2015 was 

0.7 deciviews under the CAIR cap and 

trade program, but only 0.4 deciviews 

under the source-specific BART 

approach.

b. Comments and EPA Responses 

Several commenters noted that EPA 

did not model the ‘‘correct’’ emissions 

scenarios to compare the CAIR and 

BART controls. They suggested that a 

model run with the CAIR controls in the 

East and BART controls in the West 

should be compared to a model run 

with nationwide BART controls. 

The EPA agrees (as we have already 

noted in the SNPR) that the suggested 

comparison of model runs is a more 

appropriate comparison of the CAIR and 

BART. The SNPR better-than-BART 

analysis was limited by the availability 

of the model results at the time. For the 

NFR, we have modeled nationwide 

BART for EGUs as proposed in the May 

2004 guidelines and a separate scenario 

consisting of CAIR reductions in the 

CAIR-affected States plus BARTreductions in the remaining States 

(excluding Alaska and Hawaii). 

Additionally, we have improved the 

BART control assumptions (in both 

scenarios) by increasing the number of 

BART-eligible units included. 

Specifically, in the SNPR analysis, 

controls were ‘‘required’’ (i.e., assumed 

by the model) for BART-eligible EGUs 

greater than 250 MW capacity, for both 

NOX and SO2. For today’s action, BART 

controls are assumed for SO2 for all 

BART-eligible EGU units greater than 

100 MW, and NOX controls for all 

BART-eligible EGU units greater than 25 

MW.160 This, along with a review of 

potentially BART-eligible EGUs, has 

expanded the universe of units assumed 

subject to BART in the modeling from 

302 to 491.161

Several commenters noted that the 

better-than-BART visibility analysis 

only covered 44 Class I areas and did 

not adequately address visibility in all 

areas of the country. 

For the NFR, we have significantly 

expanded the number of Class I areas 

covered by the analysis. The NPR and 

SNPR visibility analysis was limited by 

the availability of observed data from 

Inter-agency Monitoring of Protected 

Visual Environments (IMPROVE) 

monitors during the meteorological 

modeling year of 1996. There was 

complete IMPROVE data at 44 

IMPROVE sites which represented 68 

Class I areas.162 All of the regions of the 

country (as defined by IMPROVE) were 

represented by at least one site, except 

the Northern Great Lakes region. For the 

final rule, the modeling has been 

updated to use a meteorological year of 

2001. Therefore, the IMPROVE data for 

2001 was used for the NFR better-thanBART analysis. For 2001, there were 81 

IMPROVE sites with complete data,163

representing 116 Class I areas. The NFR 

analysis accounts for visibility changes 

at 80 percent of the active IMPROVE 

sites in the lower 48 States. More 

importantly for today’s rulemaking, the 

number of Class I areas in the East has 

been increased from 15 to 29 and now 

covers all IMPROVE-defined visibility 

regions within the CAIR-affected States, 

including the Northern Great Lakes.164

We, therefore, believe the expanded 

geographic scope of Class I areas 

covered is sufficient for purposes of this 

analysis.

c. Today’s Action

We have compared the two model 

runs (BART nationwide and BART in 

the West with the CAIR in the East) 

using the proposed two-pronged betterthan-BART test. The results were 

analyzed at the 116 Class I areas that 

have complete IMPROVE data for 2001 

or are represented by IMPROVE 

monitors with complete data. Twentynine of the Class I areas are in the East 

and 87 are in the West. Detailed 

modeling results for all 116 Class I areas 

are contained in the Better-than-BART 

TSD.165 Results applicable to the betterthan-BART proposed two-pronged test 

are summarized below.

The updated visibility analysis 

reaffirms that under the proposed twopronged test, CAIR controls are better 

than BART for EGUs. The modeling 

predicts that the CAIR cap and trade 

program will not result in degradation 

of visibility on the 20 percent best or 20 

percent worst days compared to the 

2015 baseline conditions, at any of the 

116 Class I areas considered.166

With respect to the greater-averageimprovement prong, the modeling 

indicates that CAIR emissions 

reductions in the East produce 

significantly greater visibility 

improvements than source-specific 

BART. Specifically, for the 29 Eastern 

Class I areas analyzed, the average 

visibility improvement, on the 20 

percent worst days, expected solely as a 

result of the CAIR applied in the East 

and BART applied in the West is 1.6 dv, 

as compared to the average degree of 

improvement predicted for nationwide 

source-specific BART of 0.7 dv. 

Similarly, on a national basis, the 

visibility modeling showed that for all 

116 Class I areas evaluated, the average 

visibility improvement, on the 20 

percent worst days, in 2015 was 0.5 dv 

under the CAIR cap and trade program 

in the East and BART in the West, but 

only 0.2 deciviews under the 

nationwide source-specific BART 

approach. 

The modeling showed similar results 

for the 20 percent best visibility days, 

although there is less visibility 

improvement on the best days compared 

to the worst days. For the 29 Eastern 

Class I areas analyzed, the average 

visibility improvement, on the 20 

percent best days, expected solely as 

result of the CAIR applied in the East 

and BART applied in the West is 0.4 dv, 

as compared to the average degree of 

25304 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

167Eastern Class I areas are those in the CAIR 

affected states, except areas in west Texas which are 

considered western and therefore included in the 

national average, plus those in New England.

improvement predicted for nationwide 

source-specific BART of 0.2 dv. On a 

national basis, the visibility modeling 

showed that for all 116 class I areas 

evaluated, the average visibility 

improvement, on the 20 percent best 

days, in 2015 was 0.1 dv under both the 

CAIR cap and trade program in the East 

and BART in the West, and under the 

nationwide source-specific BART 

approach. The results are summarized 

in table IX–1.

TABLE IX–1.—AVERAGE VISIBILITY IMPROVEMENT IN 2015 VS. 2015 

Base Case (deciviews) 

Class I Areas 

CAIR + BART in West Nationwide BART 

East 167 National East National 

20% Worst Days .............................................................................................................. 1.6 0.5 0.7 0.2 

20% Best Days ................................................................................................................ 0.4 0.1 0.2 0.1 

The results clearly indicate that the 

CAIR will achieve greater reasonable 

progress than BART as proposed, 

measured by the proposed better-thanBART test. At this time, we can foresee 

no circumstances under which BART 

for EGUs could produce greater 

visibility improvement than the CAIR. 

However, for the reasons noted in 

section IX.C.1. above, we are deferring 

a final determination of whether the 

CAIR makes greater reasonable progress 

than BART until the BART guidelines 

for EGUs and the criteria for BARTalternative programs are finalized.

D. How Will EPA Handle State Petitions 

Under Section 126 of the CAA? 

Section 126 of the CAA authorizes a 

downwind State to petition EPA for a 

finding that any new (or modified) or 

existing major stationary source or 

group of stationary sources upwind of 

the State emits or would emit in 

violation of the prohibition of section 

110(a)(2)(D)(i) because their emissions 

contribute significantly to 

nonattainment, or interfere with 

maintenance, of a NAAQS in the State. 

If EPA makes such a finding, EPA is 

authorized to directly regulate the 

affected sources. Section 126 relies on 

the same statutory provision that 

underlies the CAIR. 

In the January 30, 2004 CAIR 

proposal, EPA set forth its general view 

of the approach it expected to take in 

responding to any section 126 petition 

that might be submitted which relies on 

essentially the same record as the CAIR. 

That approach is the one EPA used in 

addressing section 126 petitions that 

were submitted to EPA in 1997 while 

EPA was developing the NOX SIP Call 

to control ozone transport. In the NOX

SIP Call rule, we determined under 

section 110(a)(2)(D) that the SIP for each 

affected State (and the District of 

Columbia) must be revised to eliminate 

the amount of emissions that 

contributes significantly to 

nonattainment in downwind States. The 

emissions reductions requirement was 

based on the quantity of emissions that 

could be eliminated by the application 

of highly cost-effective controls on 

specified sources in that State. In May 

1999, shortly after promulgation of the 

NOX SIP Call, EPA took final action on 

the section 126 petitions (64 FR 28250; 

May 25, 1999). The Section 126 action 

relied on essentially the same record as 

the NOX SIP Call. In addition, we 

established a section 126 remedy based 

on the same set of highly cost-effective 

controls. In the May 1999 Section 126 

Rule, we determined which petitions 

had technical merit, but we stopped 

short of granting the findings for the 

petitions. Instead, we stated that 

because we had promulgated the NOX

SIP Call—a transport rule under section 

110(a)(2)(D)—as long as an upwind 

State remained on track to comply with 

that rule, EPA would defer making the 

section 126 findings. The findings 

would be triggered at either of two 

future dates if specified progress had 

not been made by those times. The 

Section 126 Rule included a provision 

under which the rule would be 

automatically withdrawn for sources in 

a State once that State submitted and 

EPA fully approved a SIP that complied 

with the NOX SIP Call. (See 64 FR 

28271–28274; May 25, 1999.) The 

reason for this withdrawal would be the 

fact that the affected State’s SIP revision 

would fulfill the section 110(a)(2)(D) 

requirements, so that there would no 

longer be any basis for the section 126 

finding with respect to that State. In this 

manner, the NOX SIP Call and the 

Section 126 Rules would be 

harmonized. 

Under the CAIR proposal, EPA 

received comments regarding its 

intended approach for acting on any 

future section 126 petitions that might 

be filed. Many commenters expressed 

support for the approach that EPA had 

outlined. Other commenters raised 

issues regarding the timing of emissions 

reductions under a new section 126 

action. Some pointed out that the CAIR 

compliance date would be later than the 

3 years allowed for compliance under 

section 126. Some were concerned that 

the proposed CAIR compliance date is 

later than many attainment dates and 

States may need section 126 petitions in 

order to get earlier upwind reductions 

in order to meet their attainment dates. 

Some questioned the legal basis for 

linking the two rules. Several 

commenters expressed concern that 

EPA would be restricting the use of or 

weakening the section 126 provision. A 

number of commenters urged EPA not 

to prejudge any petition, but to evaluate 

each on its own merit. Some thought 

that any petitions submitted prior to 

designations or before States had had 

the opportunity to prepare SIPs would 

be premature and should be denied. 

Others suggested that CAIR might not 

solve all the transport problems and that 

States would need to retain the section 

126 tool to seek further reductions. 

After issuing the CAIR proposal, EPA 

received, on March 19, 2004, a section 

126 petition from North Carolina 

seeking reductions in upwind NOX and 

SO2 for purposes of reducing PM2.5 and 

8-hour ozone levels in North Carolina. 

The petition relies in large part on the 

technical record for the proposed CAIR.

When we propose action on the North 

Carolina petition, we will set forth our 

view of the interaction between section 

110(a)(2)(D) and section 126. In that 

proposal, we will take into 

consideration and respond to the 

section 126-related comments we 

received on the CAIR. The EPA will 

provide a comment period and 

opportunity for a public hearing on the 

specifics of that section 126 proposal, 

including an opportunity to comment 

on our view of the interaction of the 2 

statutory provisions. 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25305

168See 40 CFR 51.165(a)(1)(xxv) and 51.165(e), 40 

CFR 51.166(b)(31) and 51.166(v), and 40 CFR 

51.21(b)(32) and 52.21(z).

E. Will Sources Subject to CAIR Also Be 

Subject to New Source Review? 

The EPA did not propose any 

provisions in the CAIR related to new 

source review (NSR). Nonetheless, we 

received some comments on the 

relationship between CAIR and the NSR 

provisions that may apply to emissions 

sources also impacted by the CAIR. 

Many commenters indicated that if an 

EGU is part of an EPA-administered 

regional cap and trade program for NOX

and SO2, then that EGU should be 

exempted from NSR for the covered 

pollutants. The commenters cited Clear 

Skies legislation as containing 

provisions affecting NSR for covered 

sources. In this final rule, EPA is not 

addressing or revising the provisions of 

NSR. 

It should be noted that pollution 

control measures implemented by EGUs 

in compliance with the CAIR may be 

eligible for an exemption under the NSR 

pollution control project provision.168

These provisions provide an exemption 

from major NSR for controls such as 

selective catalytic reduction (SCR) for 

NOX control and wet scrubbers for SO2

control, provided that certain conditions 

identified in the provisions are met.

X. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

Under Executive Order 12866 (58 FR 

51735, October 4, 1993), the Agency 

must determine whether a regulatory 

action is ‘‘significant’’ and therefore 

subject to Office of Management and 

Budget (OMB) review and the 

requirements of the Executive Order. 

The Order defines ‘‘significant 

regulatory action’’ as one that is likely 

to result in a rule that may: 

1. Have an annual effect on the 

economy of $100 million or more or 

adversely affect in a material way the 

economy, a sector of the economy, 

productivity, competition, jobs, the 

environment, public health or safety, or 

State, local, or Tribal governments or 

communities; 

2. Create a serious inconsistency or 

otherwise interfere with an action taken 

or planned by another agency; 

3. Materially alter the budgetary 

impact of entitlements, grants, user fees, 

or loan programs or the rights and 

obligations of recipients thereof; or 

4. Raise novel legal or policy issues 

arising out of legal mandates, the 

President’s priorities, or the principles 

set forth in the Executive Order. 

In view of its important policy 

implications and potential effect on the 

economy of over $100 million, this 

action has been judged to be an 

economically ‘‘significant regulatory 

action’’ within the meaning of the 

Executive Order. As a result, today’s 

action was submitted to OMB for 

review, and EPA has prepared an 

economic analysis of the rule entitled 

‘‘Regulatory Impact Analysis of the 

Final Clean Air Interstate Rule’’ (March 

2005). 

1. What Economic Analyses Were 

Conducted for the Rulemaking? 

The analyses conducted for this final 

rule provide several important analyses 

of impacts on public welfare. These 

include an analysis of the social 

benefits, social costs, and net benefits of 

the regulatory scenario. The economic 

analyses also address issues involving 

small business impacts, unfunded 

mandates (including impacts for Tribal 

governments), environmental justice, 

children’s health, energy impacts, and 

requirements of the Paperwork 

Reduction Act (PRA). 

2. What Are the Benefits and Costs of 

This Rule? 

The benefit-cost analysis shows that 

substantial net economic benefits to 

society are likely to be achieved due to 

reductions in emissions resulting from 

this rule. The results detailed below 

show that this rule would be highly 

beneficial to society, with annual net 

benefits (benefits less costs) of 

approximately $71.4 or $60.4 billion in 

2010 and $98.5 or $83.2 billion in 2015. 

These alternative net benefits estimates 

occur due to differing assumptions 

concerning the social discount rate used 

to estimate the annual value of the 

benefits and costs of the rule with the 

lower estimates relating to a discount 

rate of 7 percent and the higher 

estimates a discount rate of 3 percent. 

All amounts are reflected in 1999 

dollars. 

The benefits and costs reported for the 

CAIR represent estimates for the final 

CAIR program that includes the CAIR 

promulgated rule and the concurrent 

proposal to include annual SO2 and 

NOX controls for New Jersey and 

Delaware. The modeling used to provide 

these estimates also assumes annual SO2

and NOX controls for Arkansas that are 

not a part of the final CAIR program 

resulting in a slight overstatement of the 

reported benefits and costs.

a. Control Scenario 

Today’s rule sets forth requirements 

for States to eliminate their significant 

contribution to down-wind 

nonattainment of the ozone and PM2.5

NAAQS. In order to reduce this 

significant contribution, EPA requires 

that certain States reduce their 

emissions of SO2 and NOX. The EPA 

derived the quantities by calculating the 

amount of SO2 and NOX emissions that 

EPA believes can be controlled from the 

electric power industry in a highly costeffective manner. The EPA considered 

all promulgated CAA requirements and 

known State actions in the baseline 

used to develop the estimates of benefits 

and costs for this rule. For a more 

complete description of the reduction 

requirements and how they were 

calculated, see section IV of today’s 

rulemaking. 

Although States may choose to obtain 

the emissions reductions from other 

source categories, for purposes of 

analyzing the impacts of the rule, EPA 

is assuming the application of the 

controls that it has identified to be 

highly cost effective on all EGUs in the 

transport region. 

b. Cost Analysis and Economic Impacts 

For the affected region, the projected 

annual private incremental costs of the 

CAIR to the power industry are $2.4 

billion in 2010 and $3.6 billion in 2015. 

These costs represent the private 

compliance cost to the electric 

generating industry of reducing NOX

and SO2 emissions to meet the caps set 

forth in the rule. Estimates are in 1999 

dollars. 

In estimating the net benefits of 

regulation, the appropriate cost measure 

is ‘‘social costs.’’ Social costs represent 

the welfare costs of the rule to society. 

These costs do not consider transfer 

payments (such as taxes) that are simply 

redistributions of wealth. The social 

costs of this rule are estimated to be 

approximately $1.9 billion in 2010 and 

$2.6 billion in 2015 assuming a 3 

percent discount rate. These costs 

become $2.1 billion in 2010 and $3.1 

billion in 2015 assuming a 7 percent 

discount rate. 

Overall, the impacts of the CAIR are 

modest, particularly in light of the large 

benefits we expect. Ultimately, we 

believe the industry will pass along 

most of the costs of the rule to 

consumers, so that the costs of the rule 

will largely fall upon the consumers of 

electricity. Retail electricity prices are 

projected to increase roughly 2.0–2.7 

percent with the CAIR in the 2010 and 

2015 timeframe, and then drop below 

the 2.0 percent increase level thereafter. 

The effects of the CAIR on natural gas 

prices and the power-sector generation 

mix are relatively small, with a 1.6 

percent or less increase in natural gas 

prices projected from 2010 to 2020. 

25306 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

169Thurston, G.D. and K. Ito. 2001. 

‘‘Epidemiological Studies of Acute Ozone 

Exposures and Mortality’’. J. Expo Anal Environ 

Epidemiology 11 (4) :286–294.

170Bell, M.L., A. McDermott, S. Zeger, J. Samet, 

F. Dominichi. 2005. ‘‘Ozone and Mortality in 95 

U.S. Urban Communities from 1987 to 2000.’’

Journal of the American Medical Association.

Forthcoming.

There will be continued reliance on 

coal-fired generation, that is projected to 

remain at roughly 50 percent of total 

electricity generated. A relatively small 

amount of coal-fired capacity, about 5.3 

GW (1.7 percent of all coal-fired 

capacity and 0.5 percent of all 

generating capacity), is projected to be 

uneconomic to maintain. For the most 

part, these units are small and 

infrequently used generating units that 

are dispersed throughout the CAIR 

region. Units projected to be 

uneconomic to maintain may be 

‘‘mothballed,’’ retired, or kept in service 

to ensure transmission reliability in 

certain parts of the grid. The EPA’s 

analysis does not address these choices. 

As demand grows in the future, 

additional coal-fired generation is 

projected to be built under the CAIR. As 

a result, coal production for electricity 

generation is projected to increase from 

2003 levels by about 15 percent in 2010 

and 25 percent by 2020, and we expect 

a small shift towards greater coal 

production in Appalachia and the 

interior coal regions of the country with 

the CAIR. 

For today’s rule, EPA analyzed the 

costs using the Integrated Planning 

Model (IPM). The IPM is a dynamic 

linear programming model that can be 

used to examine the economic impacts 

of air pollution control policies for SO2

and NOX throughout the contiguous 

U.S. for the entire power system. 

Documentation for IPM can be found in 

the docket for this rulemaking or at 

http://www.epa.gov/airmarkets/epaipm.

c. Human Health Benefit Analysis 

Our analysis of the health and welfare 

benefits anticipated from this rule are 

presented in this section. Briefly, the 

analysis projects major benefits from 

implementation of the rule in 2010 and 

2015. As described below, thousands of 

deaths and other serious health effects 

would be prevented. We are able to 

monetize annual benefits of 

approximately $73.3 or $62.6 billion in 

2010 (based upon a 3 percent or 7 

percent discount rate, respectively) and 

$101 billion or $86.3 billion in 2015 

(based upon a discount rate of 3 percent 

or 7 percent, respectively, 1999 dollars). 

Table X–1 presents the primary 

estimates of reduced incidence of PMand ozone-related health effects for the 

years 2010 and 2015 for the regulatory 

control strategy. In 2015, we estimate 

that PM-related annual benefits include 

approximately 17,000 fewer premature 

fatalities, 8,700 fewer cases of chronic 

bronchitis, 22,000 fewer non-fatal heart 

attacks, 10,500 fewer hospitalizations 

(for respiratory and cardiovascular 

disease combined) and result in 

significant reductions in days of 

restricted activity due to respiratory 

illness (with an estimate of 9.9 million 

fewer cases) and approximately 

1,700,000 fewer work-loss days. We also 

estimate substantial health 

improvements for children from 

reduced upper and lower respiratory 

illness, acute bronchitis, and asthma 

attacks. 

Ozone health-related benefits are 

expected to occur during the summer 

ozone season (usually ranging from May 

to September in the Eastern U.S.). Based 

upon modeling for 2015, annual ozonerelated health benefits are expected to 

include 2,800 fewer hospital admissions 

for respiratory illnesses, 280 fewer 

emergency room admissions for asthma, 

690,000 fewer days with restricted 

activity levels, and 510,000 fewer days 

where children are absent from school 

due to illnesses. 

While we did not include in our 

primary benefits analysis separate 

estimates of the number of premature 

deaths that would be avoided due to 

reductions in ozone levels, recent 

studies suggest a link between shortterm ozone exposures with premature 

mortality independent of PM exposures. 

Based upon a recent report by Thurston 

and Ito, (2001),169 the EPA Science 

Advisory Board has recommended that 

EPA reevaluate the ozone mortality 

literature for possible inclusion of ozone 

mortality in the estimate of total 

benefits. More recently, a 

comprehensive analysis using data from 

the National Morbidity, Mortality and 

Air Pollution Study (NMMAPS) found a 

significant association between daily 

ozone levels and daily mortality rates 

(Bell et al. 2004).170 The analysis 

estimated a 0.5 percent increase in daily 

mortality associated with a 10 ppb 

increase in ozone, based on data from 95 

major urban areas. Using a similar 

magnitude effect estimate, sensitivity 

analysis estimates suggest that in 2015, 

the CAIR would result in an additional 

500 fewer premature deaths annually 

due to reductions in daily ambient 

ozone concentrations. The EPA has 

sponsored three independent metaanalyses of the ozone mortality 

epidemiology literature to inform a 

determination on inclusion of this 

important health impact in the primary 

benefits analysis for future regulations.

Table X–2 presents the estimated 

monetary value of reductions in the 

incidence of health and welfare effects. 

Annual PM-related and ozone-related 

health benefits are estimated to be 

approximately $72.1 or $61.4 billion in 

2010 (3 percent and 7 percent discount 

rate, respectively) and $99.3 or $84.5 

billion in 2015 (3 percent or 7 percent 

discount rate, respectively). Estimated 

annual visibility benefits in 

southeastern Class I areas are 

approximately $1.14 billion in 2010 and 

$1.78 billion in 2015. All monetized 

estimates are stated in 1999$. These 

estimates account for growth in real 

gross domestic product (GDP) per capita 

between the present and the years 2010 

and 2015. As the table indicates, total 

benefits are driven primarily by the 

reduction in premature fatalities each 

year, that accounts for over 90 percent 

of total benefits. 

Table X–3 presents the total 

monetized net benefits for the years 

2010 and 2015. This table also indicates 

with a ‘‘B’’ those additional health and 

environmental benefits of the rule that 

we were unable to quantify or monetize. 

These effects are additive to the estimate 

of total benefits. A listing of the benefit 

categories that could not be quantified 

or monetized in our benefit estimates 

are provided in Table X–4. We are not 

able to estimate the magnitude of these 

unquantified and unmonetized benefits. 

While EPA believes there is 

considerable value to the public for the 

PM-related benefit categories that could 

not be monetized, we believe these 

benefits may be small relative to those 

categories we were able to quantify and 

monetize. In contrast, EPA believes the 

monetary value of the ozone-related 

premature mortality benefits could be 

substantial. As previously discussed, we 

estimate that ozone mortality benefits 

may yield as many as 500 reduced 

premature mortalities per year and may 

increase the benefits of CAIR by 

approximately $3 billion annually. 

d. Quantified and Monetized Welfare 

Benefits

Only a subset of the expected 

visibility benefits—those for Class I 

areas in the southeastern U.S. are 

included in the monetary benefits 

estimates we project for this rule. We 

believe the benefits associated with 

these non-health benefit categories are 

likely significant. For example, we are 

able to quantify significant visibility 

improvements in Class I areas in the 

Northeast and Midwest, but are unable 

at present to place a monetary value on 

these improvements. Similarly, we 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25307

171Pope, C.A., III, R.T. Burnett, M.J. Thun, E.E. 

Calle, D. Krewski, K. Ito, and G.D. Thurston. 2002. 

‘‘Lung Cancer, Cardiopulmonary Mortality, and 

Long-term Exposure to Fine Particulate Air 

Pollution.’’ Journal of American Medical 

Association 287:1132–1141.

172Woodruff, T.J., J. Grillo, and K.C. Schoendorf. 

1997. ‘‘The Relationship Between Selected Causes 

of Postneonatal Infant Mortality and Particulate 

Infant Mortality and Particulate Air Pollution in the 

United States.’’ Environmental Health Perspectives

105(6):608–612.

173U.S. Environmental Protection Agency, 2000. 

Guidelines for Preparing Economic Analyses. 

www.yosemite1.epa.gov/ee/epa/eed/hsf/pages/

Guideline.html. Office of Management and Budget, 

The Executive Office of the President, 2003. 

Circular A–4. http://www.whitehouse.gov/omb/

circulars.

anticipate improvement in visibility in 

residential areas where people live, 

work and recreate within the CAIR 

region for which we are currently 

unable to monetize benefits. For the 

Class I areas in the southeastern U.S., 

we estimate annual benefits of $1.78 

billion beginning in 2015 for visibility 

improvements. The value of visibility 

benefits in areas where we were unable 

to monetize benefits could also be 

substantial. 

We also quantify nitrogen and sulfur 

deposition reductions expected to occur 

as a result of the CAIR and discuss 

potential benefits from these reductions 

in section X.A.4 of this preamble. While 

we are unable to estimate a dollar value 

associated with these benefits, we are 

able to quantify acidification 

improvements in lakes in the Northeast 

including the Adirondacks and 

potential benefits of reductions in 

nitrogen deposition to estuaries such as 

the Chesapeake Bay.

TABLE X–1.—ESTIMATED ANNUAL REDUCTIONS IN INCIDENCE OF HEALTH EFFECTS a

Health Effect 

2010 annual 

incidence reduction 

2015 annual 

incidence reduction 

PM–Related endpoints

Premature Mortality b, c.

Adult, age 30 and over ..................................................................................................................................... 13,000 17,000 

Infant, age <1 year ........................................................................................................................................... 29 36 

Chronic bronchitis (adult, age 26 and over) ............................................................................................................ 6,900 8,700 

Non-fatal myocardial infarction (adult, age 18 and over) ........................................................................................ 17,000 22,000 

Hospital admissions—respiratory (all ages) d .......................................................................................................... 4,300 5,500 

Hospital admissions—cardiovascular (adults, age >18) e ....................................................................................... 3,800 5,000 

Emergency room visits for asthma (age 18 years and younger) ............................................................................ 10,000 13,000 

Acute bronchitis, (children, age 8–12) ..................................................................................................................... 16,000 19,000 

Lower respiratory symptoms (children, age 7–14) .................................................................................................. 190,000 230,000 

Upper respiratory symptoms (asthmatic children, age 9–18) ................................................................................. 150,000 180,000 

Asthma exacerbation (asthmatic children, age 6–18) ............................................................................................. 240,000 290,000 

Work Loss Days ...................................................................................................................................................... 1,400,000 1,700,000 

Minor restricted activity days (adults age 18–65) ................................................................................................... 8,100,000 9,900,000 

Ozone-Related endpoints

Hospital admissions—respiratory causes (adult, 65 and older)f ............................................................................ 610 1,700 

Hospital admissions—respiratory causes (children, under 2) ................................................................................. 380 1,100 

Emergency room visit for asthma (all ages) ........................................................................................................... 100 280 

Minor restricted activity days (adults, age 18–65) .................................................................................................. 280,000 690,000 

School absence days .............................................................................................................................................. 180,000 510,000 

a Incidences are rounded to two significant digits. These estimates represent benefits from the CAIR nationwide. The modeling used to derive 

these incidence estimates are reflective of those expected for the final CAIR program including the CAIR promulgated rule and the proposal to 

include annual SO2 and NOX controls for New Jersey and Delaware. Modeling used to develop these estimates assumes annual SO2 and NOX

controls for Arkansas resulting in a slight overstatement of the reported benefits and costs for the complete CAIR program. bPremature mortality benefits associated with ozone are not analyzed in the primary analysis. 

cAdult mortality based upon studies by Pope, et al. 2002.171 Infant mortality based upon studies by Woodruff, Grillo, and Schoendorf,1997.172

d Respiratory hospital admissions for PM include admissions for chronic obstructive pulmonary disease (COPD), pneumonia and asthma. e Cardiovascular hospital admissions for PM include total cardiovascular and subcategories for ischemic heart disease, dysrhythmias, and heart 

failure. f Respiratory hospital admissions for ozone include admissions for all respiratory causes and subcategories for COPD and pneumonia. 

TABLE X–2.—ESTIMATED ANNUAL MONETARY VALUE OF REDUCTIONS IN INCIDENCE OF HEALTH AND WELFARE EFFECTS

[Millions of 1999$] a, b

Health effect Pollutant 

2010 estimated value 

of reductions 

2015 estimated value 

of reductions 

Premature mortality c, d

Adult >30 years .................. .................... ....................

3 percent discount rate ............................................................................................................... PM2.5 ........ $67,300 $92,800 

7 percent discount rate ............................................................................................................... .................. 56,600 78,100 

Child <1 year ...................................................................................................................................... .................. 168 222 

Chronic bronchitis (adults, 26 and over) ................................................................................................... PM2.5 ........ 2,520 3,340 

Non-fatal acute myocardial infarctions 

3 percent discount rate ....................................................................................................................... PM2.5 ........ 1,420 1,850 

7 percent discount rate ....................................................................................................................... .................. 1,370 1,790 

25308 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

TABLE X–2.—ESTIMATED ANNUAL MONETARY VALUE OF REDUCTIONS IN INCIDENCE OF HEALTH AND WELFARE

EFFECTS—Continued

[Millions of 1999$] a, b

Health effect Pollutant 

2010 estimated value 

of reductions 

2015 estimated value 

of reductions 

Hospital admissions for respiratory causes ............................................................................................... PM2.5, O3 45.2 78.9 

Hospital admissions for cardiovascular causes ........................................................................................ PM2.5 ........ 80.7 105 

Emergency room visits for asthma ............................................................................................................ PM2.5, O3 2.84 3.56 

Acute bronchitis (children, age 8–12) ........................................................................................................ PM2.5 ........ 5.63 7.06 

Lower respiratory symptoms (children, age 7–14) .................................................................................... PM2.5 ........ 2.98 3.74 

Upper respiratory symptoms (asthma, age 9–11) ..................................................................................... PM2.5 ........ 3.80 4.77 

Asthma exacerbations ............................................................................................................................... PM2.5 ........ 10.3 12.7 

Work loss days .......................................................................................................................................... PM2.5, ....... 180 219 

Minor restricted activity days (MRADs) ..................................................................................................... PM2.5, O3 422 543 

School absence days ................................................................................................................................ O3 ............ 12.9 36.4 

Worker productivity (outdoor workers, age 18–65) ................................................................................... O3 ............ 7.66 19.9 

Recreational visibility, 81 Class I areas .................................................................................................... PM2.5 ........ 1,140 1,780 

Monetized Total e

Base estimate .................. .................... ....................

3 percent discount rate ............................................................................................................... PM2.5, O3 73,300 + B 101,000 + B 

7 percent discount rate ............................................................................................................... .................. 62,600 + B 86,300 + B 

a Monetary benefits are rounded to three significant digits. These estimates represent benefits from the CAIR nationwide for NOX and SO2

emissions reductions from electricity-generating units sources (with the exception of ozone and visibility benefits). Ozone benefits relate to the 

eastern United States. Visibility benefits relate to Class I areas in the southeastern United States. The benefit estimates reflected relate to the 

final CAIR program that includes the CAIR promulgated rule and the proposal to include annual SO2 and NOX controls for New Jersey and Delaware. Modeling used to develop these estimates assumes annual SO2 and NOX controls for Arkansas resulting in a slight overstatement of the 

reported benefits and costs for the complete CAIR program. b Monetary benefits adjusted to account for growth in real GDP per capita between 1990 and the analysis year (2010 or 2015). 

cValuation assumes discounting over the SAB recommended 20 year segmented lag structure described in the Regulatory Impact Analysis for 

the Final Clean Air Interstate Rule (March 2005). Results show 3 percent and 7 percent discount rates consistent with EPA and OMB guidelines 

for preparing economic analyses (US EPA, 2000 and OMB, 2003).173

dAdult mortality based upon studies by Pope et al. 2002. Infant mortality based upon studies by Woodruff, Grillo, and Schoendorf, 1997. eB represents the monetary value of health and welfare benefits not monetized. A detailed listing is provided in Table X–4. 

3. How Do the Benefits Compare to the 

Costs of This Final Rule? 

The estimated annual private costs to 

implement the emission reduction 

requirements of the final rule for the 

CAIR region are $2.36 in 2010 and $3.57 

billion in 2015 (1999$). These costs are 

the annual incremental electric 

generation production costs that are 

expected to occur with the CAIR. The 

EPA uses these costs as compliance cost 

estimates in developing costeffectiveness estimates.

In estimating the net benefits of 

regulation, the appropriate cost measure 

is ‘‘social costs.’’ Social costs represent 

the welfare costs of the rule to society. 

These costs do not consider transfer 

payments (such as taxes) that are simply 

redistributions of wealth. The social 

costs of this rule are estimated to be 

approximately $1.9 billion in 2010 and 

$2.6 billion in 2015 assuming a 3 

percent discount rate. These costs 

become $2.1 billion in 2010 and $3.1 

billion in 2015, if one assumes a 7 

percent discount rate. Thus, the net 

benefit (social benefits minus social 

costs) of the program is approximately 

$71.4 + B billion or $60.4 + B billion (3 

percent and 7 percent discount rate, 

respectively) annually in 2010 and 

$98.5 + B billion or $83.2 + B billion 

annually (3 percent and 7 percent 

discount rate, respectively) in 2015. 

Implementation of the rule is expected 

to provide society with a substantial net 

gain in social welfare based on 

economic efficiency criteria. 

The annualized regional cost of the 

CAIR, as quantified here, is EPA’s best 

assessment of the cost of implementing 

the CAIR, assuming that States adopt 

the model cap and trade program. These 

costs are generated from rigorous 

economic modeling of changes in the 

power sector due to the CAIR. This type 

of analysis using IPM has undergone 

peer review and been upheld in Federal 

courts. The direct cost includes, but is 

not limited to, capital investments in 

pollution controls, operating expenses 

of the pollution controls, investments in 

new generating sources, and additional 

fuel expenditures. The EPA believes 

that these costs reflect, as closely as 

possible, the additional costs of the 

CAIR to industry. The relatively small 

cost associated with monitoring 

emissions, reporting, and recordkeeping 

for affected sources is not included in 

these annualized cost estimates, but 

EPA has done a separate analysis and 

estimated the cost to less than $42 

million (see section X. B., Paperwork 

Reduction Act). However, there may 

exist certain costs that EPA has not 

quantified in these estimates. These 

costs may include costs of transitioning 

to the CAIR, such as the costs associated 

with the retirement of smaller or less 

efficient EGUs, employment shifts as 

workers are retrained at the same 

company or re-employed elsewhere in 

the economy, and certain relatively 

small permitting costs associated with 

title IV that new program entrants face. 

Costs may be understated since an 

optimization model was employed that 

assumes cost minimization, and the 

regulated community may not react in 

the same manner to comply with the 

rules. Although EPA has not quantified 

these costs, the Agency believes that 

they are small compared to the 

quantified costs of the program on the 

power sector. The annualized cost 

estimates presented are the best and 

most accurate based upon available 

information. In a separate analysis, EPA 

estimates the indirect costs and impacts 

of higher electricity prices on the entire 

economy [see Regulatory Impact 

Analysis for the Final Clean Air 

Interstate Rule, Appendix E (March 

2005)].

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25309

174United States Environmental Protection 

Agency, 2000. Guidelines for Preparing Economic 

Analyses. www.yosemitel.epa.gov/ee/epa/eed/hsf/

pages/Guideline.html. Office of Management and 

Budget, The Executive Office of the President, 2003. 

Circular A–4. http://www.whitehouse.gov/omb/

circulars.

175Mrozek, J.R. and L.O. Taylor, What determines 

the value of a life? A Meta Analysis, Journal of 

Policy Analysis and Management 21(2), pp. 253–

270.

The costs presented here are EPA’s 

best estimate of the direct private costs 

of the CAIR. For purposes of benefit-cost 

analysis of this rule, EPA has also 

estimated the additional costs of the 

CAIR using alternate discount rates for 

calculating the social costs, parallel to 

the range of discount rates used in the 

estimates of the benefits of the CAIR (3 

percent and 7 percent). Using these 

alternate discount rates, the social costs 

of the CAIR are $1.9 billion in 2010 and 

$2.6 billion in 2015 using a discount 

rate of 3 percent, and $2.1 billion in 

2010 and $3.1 billion in 2015 using a 

discount rate of 7 percent. The costs of 

the CAIR using the adjusted discount 

rates are lower than the private costs of 

the CAIR generated using IPM because 

the social costs do not include certain 

transfer payments, primarily taxes, that 

are considered a redistribution of wealth 

rather than a social cost.174

TABLE X–3.—SUMMARY OF ANNUAL BENEFITS, COSTS, AND NET BENEFITS OF THE CLEAN AIR INTERSTATE RULE a

[Billions of 1999 dollars] 

Description 

2010 (Billions 

of 1999 dollars) 

2015 (Billions 

of 1999 dollars) 

Social Costs: b

3 percent discount rate ......................................................................................................................................... $1.91 ........... $2.56

7 percent discount rate ......................................................................................................................................... 2.14 ............. 3.07

Social Benefits: c,d,e

3 percent discount rate ......................................................................................................................................... 73.3 + B ...... 101 + B 

7 percent discount rate ......................................................................................................................................... 62.6 + B ...... 86.3 + B 

Health-related benefits: 

3 percent discount rate ......................................................................................................................................... 72.1 + B ...... 99.3 + B 

7 percent discount rate ......................................................................................................................................... 61.4 + B ...... 84.5 + B 

Visibility benefits ........................................................................................................................................................... 1.14 + B ...... 1.78 + B 

Annual Net Benefits (Benefits-Costs): e,f

3 percent discount rate ......................................................................................................................................... 71.4 + B ...... 98.5 + B 

7 percent discount rate ......................................................................................................................................... 60.4 + B ...... 83.2 + B 

aAll estimates are rounded to three significant digits and represent annualized benefits and costs anticipated for the years 2010 and 2015. Estimates relate to the complete CAIR program including the CAIR promulgated rule and the proposal to include annual SO2 and NOX controls for 

New Jersey and Delaware. Modeling used to develop these estimates assumes annual SO2 and NOX controls for Arkansas resulting in a slight 

overstatement of the reported benefits and costs for the complete CAIR program. b Note that costs are the annual total costs of reducing pollutants including NOX and SO2 in the CAIR region. cAs this table indicates, total benefits are driven primarily by PM-related health benefits. The reduction in premature fatalities each year accounts for over 90 percent of total monetized benefits in 2015. Benefits in this table are nationwide (with the exception of ozone and visibility) 

and are associated with NOX and SO2 reductions for the EGU source category. Ozone benefits represent benefits in the eastern United States. 

Visibility benefits represent benefits in Class I areas in the southeastern United States. d Not all possible benefits or disbenefits are quantified and monetized in this analysis. B is the sum of all unquantified benefits and disbenefits. 

Potential benefit categories that have not been quantified and monetized are listed in Table X–4. eValuation assumes discounting over the SAB-recommended 20 year segmented lag structure described in chapter 4 of the Regulatory Impact 

Analysis for the Clean Air Interstate Rule (March 2005). Results reflect 3 percent and 7 percent discount rates consistent with EPA and OMB 

guidelines for preparing economic analyses (U.S. EPA, 2000 and OMB, 2003).174

f Net benefits are rounded to the nearest $100 million. Columnar totals may not sum due to rounding. 

Every benefit-cost analysis examining 

the potential effects of a change in 

environmental protection requirements 

is limited to some extent by data gaps, 

limitations in model capabilities (such 

as geographic coverage), and 

uncertainties in the underlying 

scientific and economic studies used to 

configure the benefit and cost models. 

Gaps in the scientific literature often 

result in the inability to estimate 

quantitative changes in health and 

environmental effects. Gaps in the 

economics literature often result in the 

inability to assign economic values even 

to those health and environmental 

outcomes that can be quantified. While 

uncertainties in the underlying 

scientific and economics literatures 

(that may result in overestimation or 

underestimation of benefits) are 

discussed in detail in the economic 

analyses and its supporting documents 

and references, the key uncertainties 

which have a bearing on the results of 

the benefit-cost analysis of this rule 

include the following: 

• EPA’s inability to quantify 

potentially significant benefit categories; 

• Uncertainties in population growth 

and baseline incidence rates; 

• Uncertainties in projection of 

emissions inventories and air quality 

into the future; 

• Uncertainty in the estimated 

relationships of health and welfare 

effects to changes in pollutant 

concentrations including the shape of 

the C–R function, the size of the effect 

estimates, and the relative toxicity of the 

many components of the PM mixture; 

• Uncertainties in exposure 

estimation; and 

• Uncertainties associated with the 

effect of potential future actions to limit 

emissions. 

Despite these uncertainties, we 

believe the benefit-cost analysis 

provides a reasonable indication of the 

expected economic benefits of the 

rulemaking in future years under a set 

of reasonable assumptions. 

In valuing reductions in premature 

fatalities associated with PM, we used a 

value of $5.5 million per statistical life. 

This represents a central value 

consistent with a range of values from 

$1 to $10 million suggested by recent 

meta-analyses of the wage-risk value of 

statistical life (VSL) literature.175

The benefits estimates generated for 

this rule are subject to a number of 

assumptions and uncertainties, that are 

discussed throughout the Regulatory 

Impact Analysis document [Regulatory 

25310 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

176U.S. EPA. (2004). Air Quality Criteria for 

Particulate Matter. Research Triangle Park, NC: 

National Center for Environmental Assessment—

RTP Office; Report No. EPA/600/P–99/002aD.

177Banzhaf, Spencer, Dallas Burtraw, David 

Evans, and Alan Krupnick. ‘‘Valuation of Natural 

Resource Improvements in the Adirondacks,’’

Resources for the Future (RFF), September 2004.

Impact Analysis for the Final Clean Air 

Interstate Rule (March 2005)]. As Table 

X–2 indicates, total benefits are driven 

primarily by the reduction in premature 

fatalities each year. Elaborating on the 

previous uncertainty discussion, some 

key assumptions underlying the primary 

estimate for the premature mortality 

category include the following: 

(1) EPA assumes inhalation of fine 

particles is causally associated with 

premature death at concentrations near 

those experienced by most Americans 

on a daily basis. Plausible biological 

mechanisms for this effect have been 

hypothesized for the endpoints 

included in the primary analysis and 

the weight of the available 

epidemiological evidence supports an 

assumption of causality. 

(2) EPA assumes all fine particles, 

regardless of their chemical 

composition, are equally potent in 

causing premature mortality. This is an 

important assumption, because the 

proportion of certain components in the 

PM mixture produced via precursors 

emitted from EGUs may differ 

significantly from direct PM released 

from automotive engines and other 

industrial sources, but no clear 

scientific grounds exist for supporting 

differential effects estimates by particle 

type. 

(3) EPA assumes the C–R function for 

fine particles is approximately linear 

within the range of ambient 

concentrations under consideration. In 

the PM Criteria Document, EPA 

recognizes that for individuals and 

specific health responses there are likely 

threshold levels, but there remains little 

evidence of thresholds for PM-related 

effects in populations.176 Where 

potential threshold levels have been 

suggested, they are at fairly low levels 

with increasing uncertainty about 

effects at lower ends of the PM2.5

concentration ranges. Thus, EPA 

estimates include health benefits from 

reducing the fine particles in areas with 

varied concentrations of PM, including 

both regions that are in attainment with 

fine particle standard and those that do 

not meet the standard.

The EPA recognizes the difficulties, 

assumptions, and inherent uncertainties 

in the overall enterprise. The analyses 

upon which the CAIR is based were 

selected from the peer-reviewed 

scientific literature. We used up-to-date 

assessment tools, and we believe the 

results are highly useful in assessing 

this rule. 

There are a number of health and 

environmental effects that we were 

unable to quantify or monetize. A 

complete benefit-cost analysis of the 

CAIR requires consideration of all 

benefits and costs expected to result 

from the rule, not just those benefits and 

costs which could be expressed here in 

dollar terms. A listing of the benefit 

categories that were not quantified or 

monetized in our estimate are provided 

in Table X–4. These effects are denoted 

by ‘‘B’’ in Table X–3 above, and are 

additive to the estimates of benefits. 

4. What Are the Unquantified and 

Unmonetized Benefits of the CAIR 

Emissions Reductions? 

Important benefits beyond the human 

health and welfare benefits resulting 

from reductions in ambient levels of 

PM2.5 and ozone are expected to occur 

from this rule. These other benefits 

occur both directly from NOX and SO2

emissions reductions, and indirectly 

through reductions in co-pollutants 

such as mercury. These benefits are 

listed in Table X–4. Some of the more 

important examples include: Reductions 

in NOX and SO2 emissions required by 

the CAIR will reduce acidification and, 

in the case of NOX, eutrophication of 

water bodies. Reduced nitrate 

contamination of drinking water is 

another possible benefit of the rule. This 

final rule will also reduce acid and 

particulate deposition that cause 

damages to cultural monuments, as well 

as, soiling and other materials damage. 

To illustrate the important nature of 

benefit categories we are currently 

unable to monetize, we discuss two 

categories of public welfare and 

environmental impacts related to 

reductions in emissions required by the 

CAIR: Reduced acid deposition and 

reduced eutrophication of water bodies. 

a. What Are the Benefits of Reduced 

Deposition of Sulfur and Nitrogen to 

Aquatic, Forest, and Coastal 

Ecosystems? 

Atmospheric deposition of sulfur and 

nitrogen, more commonly known as 

acid rain, occurs when emissions of SO2

and NOX react in the atmosphere (with 

water, oxygen, and oxidants) to form 

various acidic compounds. These acidic 

compounds fall to earth in either a wet 

form (rain, snow, and fog) or a dry form 

(gases and particles). Prevailing winds 

can transport acidic compounds 

hundreds of miles, across State borders. 

Acidic compounds (including small 

particles such as sulfates and nitrates) 

cause many negative environmental 

effects, including acidification of lakes 

and streams, harm to sensitive forests, 

and harm to sensitive coastal 

ecosystems.

i. Acid Deposition and Acidification of 

Lakes and Streams 

The extent of adverse effects of acid 

deposition on freshwater and forest 

ecosystems depends largely upon the 

ecosystem’s ability to neutralize the 

acid. The neutralizing ability [key 

indicator is termed Acid Neutralizing 

Capacity (ANC)] depends largely on the 

watershed’s physical characteristics: 

Geology, soils, and size. Waters that are 

sensitive to acidification tend to be 

located in small watersheds that have 

few alkaline minerals and shallow soils. 

Conversely, watersheds that contain 

alkaline minerals, such as limestone, 

tend to have waters with a high ANC. 

Areas especially sensitive to 

acidification include portions of the 

Northeast (particularly, the Adirondack 

and Catskill Mountains, portions of New 

England, and streams in the midAppalachian highlands) and 

southeastern streams. 

Some of the impacts of today’s 

rulemaking on acidification of water 

bodies have been quantified. In 

particular, this rule will result in 

improvements in the acid buffering 

capacity for lakes in the Northeast and 

Adirondack Mountains. Specifically, 12 

percent of Adirondack lakes are 

projected to be chronically acidic in the 

base case. However, we project that the 

CAIR rule will eliminate chronic 

acidification in lakes in the Adirondack 

Mountains by 2030. In addition, today’s 

rule is expected to decrease the 

percentage of chronically acidic lakes 

throughout Northeast from 6 to 1 

percent. However, some lakes in the 

Adirondacks and New England will 

continue to experience episodic 

acidification even after implementation 

of this rule. 

In a recent study,177 Resources for the 

Future (RFF) estimates total benefits 

(i.e., the sum of use and nonuse values) 

of natural resource improvements for 

the Adirondacks resulting from a 

program that would reduce acidification 

in 40 percent of the lakes in the 

Adirondacks that were of concern for 

acidification. While this study requires 

further evaluation, the RFF study 

suggests that the benefits of acid 

deposition reductions for the CAIR are 

likely to be substantial in terms of the 

total monetized value for ecological 

endpoints (although likely small in 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25311

178Sweeney, Jeff. ‘‘EPA’s Chesapeake Bay 

Program Air Strategy.’’ October 26, 2004.

comparison to the estimated premature 

mortality benefits estimates).

ii. Acid Deposition and Forest 

Ecosystem Impacts 

Current understanding of the effects 

of acid deposition on forest ecosystems 

focuses on the effects of ecological 

processes affecting plant uptake, 

retention, and cycling of nutrients 

within forest ecosystems. Recent studies 

indicate that acid deposition is at least 

partially responsible for decreases in 

base cations (calcium, magnesium, 

potassium, and others) from soils in the 

northeastern and southeastern United 

States. Losses of calcium from forest 

soils and forested watersheds have now 

been documented as a sensitive early 

indicator of soil response to acid 

deposition for a wide range of forest 

soils in the United States. 

In red spruce stands, a clear link 

exists between acid deposition, calcium 

supply, and sensitivity to abiotic stress. 

Red spruce uptake and retention of 

calcium is impacted by acid deposition 

in two main ways: Leaching of 

important stores of calcium from 

needles and decreased root uptake of 

calcium due to calcium depletion from 

the soil and aluminum mobilization. 

These changes increase the sensitivity of 

red spruce to winter injuries under 

normal winter conditions in the 

Northeast, result in the loss of needles, 

slow tree growth, and impair the overall 

health and productivity of forest 

ecosystems in many areas of the eastern 

United States. In addition, recent 

studies of sugar maple decline in the 

Northeast demonstrate a link between 

low base cation availability, high levels 

of aluminum and manganese in the soil, 

and increased levels of tree mortality 

due to native defoliating insects.

Although sulfate is the primary cause 

of base cation leaching, nitrate is a 

significant contributor in watersheds 

that are nearly nitrogen saturated. Base 

cation depletion is a cause for concern 

because of the role these ions play in 

surface water acid neutralization and 

their importance as essential nutrients 

for tree growth (calcium, magnesium 

and potassium). 

This regulatory action will decrease 

acid deposition in the transport region 

and is likely to have positive effects on 

the health and productivity of forest 

systems in the region. 

iii. Coastal Ecosystems 

Since 1990, a large amount of research 

has been conducted on the impact of 

nitrogen deposition to coastal waters. 

Nitrogen is often the limiting nutrient in 

coastal ecosystems. Increasing the levels 

of nitrogen in coastal waters can cause 

significant changes to those ecosystems. 

In recent decades, human activities have 

accelerated nitrogen nutrient inputs, 

causing excessive growth of algae and 

leading to degraded water quality and 

associated impairments of estuarine and 

coastal resources. 

Atmospheric deposition of nitrogen is 

a significant source of nitrogen to many 

estuaries. The amount of nitrogen 

entering estuaries due to atmospheric 

deposition varies widely, depending on 

the size and location of the estuarine 

watershed and other sources of nitrogen 

in the watershed. There are a few 

estuaries where atmospheric deposition 

of nitrogen contributes well over 40 

percent of the total nitrogen load; 

however, in most estuaries for which 

estimates exist, the contribution from 

atmospheric deposition ranges from 15–

30 percent. The area of the country with 

the highest air deposition rates (30 

percent deposition rates) includes many 

estuaries along the northeast seaboard 

from Massachusetts to the Chesapeake 

Bay and along the central Gulf of 

Mexico coast. 

In 1999, National Oceanic and 

Atmospheric Administration (NOAA) 

published the results of a 5-year 

national assessment of the severity and 

extent of estuarine eutrophication. An 

estuary is defined as the inland arm of 

the sea that meets the mouth of a river. 

The 138 estuaries characterized in the 

study represent more than 90 percent of 

total estuarine water surface area and 

the total number of U.S. estuaries. The 

study found that estuaries with 

moderate to high eutrophication 

represented 65 percent of the estuarine 

surface area. 

Eutrophication is of particular 

concern in coastal areas with poor or 

stratified circulation patterns, such as 

the Chesapeake Bay, Long Island Sound, 

and the Gulf of Mexico. In such areas, 

the ‘‘overproduced’’ algae tends to sink 

to the bottom and decay, using all or 

most of the available oxygen and 

thereby reducing or eliminating 

populations of bottom-feeder fish and 

shellfish, distorting the normal 

population balance between different 

aquatic organisms, and in extreme cases, 

causing dramatic fish kills. Severe and 

persistent eutrophication often directly 

impacts human activities. For example, 

fishery resource losses can be caused 

directly by fish kills associated with low 

dissolved oxygen and toxic blooms. 

Declines in tourism occur when low 

dissolved oxygen causes noxious smells 

and floating mats of algal blooms create 

unfavorable aesthetic conditions. Risks 

to human health increase when the 

toxins from algal blooms accumulate in 

edible fish and shellfish, and when 

toxins become airborne, causing 

respiratory problems due to inhalation. 

According to the NOAA report, more 

than half of the nation’s estuaries have 

moderate to high expressions of at least 

one of these symptoms’an indication 

that eutrophication is well developed in 

more than half of U.S. estuaries. 

This rule is anticipated to reduce 

nitrogen deposition in the CAIR region. 

Thus, reductions in the levels of 

nitrogen deposition will have a positive 

impact upon current eutrophic 

conditions in estuaries and coastal areas 

in the region. While we are unable to 

monetize the benefits of such 

reductions, the Chesapeake Bay Program 

estimated the reduced mass of delivered 

nitrogen loads likely to result from the 

CAIR, based upon the CAIR proposal 

deposition estimates published in 

January 2004. Atmospheric deposition 

of nitrogen accounts for a significant 

portion of the nitrogen loads to the 

Chesapeake with 28 percent of the 

nitrogen loads from the watershed 

coming from air deposition. Based upon 

the CAIR proposal, nitrogen deposition 

rates published in the January 2004 

proposal, the Chesapeake Bay Program 

finds that the CAIR will likely reduce 

the nitrogen loads to the Bay by 10 

million pounds per year by 2010.178

These substantial nitrogen load 

reductions more than fulfill the EPA’s 

commitment to reduce atmospheric 

deposition delivered to the Chesapeake 

Bay by 8 million pounds.

b. Are There Health or Welfare 

Disbenefits of the CAIR That Have Not 

Been Quantified? 

In contrast to the additional benefits 

of the rule discussed above, it is also 

possible that this rule will result in 

disbenefits in some areas of the region. 

Current levels of nitrogen deposition in 

these areas may provide passive 

fertilization for forest and terrestrial 

ecosystems where nutrients are a 

limiting factor and for some croplands.

The effects of ozone and PM on 

radiative transfer in the atmosphere can 

also lead to effects of uncertain 

magnitude and direction on the 

penetration of ultraviolet light and 

climate. Ground level ozone makes up 

a small percentage of total atmospheric 

ozone (including the stratospheric layer) 

that attenuates penetration of 

ultraviolet—b (UVb) radiation to the 

ground. The EPA’s past evaluation of 

the information indicates that potential 

disbenefits would be small, variable, 

and with too many uncertainties to 

attempt quantification of relatively 

25312 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

small changes in average ozone levels 

over the course of a year (EPA, 2005a). 

The EPA’s most recent provisional 

assessment of the currently available 

information indicates that potential but 

unquantifiable benefits may also arise 

from ozone-related attenuation of UVb 

radiation (EPA, 2005b). Sulfate and 

nitrate particles also scatter UVb, which 

can decrease exposure of horizontal 

surfaces to UVb, but increase exposure 

of vertical surfaces. In this case as well, 

both the magnitude and direction of the 

effect of reductions in sulfate and nitrate 

particles are too uncertain to quantify 

(EPA, 2004). Ozone is a greenhouse gas, 

and sulfates and nitrates can reduce the 

amount of solar radiation reaching the 

earth, but EPA believes that we are 

unable to quantify any net climaterelated disbenefit or benefit associated 

with the combined ozone and PM 

reductions in this rule.

TABLE X–4.—UNQUANTIFIED AND NON-MONETIZED EFFECTS OF THE CLEAN AIR INTERSTATE RULE

Pollutant/effects Effects not included in primary estimates—Changes in: 

Ozone Health a .................................................... Premature mortality b

Chronic respiratory damage 

Premature aging of the lungs 

Non-asthma respiratory emergency room visits 

Increased exposure to UVb 

Ozone Welfare .................................................... Yields for 

–commercial forests 

–fruits and vegetables 

–commercial and non-commercial crops 

Damage to urban ornamental plants 

Impacts on recreational demand from damaged forest aesthetics 

Ecosystem functions 

Increased exposure to UVb 

PM Health c ......................................................... Premature mortality—short term exposures d

Low birth weight 

Pulmonary function 

Chronic respiratory diseases other than chronic bronchitis 

Non-asthma respiratory emergency room visits 

Exposure to UVb (+/¥) e

PM Welfare ......................................................... Visibility in many Class I areas 

Residential and recreational visibility in non-Class I areas 

Soiling and materials damage 

Damage to ecosystem functions 

Exposure to UVb (+/¥) e

Nitrogen and Sulfate Deposition Welfare ........... Commercial forests due to acidic sulfate and nitrate 

deposition 

Commercial freshwater fishing due to acidic deposition 

Recreation in terrestrial ecosystems due to acidic deposition 

Existence values for currently healthy ecosystems 

Commercial fishing, agriculture, and forests due to nitrogen deposition 

Recreation in estuarine ecosystems due to nitrogen deposition 

Ecosystem functions 

Passive fertilization 

Mercury Health ................................................... Incidences of neurological disorders 

Incidences of learning disabilities 

Incidences of developmental delays 

Potential reproductive effects f

Potential cardiovascular effects,f including: 

–Altered blood pressure regulation f

–Increased heart rate variability f

–Myocardial infarction f

Mercury Deposition Welfare ............................... Impact on birds and mammals (e.g., reproductive effects) 

Impacts to commercial, subsistence, and recreational fishing 

Notes:

a In addition to primary economic endpoints, there are a number of biological responses that have been associated with ozone health effects 

including increased airway responsiveness to stimuli, inflamation in the lung, acute inflammation and respiratory cell damage, and increased susceptibility to respiratory infection. The public health impact of these biological responses may be partly represented by our quantified endpoints. bPremature mortality associated with ozone is not currently included in the primary analysis. Recent evidence suggests that short-term exposures to ozone may have a significant effect on daily mortality rates, independent of exposure to PM. EPA is currently conducting a series of 

meta-analyses of the ozone mortality epidemiology literature. EPA will consider including ozone mortality in primary benefits analyses once a 

peer reviewed methodology is available. c In addition to primary economic endpoints, there are a number of biological responses that have been associated with PM health effects including morphological changes and altered host defense mechanisms. The public health impact of these biological responses may be partly represented by our quantified endpoints. dWhile some of the effects of short term exposures are likely to be captured in the estimates, there may be premature mortality due to short 

term exposure to PM not captured in the cohort study upon which the primary analysis is based. e May result in benefits or disbenefits. 

fThese are potential effects as the literature is insufficient. 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25313

B. Paperwork Reduction Act 

In compliance with the Paperwork 

Reduction Act (44 U.S.C. 3501 et seq.), 

EPA submitted a proposed Information 

Collection Request (ICR) (EPA ICR 

number 2512.01) to the OMB for review 

and approval on July 19, 2004 (FR 

42720–42722). The ICR describes the 

nature of the information collection and 

its estimated burden and cost associated 

with the final rule. In cases where 

information is already collected by a 

related program, the ICR takes into 

account only the additional burden. 

This situation arises in States that are 

also subject to requirements of the 

Consolidated Emissions Reporting Rule 

(EPA ICR number 0916.10; OMB control 

number 2060–0088) or for sources that 

are subject to the Acid Rain Program 

(EPA ICR number 1633.13; OMB control 

number 2060–0258) or NOX SIP Call 

(EPA ICR number 1857.03; OMB 

number 2060–0445) requirements. 

The EPA solicited comments on 

specific aspects of the information 

collection. The purpose of the ICR is to 

estimate the anticipated monitoring, 

reporting, and recordkeeping burden 

estimates and associated costs for States, 

local governments, and sources that are 

expected to result from the CAIR. 

The recordkeeping and reporting 

burden to sources resulting from States 

choosing to participate in a regional cap 

and trade program are expected to be 

less than $42 million annually at the 

time the monitors are implemented. 

This estimate includes the annualized 

cost of installing and operating 

appropriate SO2 and NOX emissions 

monitoring equipment to measure and 

report the total emissions of these 

pollutants from affected EGUs serving 

generators greater than 25 megawatt 

electrical. The burden to State and local 

air agencies includes any necessary SIP 

revisions, performing monitoring 

certification, and fulfilling audit 

responsibilities.

In accordance with the Paperwork 

Reduction Act, on July 19, 2004, an ICR 

was made available to the public for 

comment. The 60-day comment period 

expired September 19, 2004 with no 

public comments received specific to 

the ICR. 

C. Regulatory Flexibility Act 

The Regulatory Flexibility Act (5 

U.S.C. § 601 et seq.)(RFA), as amended 

by the Small Business Regulatory 

Enforcement Fairness Act (Pub. L. 104–

121)(SBREFA), provides that whenever 

an agency is required to publish a 

general notice of rulemaking, it must 

prepare and make available an initial 

regulatory flexibility analysis, unless it 

certifies that the rule, if promulgated, 

will not have ‘‘a significant economic 

impact on a substantial number of small 

entities.’’ 5 U.S.C. 605(b). Small entities 

include small businesses, small 

organizations, and small governmental 

jurisdictions. 

For purposes of assessing the impacts 

of today’s rule on small entities, small 

entity is defined as: (1) A small business 

that is identified by the North American 

Industry Classification System (NAICS) 

Code, as defined by the Small Business 

Administration (SBA); (2) a small 

governmental jurisdiction that is a 

government of a city, county, town, 

school district or special district with a 

population of less than 50,000; and (3) 

a small organization that is any not-forprofit enterprise which is independently 

owned and operated and is not 

dominant in its field. Table X–5 lists 

entities potentially impacted by this 

rule with applicable NAICS code.

X–5.—POTENTIALLY REGULATED CATEGORIES AND ENTITIES

Category 1 NAICS 

code Examples of potentially regulated entities 

Industry ........................................................ 221112 Fossil fuel-fired electric utility steam generating units. 

Federal government .................................... 2 221112 Fossil fuel-fired electric utility steam generating units owned by the Federal government. 

State/local/Tribal government ...................... 2 221112 Fossil fuel-fired electric utility steam generating units owned by municipalities. 

................................................................. 921150 Fossil fuel-fired electric utility steam generating units in Indian Country. 

1 North American Industry Classification System. 

2Federal, State, or local government-owned and operated establishments are classified according to the activity in which they are engaged. 

According to the SBA size standards 

for NAICS code 221112 Utilities-Fossil 

Fuel Electric Power Generation, a firm 

is small if, including its affiliates, it is 

primarily engaged in the generation, 

transmission, and or distribution of 

electric energy for sale and its total 

electric output for the preceding fiscal 

year did not exceed 4 million megawatt 

hours. 

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 

Michigan v. EPA, 213 F.3d 663, 668–69 

(DC Cir., 2000), cert. den. 121 S.Ct. 225, 

149 L.Ed.2d 135 (2001). 

This rule would not establish 

requirements applicable to small 

entities. Instead, it would require States 

to develop, adopt, and submit SIP 

revisions that would achieve the 

necessary SO2 and NOX emissions 

reductions, and would leave to the 

States the task of determining how to 

obtain those reductions, including 

which entities to regulate. Moreover, 

because affected States would have 

discretion to choose the sources to 

regulate and how much emissions 

reductions each selected source would 

have to achieve, EPA could not predict 

the effect of the rule on small entities. 

Although not required by the RFA, the 

Agency has conducted a small business 

analysis. 

Overall, about 445 MW of total small 

entity capacity, or 1.0 percent of total 

small entity capacity in the CAIR region, 

is projected to be uneconomic to 

maintain under the CAIR relative to the 

base case. In practice, units projected to 

be uneconomic to maintain may be 

‘‘mothballed,’’ retired, or kept in service 

to ensure transmission reliability in 

certain parts of the grid. Our IPM 

modeling is unable to distinguish 

between these potential outcomes. 

The EPA modeling identified 264 

small entities within the CAIR region 

based upon the definition of small 

entity outlined above. From this 

analysis, EPA excluded 189 small 

entities that were not projected to have 

at least one unit with a generating 

capacity of 25 MW or great operating in 

the base case. Thus, we found that 75 

small entities may potentially be 

affected by the CAIR. Of these 75 small 

entities, 28 may experience compliance 

costs in excess of one percent of 

revenues in 2010, and 46 may in 2015, 

based on the Agency’s assumptions of 

how the affected States implement 

control measures to meet their 

emissions budgets as set forth in this 

rulemaking. Potentially affected small 

entities experiencing compliance costs 

in excess of 1 percent of revenues have 

25314 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

some potential for significant impact 

resulting from implementation of the 

CAIR. However, it is the Agency’s 

position that because none of the 

affected entities currently operate in a 

competitive market environment, they 

should be able to pass the costs of 

complying with the CAIR on to ratepayers. Moreover, the decision to 

include only units greater than 25 MW 

in size exempts 185 small entities that 

would otherwise be potentially affected 

by the CAIR.

Two other points should be 

considered when evaluating the impact 

of the CAIR, specifically, and cap and 

trade programs more generally, on small 

entities. First, under the CAIR, the cap 

and trade program is designed such that 

States determine how NOX allowances 

are to be allocated across units. A State 

that wishes to mitigate the impact of the 

rule on small entities might choose to 

allocate NOX allowances in a manner 

that is favorable to small entities. 

Finally, the use of cap and trade in 

general will limit impacts on small 

entities relative to a less flexible 

command-and-control program. 

D. Unfunded Mandates Reform Act 

Title II of the Unfunded Mandates 

Reform Act of 1995 (Pub. L. 104–4) 

(UMRA), establishes requirements for 

Federal agencies to assess the effects of 

their regulatory actions on State, local, 

and Tribal governments and the private 

sector. Under section 202 of the UMRA, 

2 U.S.C. 1532, EPA generally must 

prepare a written statement, including a 

cost-benefit analysis, for any proposed 

or final rule that ‘‘includes any Federal 

mandate that may result in the 

expenditure by State, local, and Tribal 

governments, in the aggregate, or by the 

private sector, of $100,000,000 or more 

* * * in any one year.’’ A ‘‘Federal 

mandate’’ is defined under section 

421(6), 2 U.S.C. 658(6), to include a 

‘‘Federal intergovernmental mandate’’

and a ‘‘Federal private sector mandate.’’

A ‘‘Federal intergovernmental 

mandate,’’ in turn, is defined to include 

a regulation that ‘‘would impose an 

enforceable duty upon State, Local, or 

Tribal governments,’’ section 

421(5)(A)(i), 2 U.S.C. 658(5)(A)(i), 

except for, among other things, a duty 

that is ‘‘a condition of Federal 

assistance,’’ section 421(5)(A)(i)(I). A 

‘‘Federal private sector mandate’’

includes a regulation that ‘‘would 

impose an enforceable duty upon the 

private sector,’’ with certain exceptions, 

section 421(7)(A), 2 U.S.C. 658(7)(A). 

Before promulgating an EPA rule for 

which a written statement is needed 

under section 202 of the UMRA, section 

205, 2 U.S.C. 1535, of the UMRA 

generally requires EPA to identify and 

consider a reasonable number of 

regulatory alternatives and adopt the 

least costly, most cost-effective, or least 

burdensome alternative that achieves 

the objectives of the rule. 

The EPA prepared a written statement 

for the final rule consistent with the 

requirements of section 202 of the 

UMRA. Furthermore, as EPA stated in 

the rule, EPA is not directly establishing 

any regulatory requirements that may 

significantly or uniquely affect small 

governments, including Tribal 

governments. Thus, EPA is not obligated 

to develop under section 203 of the 

UMRA a small government agency plan. 

Furthermore, in a manner consistent 

with the intergovernmental consultation 

provisions of section 204 of the UMRA, 

EPA carried out consultations with the 

governmental entities affected by this 

rule. 

For several reasons, however, EPA is 

not reaching a final conclusion as to the 

applicability of the requirements of 

UMRA to this rulemaking action. First, 

it is questionable whether a requirement 

to submit a SIP revision would 

constitute a Federal mandate in any 

case. The obligation for a State to revise 

its SIP that arises out of section 110(a) 

of the CAA is not legally enforceable by 

a court of law, and at most is a 

condition for continued receipt of 

highway funds. Therefore, it is possible 

to view an action requiring such a 

submittal as not creating any 

enforceable duty within the meaning of 

section 421(5)(9a)(I) of UMRA (2 U.S.C. 

658 (a)(I)). Even if it did, the duty could 

be viewed as falling within the 

exception for a condition of Federal 

assistance under section 421(5)(a)(i)(I) of 

UMRA (2 U.S.C. 658(5)(a)(i)(I)). 

As noted earlier, however, 

notwithstanding these issues, EPA 

prepared for the final rule the statement 

that would be required by UMRA if its 

statutory provisions applied, and EPA 

has consulted with governmental 

entities as would be required by UMRA. 

Consequently, it is not necessary for 

EPA to reach a conclusion as to the 

applicability of the UMRA 

requirements.

The EPA conducted an analysis of the 

economic impacts anticipated from the 

CAIR for government-owned entities. 

The modeling conducted using the IPM 

projects that about 340 MW of 

municipality-owned capacity (about 0.4 

percent of all subdivision, State and 

municipality capacity in the CAIR 

region) would be uneconomic to 

maintain under the CAIR, beyond what 

is projected in the base case. In practice, 

however, the units projected to be 

uneconomic to maintain may be 

‘mothballed,’ retired, or kept in service 

to ensure transmission reliability in 

certain parts of the grid. For the most 

part, these units are small and 

infrequently used generating units that 

are dispersed throughout the CAIR 

region. 

The EPA modeling identified 265 

State or municipally-owned entities, as 

well as subdivisions, within the CAIR 

region. The EPA excluded from the 

analysis government-owned entities that 

were not projected to have at least one 

unit with generating capacity of 25 MW 

or greater in the base case. Thus, we 

excluded 184 entities from the analysis. 

We found that 81 government entities 

will be potentially affected by CAIR. Of 

the 81 government entities, 20 may 

experience compliance costs in excess 

of 1 percent of revenues in 2010, and 39 

may in 2015, based on our assumptions 

of how the affected States implement 

control measures to meet their 

emissions budgets as set forth in this 

rulemaking. 

Government entities projected to 

experience compliance costs in excess 

of 1 percent of revenues have some 

potential for significant impact resulting 

from implementation of the CAIR. 

However, as noted above, it is EPA’s 

position that because these government 

entities can pass on their costs of 

compliance to rate-payers, they will not 

be significantly impacted. Furthermore, 

the decision to include only units 

greater than 25 MW in size exempts 179 

government entities that would 

otherwise be potentially affected by the 

CAIR. 

The above points aside, potentially 

adverse impacts of the CAIR on State 

and municipality-owned entities could 

be limited by the fact that the cap and 

trade program is designed such that 

States determine how NOX allowances 

are to be allocated across units. A State 

that wishes to mitigate the impact of the 

rule on State or municipality-owned 

entities might choose to allocate NOX

allowances in a manner that is favorable 

to these entities. Finally, the use of cap 

and trade in general will limit impacts 

on entities owned by small governments 

relative to a less flexible command-andcontrol program. 

E. Executive Order 13132: Federalism 

Executive Order 13132, entitled 

‘‘Federalism’’ (64 FR 43255, August 10, 

1999), requires EPA to develop an 

accountable process to ensure 

‘‘meaningful and timely input by State 

and local officials in the development of 

regulatory policies that have federalism 

implications.’’ ‘‘Policies that have 

federalism implications’’ is defined in 

the Executive Order to include 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25315

regulations that have ‘‘substantial direct 

effects on the States, on the relationship 

between the national government and 

the States, or on the distribution of 

power and responsibilities among the 

various levels of government.’’

This rule does not have federalism 

implications. It will not have substantial 

direct effects on the States, on the 

relationship between the national 

government and the States, or on the 

distribution of power and 

responsibilities among the various 

levels of government, as specified in 

Executive Order 13132. The CAA 

establishes the relationship between the 

Federal Government and the States, and 

this rule does not impact that 

relationship. Thus, Executive Order 

13132 does not apply to this rule. In the 

spirit of Executive Order 13132, and 

consistent with EPA policy to promote 

communications between EPA and State 

and local governments, EPA specifically 

solicited comment on this rule from 

State and local officials.

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

Executive Order 13175, entitled 

‘‘Consultation and Coordination with 

Indian Tribal Governments’’ (65 FR 

67249, November 9, 2000), requires EPA 

to develop an accountable process to 

ensure ‘‘meaningful and timely input by 

Tribal officials in the development of 

regulatory policies that have Tribal 

implications.’’ This rule does not have 

‘‘Tribal implications’’ as specified in 

Executive Order 13175. 

This rule addresses transport of 

pollution that are precurors for ozone 

and PM2.5. The CAA provides for States 

and Tribes to develop plans to regulate 

emissions of air pollutants within their 

jurisdictions. The regulations clarify the 

statutory obligations of States and 

Tribes that develop plans to implement 

this rule. The Tribal Authority Rule 

(TAR) give Tribes the opportunity to 

develop and implement CAA programs, 

but it leaves to the discretion of the 

Tribe whether to develop these 

programs and which programs, or 

appropriate elements of a program, the 

Tribe will adopt. 

This rule does not have Tribal 

implications as defined by Executive 

Order 13175. It does not have a 

substantial direct effect on one or more 

Indian Tribes, because no Tribe has 

implemented a federally-enforceable air 

quality management program under the 

CAA at this time. Furthermore, this rule 

does not affect the relationship or 

distribution of power and 

responsibilities between the Federal 

Government and Indian Tribes. The 

CAA and the TAR establish the 

relationship of the Federal Government 

and Tribes in developing plans to attain 

the NAAQS, and this rule does nothing 

to modify that relationship. Because this 

rule does not have Tribal implications, 

Executive Order 13175 does not apply. 

If one assumes a Tribe is 

implementing a Tribal Implementation 

Plan, today’s rule could have 

implications for that Tribe, but it would 

not impose substantial direct costs upon 

the Tribe, nor preempt Tribal law. As 

provided above, EPA has estimated that 

the total annual private costs for the rule 

for the CAIR region as implemented by 

State, local, and Tribal governments is 

approximately $2.4 billion in 2010 and 

$3.6 billion in 2015 (1999$). There are 

currently very few emissions sources in 

Indian country that could be affected by 

this rule and the percentage of Tribal 

land that will be impacted is very small. 

For Tribes that choose to regulate 

sources in Indian country, the costs 

would be attributed to inspecting 

regulated facilities and enforcing 

adopted regulations. 

Although Executive Order 13175 does 

not apply to this rule, EPA consulted 

with Tribal officials in developing this 

rule. The EPA has encouraged Tribal 

input at an early stage. Also, EPA held 

periodic meetings with the States and 

the Tribes during the technical 

development of this rule. Three 

meetings were held with the Crow 

Tribe, where the Tribe expressed 

concerns about potential impacts of the 

rule on their coal mine operations. In 

addition, EPA held three calls with 

Tribal environmental professionals to 

address concerns specific to the Tribes. 

These discussions have given EPA 

valuable information about Tribal 

concerns regarding the development of 

this rule. The EPA has provided 

briefings for Tribal representatives and 

the newly formed National Tribal Air 

Association (NTAA), and other national 

Tribal forums. Input from Tribal 

representatives has been taken into 

consideration in development of this 

rule. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

and Safety Risks 

Executive Order 13045, ‘‘Protection of 

Children from Environmental Health 

and Safety Risks’’ (62 FR 19885, April 

23, 1997) applies to any rule that (1) is 

determined to be ‘‘economically 

significant’’ as defined under Executive 

Order 12866, and (2) concerns an 

environmental health or safety risk that 

EPA has reason to believe may have a 

disproportionate effect on children. If 

the regulatory action meets both criteria, 

Section 5–501 of the Order directs the 

Agency to evaluate the environmental 

health or safety effects of the planned 

rule on children, and explain why the 

planned regulation is preferable to other 

potentially effective and reasonably 

feasible alternatives considered by the 

Agency. 

This final rule is not subject to the 

Executive Order, because it does not 

involve decisions on environmental 

health or safety risks that may 

disproportionately affect children. The 

EPA believes that the emissions 

reductions from the strategies in this 

rule will further improve air quality and 

will further improve children’s health. 

H. Executive Order 13211: Actions That 

Significantly Affect Energy Supply, 

Distribution, or Use 

Executive Order 13211 (66 FR 28355, 

May 22, 2001) provides that agencies 

shall prepare and submit to the 

Administrator of the Office of 

Regulatory Affairs, OMB, a Statement of 

Energy Effects for certain actions 

identified as ‘‘significant energy 

actions.’’ Section 4(b) of Executive 

Order 13211 defines ‘‘significant energy 

actions’’ as ‘‘any action by an agency 

(normally published in the Federal 

Register) that promulgates or is 

expected to lead to the promulgation of 

a final rule or regulation, including 

notices of inquiry, advance notices of 

final rulemaking, and notices of final 

rulemaking (1) (i) a significant 

regulatory action under Executive Order 

12866 or any successor order, and (ii) 

likely to have a significant adverse effect 

on the supply, distribution, or use of 

energy; or (2) designated by the 

Administrator of the Office of 

Information and Regulatory Affairs as a 

‘‘significant energy action.’’ This final 

rule is a significant regulatory action 

under Executive Order 12866, and this 

rule may have a significant adverse 

effect on the supply, distribution, or use 

of energy. 

If States choose to obtain the 

emissions reductions required by this 

rule by regulating EGUs, EPA projects 

that approximately 5.3 GWs of coal-fired 

generation may be removed from 

operation by 2010. In practice, however, 

the units projected to be uneconomic to 

maintain may be ‘mothballed,’ retired, 

or kept in service to ensure transmission 

reliability in certain parts of the grid. 

For the most part, these units are small 

and infrequently used generating units 

that are dispersed throughout the CAIR 

region. Less conservative assumptions 

regarding natural gas prices or 

electricity demand would create a 

greater incentive to keep these units 

operational. The EPA projects that the 

25316 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

179U.S. Environmental Protection Agency, 1998. 

Guidance for Incorporating Environmental Justice 

Concerns in EPA’s NEPA Compliance Analyses. 

Office of Federal Activities, Washington, DC, April, 

1998.

average annual electricity price will 

increase by less than 2.7 percent in the 

CAIR region and that natural gas prices 

will increase by less than 1.6 percent. 

The EPA does not believe that this rule 

will have any other impacts that exceed 

the significance criteria.

The EPA believes that a number of 

features of today’s rulemaking serve to 

reduce its impact on energy supply. 

First, the optional trading program 

provides considerable flexibility to the 

power sector and enables industry to 

comply with the emission reduction 

requirements in the most cost-effective 

manner, thus minimizing overall costs 

and the ultimate impact on energy 

supply. The ability to use banked 

allowances from the existing title IV SO2

trading program and the NOX SIP Call 

Trading Program also provide additional 

flexibility. Second, the CAIR caps are 

set in two phases and provide adequate 

time for EGUs to install pollution 

controls. For more details concerning 

energy impacts, see the Regulatory 

Impact Analysis for the Final Clean Air 

Interstate Rule (March 2005). 

I. National Technology Transfer 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act (NTTAA) of 1995 (Pub. L. 104–113; 

15 U.S.C. 272 note) directs EPA to use 

voluntary consensus standards in its 

regulatory and procurement activities 

unless to do so would be inconsistent 

with applicable law or otherwise 

impractical. Voluntary consensus 

standards are technical standards (e.g., 

materials specifications, test methods, 

sampling procedures, business 

practices) developed or adopted by one 

or more voluntary consensus bodies. 

The NTTAA directs EPA to provide 

Congress, through annual reports to 

OMB, with explanations when an 

agency does not use available and 

applicable voluntary consensus 

standards. 

This rule would require all sources 

that participate in the trading program 

under part 96 to meet the applicable 

monitoring requirements of part 75. Part 

75 already incorporates a number of 

voluntary consensus standards. 

Consistent with the Agency’s 

Performance Based Measurement 

System (PBMS), part 75 sets forth 

performance criteria that allow the use 

of alternative methods to the ones set 

forth in part 75. The PBMS approach is 

intended to be more flexible and costeffective for the regulated community; it 

is also intended to encourage innovation 

in analytical technology and improved 

data quality. At this time, EPA is not 

recommending any revisions to part 75; 

however, EPA periodically revises the 

test procedures set forth in part 75. 

When EPA revises the test procedures 

set forth in part 75 in the future, EPA 

will address the use of any new 

voluntary consensus standards that are 

equivalent. Currently, even if a test 

procedure is not set forth in part 75 EPA 

is not precluding the use of any method, 

whether it constitutes a voluntary 

consensus standard or not, as long as it 

meets the performance criteria 

specified; however, any alternative 

methods must be approved through the 

petition process under Sec. 75.66 before 

they are used under part 75. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order 12898, ‘‘Federal 

Actions to Address Environmental 

Justice in Minority Populations and 

Low-Income Populations,’’ requires 

Federal agencies to consider the impact 

of programs, policies, and activities on 

minority populations and low-income 

populations. According to EPA 

guidance,179 agencies are to assess 

whether minority or low-income 

populations face risks or a rate of 

exposure to hazards that are significant 

and that ‘‘appreciably exceed or is likely 

to appreciably exceed the risk or rate to 

the general population or to the 

appropriate comparison group.’’ (EPA, 

1998)

In accordance with Executive Order 

12898, the Agency has considered 

whether this rule may have 

disproportionate negative impacts on 

minority or low income populations. 

The Agency expects this rule to lead to 

reductions in air pollution and 

exposures generally. For this reason, 

negative impacts to these subpopulations that appreciably exceed 

similar impacts to the general 

population are not expected.

K. Congressional Review Act 

The Congressional Review Act, 5 

U.S.C. 801 et seq., as added by the Small 

Business Regulatory Enforcement 

Fairness Act of 1996, generally provides 

that before a rule may take effect, the 

agency promulgating the rule must 

submit a rule report, which includes a 

copy of the rule, to each House of the 

Congress and to the Comptroller General 

of the United States. The EPA will 

submit a report containing this rule and 

other required information to the U.S. 

Senate, the U.S. House of 

Representatives, and the Comptroller 

General of the United States prior to 

publication of the rule in the Federal 

Register. A Major rule cannot take effect 

until 60 days after it is published in the 

Federal Register. This action is a ‘‘major 

rule’’ as defined by 5 U.S.C. 804(2). 

L. 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 CAIR is 

‘‘nationally applicable’’ within the 

meaning of section 307(b)(1). As an 

initial matter, through this rule, EPA 

interprets section 110 of the CAA, a 

provision which has nationwide 

applicability. In addition, CAIR applies 

to 28 States and the District of 

Columbia. CAIR is also based on a 

common core of factual findings and 

analyses concerning the transport of 

pollutants between the different States 

subject to it. Finally, EPA has 

established uniform approvability 

criteria that would be applied to all 

States subject to CAIR. For these 

reasons, the Administrator also is 

determining that any final action 

regarding CAIR is of nationwide scope 

and effect for purposes of section 

307(b)(1). Thus, any petitions for review 

of final actions regarding CAIR must be 

filed in the Court of Appeals for the 

District of Columbia Circuit within 60 

days from the date final action is 

published in the Federal Register.

List of Subjects 

40 CFR Part 51

Administrative practice and 

procedure, Air pollution control, 

Intergovernmental relations, Nitrogen 

oxides, Ozone, Particulate matter, 

Regional haze, Reporting and 

recordkeeping requirements, Sulfur 

dioxide. 

40 CFR Parts 72, 73, 74, 77 and 78

Acid rain, Administrative practice 

and procedure, Air pollution control, 

Electric utilities, Intergovernmental 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25317

relations, Nitrogen oxides, Reporting 

and recordkeeping requirements, Sulfur 

dioxide. 

40 CFR Part 96

Administrative practice and 

procedure, Air pollution control, 

Electric utilities, Nitrogen oxides, 

Reporting and recordkeeping 

requirements, Sulfur dioxide.

Dated: March 10, 2005. 

Stephen L. Johnson, 

Acting Administrator.

■ Title 40, chapter I, of the Code of 

Federal Regulations is amended as 

follows:

PART 51—[AMENDED]

■ 1. The authority citation for Part 51 

continues to read as follows:

Authority: 23 U.S.C. 101; 42 U.S.C. 7401–

7671q.

§ 51.121 [Amended]

■ 2. Section 51.121 is amended by 

adding a new paragraph (r) to read as 

follows:

§ 51.121 Findings and requirements for 

submission of State implementation plan 

revisions relating to emissions of oxides of 

nitrogen.

* * * * *

(r)(1) Notwithstanding any provisions 

of paragraph (p) of this section, subparts 

A through I of part 96 of this chapter, 

and any State’s SIP to the contrary, the 

Administrator will not carry out any of 

the functions set forth for the 

Administrator in subparts A through I of 

part 96 of this chapter, or in any 

emissions trading program in a State’s 

SIP approved under paragraph (p) of 

this section, with regard to any ozone 

season that occurs after September 30, 

2008. 

(2) Except as provided in § 51.123(bb), 

a State whose SIP is approved as 

meeting the requirements of this section 

and that includes an emissions trading 

program approved under paragraph (p) 

of this section must revise the SIP to 

adopt control measures that satisfy the 

same portion of the State’s NOX

emission reduction requirements under 

this section as the State projected such 

emissions trading program would 

satisfy.

■ 3. Revise § 51.122 of subpart G to read 

as follows:

§ 51.122 Emissions reporting 

requirements for SIP revisions relating to 

budgets for NOX emissions. 

(a) For its transport SIP revision under 

§ 51.121, each State must submit to EPA 

NOX emissions data as described in this 

section. 

(b) Each revision must provide for 

periodic reporting by the State of NOX

emissions data to demonstrate whether 

the State’s emissions are consistent with 

the projections contained in its 

approved SIP submission. 

(1) Annual reporting. Each revision 

must provide for annual reporting of 

NOX emissions data as follows: 

(i) The State must report to EPA 

emissions data from all NOX sources 

within the State for which the State 

specified control measures in its SIP 

submission under § 51.121(g) of this 

part. This would include all sources for 

which the State has adopted measures 

that differ from the measures 

incorporated into the baseline inventory 

for the year 2007 that the State 

developed in accordance with 

§ 51.121(g). 

(ii) If sources report NOX emissions 

data to EPA annually pursuant to a 

trading program approved under 

§ 51.121(p) or pursuant to the 

monitoring and reporting requirements 

of subpart H of 40 CFR part 75, then the 

State need not provide annual reporting 

to EPA for such sources. 

(2) Triennial reporting. Each plan 

must provide for triennial (i.e., every 

third year) reporting of NOX emissions 

data from all sources within the State. 

(3) The data availability requirements 

in § 51.116 must be followed for all data 

submitted to meet the requirements of 

paragraphs (b)(1) and (2) of this section. 

(c) The data reported in paragraph (b) 

of this section for stationary point 

sources must meet the following 

minimum criteria: 

(1) For annual data reporting purposes 

the data must include the following 

minimum elements: 

(i) Inventory year. 

(ii) State Federal Information 

Placement System code. 

(iii) County Federal Information 

Placement System code. 

(iv) Federal ID code (plant). 

(v) Federal ID code (point). 

(vi) Federal ID code (process). 

(vii) Federal ID code (stack). 

(viii) Site name. 

(ix) Physical address. 

(x) SCC. 

(xi) Pollutant code. 

(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) Spring throughput (%). 

(viii) Summer throughput (%). 

(ix) Fall throughput (%). 

(x) Work weekday emissions. 

(xi) Emission factor. 

(xii) Source of emission factor. 

(xiii) Hour/day in operation. 

(xiv) Operations Start time (hour).

(xv) Day/week in operation. 

(xvi) Week/year in operation. 

(3) The triennial inventories must 

include the following data elements: 

(i) The data required in paragraphs 

(c)(1) and (c)(2) of this section. 

(ii) X coordinate (longitude). 

(iii) Y coordinate (latitude). 

(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 non-point sources 

must include the following minimum 

elements: 

(1) For annual inventories it must 

include: 

(i) Inventory year. 

(ii) State FIPS code. 

(iii) County FIPS code. 

(iv) SCC. 

(v) Emission factor. 

(vi) Source of emission factor. 

(vii) Activity/throughput level 

(annual). 

(viii) Activity throughput level 

(seasonal). 

(ix) Source of activity/throughput 

data. 

(x) Spring throughput (%). 

(xi) Summer throughput (%). 

(xii) Fall throughput (%). 

(xiii) Control efficiency (%). 

(xiv) Pollutant code. 

(xv) Ozone season emissions. 

(xvi) Source of emissions data. 

(xvii) Hour/day in operation. 

(xviii) Day/week in operation. 

(xix) Week/year in operations. 

(2) The triennial 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 and triennial 

inventory purposes, the following data 

must be reported:

(i) Inventory year. 

(ii) State FIPS code. 

25318 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

(iii) County FIPS code. 

(iv) SCC. 

(v) Emission factor. 

(vi) Source of emission factor. 

(vii) Activity (this must be reported 

for both highway and nonroad activity. 

Submit nonroad activity in the form of 

hours of activity at standard load (either 

full load or average load) for each 

engine type, application, and 

horsepower range. Submit highway 

activity in the form of vehicle miles 

traveled (VMT) by vehicle class on each 

roadway type. Report both highway and 

nonroad activity for a typical ozone 

season weekday day, if the State uses 

EPA’s default weekday/weekend 

activity ratio. If the State uses a different 

weekday/weekend activity ratio, submit 

separate activity level information for 

weekday days and weekend days.) 

(viii) Source of activity data. 

(ix) Pollutant code. 

(x) Summer work weekday emissions. 

(xi) Ozone season emissions. 

(xii) Source of emissions data. 

(2) [Reserved.] 

(f) Approval of ozone season 

calculation by EPA. Each State must 

submit for EPA approval an example of 

the calculation procedure used to 

calculate ozone season emissions along 

with sufficient information for EPA to 

verify the calculated value of ozone 

season emissions. 

(g) Reporting schedules. (1) Data 

collection is to begin during the ozone 

season one year prior to the State’s NOX

SIP Call compliance date. 

(2) Reports are to be submitted 

according to paragraph (b) of this 

section and the schedule in Table 1. 

After 2008, trienniel reports are to be 

submitted every third year and annual 

reports are to be submitted each year 

that a trienniel report is not required.

TABLE 1.—SCHEDULE FOR SUBMITTING

REPORTS

Data collection year 

Type of

report required 

2002 ............................................ Trienniel. 

2003 ............................................ Annual. 

2004 ............................................ Annual. 

2005 ............................................ Trienniel. 

2006 ............................................ Annual. 

2007 ............................................ Annual. 

2008 ............................................ Trienniel. 

(3) States must submit data for a 

required year no later than 12 months 

after the end of the calendar year for 

which the data are collected. 

(h) Data Reporting Procedures. When 

submitting a formal NOX budget 

emissions report and associated data, 

States shall notify the appropriate EPA 

Regional Office. 

(1) States are required to report 

emissions data in an electronic format to 

EPA. Several options are available for 

data reporting. States can obtain 

information on the current formats at 

the following Internet address: http://

www.epa.gov/ttn/chief, by calling the 

EPA Info CHIEF help desk at (919) 541–

1000 or by sending an e-mail to 

info.chief@epa.gov. Because electronic 

reporting technology continually 

changes, States are to contact the 

Emission Inventory Group (EIG) for the 

latest specific formats. 

(2) For annual reporting (not for 

triennial reports), a State may have 

sources submit the data directly to EPA 

to the extent the sources are subject to 

a trading program that qualifies for 

approval under § 51.121(q), and the 

State has agreed to accept data in this 

format. The EPA will make both the raw 

data submitted in this format and 

summary data available to any State that 

chooses this option. 

(i) Definitions. As used in this section, 

the following words and terms shall 

have the meanings set forth below: 

(1) Annual emissions. Actual 

emissions for a plant, point, or process, 

either measured or calculated.

(2) Ash content. Inert residual portion 

of a fuel. 

(3) Area designation. The designation 

of the area in which the reporting source 

is located with regard to the ozone 

NAAQS. This would include attainment 

or nonattainment designations. For 

nonattainment designations, the 

classification of the nonattainment area 

must be specified, i.e., transitional, 

marginal, moderate, serious, severe, or 

extreme. 

(4) Boiler design capacity. A measure 

of the size of a boiler, based on the 

reported maximum continuous steam 

flow. Capacity is calculated in units of 

MMBtu/hr. 

(5) Control device type. The name of 

the type of control device (e.g., wet 

scrubber, flaring, or process change). 

(6) Control efficiency. The emissions 

reduction efficiency of a primary control 

device, which shows the amount of 

reductions of a particular pollutant from 

a process’s emissions due to controls or 

material change. Control efficiency is 

usually expressed as a percentage or in 

tenths. 

(7) Day/week in operations. Days per 

week that the emitting process operates. 

(8) Emission factor. Ratio relating 

emissions of a specific pollutant to an 

activity or material throughput level. 

(9) Exit gas flow rate. Numeric value 

of stack gas flow rate. 

(10) Exit gas temperature. Numeric 

value of an exit gas stream temperature. 

(11) Exit gas velocity. Numeric value 

of an exit gas stream velocity. 

(12) Fall throughput (%). Portion of 

throughput for the 3 fall months 

(September, October, November). This 

represents the expression of annual 

activity information on the basis of four 

seasons, typically spring, summer, fall, 

and winter. It can be represented either 

as a percentage of the annual activity 

(e.g., production in summer is 40 

percent of the year’s production), or in 

terms of the units of the activity (e.g., 

out of 600 units produced, spring = 150 

units, summer = 250 units, fall = 150 

units, and winter = 50 units). 

(13) Federal ID code (plant). Unique 

codes for a plant or facility, containing 

one or more pollutant-emitting sources. 

(14) Federal ID code (point). Unique 

codes for the point of generation of 

emissions, typically a physical piece of 

equipment. 

(15) Federal ID code (stack number).

Unique codes for the point where 

emissions from one or more processes 

are released into the atmosphere. 

(16) Federal Information Placement 

System (FIPS). The system of unique 

numeric codes developed by the 

government to identify States, counties, 

towns, and townships for the entire 

United States, Puerto Rico, and Guam.

(17) Heat content. The thermal heat 

energy content of a solid, liquid, or 

gaseous fuel. Fuel heat content is 

typically expressed in units of Btu/lb of 

fuel, Btu/gal of fuel, joules/kg of fuel, 

etc. 

(18) Hr/day in operations. Hours per 

day that the emitting process operates. 

(19) Maximum design rate. Maximum 

fuel use rate based on the equipment’s 

or process’ physical size or operational 

capabilities. 

(20) Maximum nameplate capacity. A 

measure of the size of a generator which 

is put on the unit’s nameplate by the 

manufacturer. The data element is 

reported in megawatts (MW) or 

kilowatts (KW). 

(21) Mobile source. A motor vehicle, 

nonroad engine or nonroad vehicle, 

where: 

(i) Motor vehicle means any selfpropelled vehicle designed for 

transporting persons or property on a 

street or highway; 

(ii) Nonroad engine means an internal 

combustion engine (including the fuel 

system) that is not used in a motor 

vehicle or a vehicle used solely for 

competition, or that is not subject to 

standards promulgated under section 

111 or section 202 of the CAA; 

(iii) Nonroad vehicle means a vehicle 

that is powered by a nonroad engine 

and that is not a motor vehicle or a 

vehicle used solely for competition. 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25319

(22) Ozone season. The period May 1 

through September 30 of a year. 

(23) Physical address. Street address 

of facility. 

(24) Point source. A non-mobile 

source which emits 100 tons of NOX or 

more per year unless the State 

designates as a point source a nonmobile source emitting at a specified 

level lower than 100 tons of NOX per 

year. A non-mobile source which emits 

less NOX per year than the point source 

threshold is a non-point source. 

(25) Pollutant code. A unique code for 

each reported pollutant that has been 

assigned in the EIIP Data Model. 

Character names are used for criteria 

pollutants, while Chemical Abstracts 

Service (CAS) numbers are used for all 

other pollutants. Some States may be 

using storage and retrieval of aerometric 

data (SAROAD) codes for pollutants, but 

these should be able to be mapped to 

the EIIP Data Model pollutant codes. 

(26) Process rate/throughput. A 

measurable factor or parameter that is 

directly or indirectly related to the 

emissions of an air pollution source. 

Depending on the type of source 

category, activity information may refer 

to the amount of fuel combusted, the 

amount of a raw material processed, the 

amount of a product that is 

manufactured, the amount of a material 

that is handled or processed, 

population, employment, number of 

units, or miles traveled. Activity 

information is typically the value that is 

multiplied against an emission factor to 

generate an emissions estimate. 

(27) SCC. Source category code. A 

process-level code that describes the 

equipment or operation emitting 

pollutants. 

(28) Secondary control efficiency (%).

The emissions reductions efficiency of a 

secondary control device, which shows 

the amount of reductions of a particular 

pollutant from a process’ emissions due 

to controls or material change. Control 

efficiency is usually expressed as a 

percentage or in tenths. 

(29) SIC. Standard Industrial 

Classification code. U.S. Department of 

Commerce’s categorization of businesses 

by their products or services. 

(30) Site name. The name of the 

facility. 

(31) Spring throughput (%). Portion of 

throughput or activity for the 3 spring 

months (March, April, May). See the 

definition of Fall Throughput. 

(32) Stack diameter. Stack physical 

diameter. 

(33) Stack height. Stack physical 

height above the surrounding terrain. 

(34) Start date (inventory year). The 

calendar year that the emissions 

estimates were calculated for and are 

applicable to. 

(35) Start time (hour). Start time (if 

available) that was applicable and used 

for calculations of emissions estimates. 

(36) Summer throughput (%). Portion 

of throughput or activity for the 3 

summer months (June, July, August). 

See the definition of Fall Throughput. 

(37) Summer work weekday 

emissions. Average day’s emissions for 

a typical day. 

(38) VMT by Roadway Class. This is 

an expression of vehicle activity that is 

used with emission factors. The 

emission factors are usually expressed 

in terms of grams per mile of travel. 

Since VMT does not directly correlate to 

emissions that occur while the vehicle 

is not moving, these non-moving 

emissions are incorporated into EPA’s 

MOBILE model emission factors. 

(39) Week/year in operation. Weeks 

per year that the emitting process 

operates. 

(40) Work Weekday. Any day of the 

week except Saturday or Sunday. 

(41) X coordinate (longitude). An 

object’s east-west geographical 

coordinate. 

(42) Y coordinate (latitude). An 

object’s north-south geographical 

coordinate.

■ 4. Part 51 is amended by adding 

§ 51.123 to Subpart G to read as follows:

§ 51.123 Findings and requirements for 

submission of State implementation plan 

revisions relating to emissions of oxides of 

nitrogen pursuant to the Clean Air Interstate 

Rule.

(a)(1) Under section 110(a)(1) of the 

CAA, 42 U.S.C. 7410(a)(1), the 

Administrator determines that each 

State identified in paragraph (c)(1) and 

(2) of this section must submit a SIP 

revision to comply with the 

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

of the CAA, 42 U.S.C. 7410(a)(2)(D)(i)(I), 

through the adoption of adequate 

provisions prohibiting sources and other 

activities from emitting NOX in amounts 

that will contribute significantly to 

nonattainment in, or interfere with 

maintenance by, one or more other 

States with respect to the fine particles 

(PM2.5) NAAQS. 

(2)(a) Under section 110(a)(1) of the 

CAA, 42 U.S.C. 7410(a)(1), the 

Administrator determines that each 

State identified in paragraph (c)(1) and 

(3) of this section must submit a SIP 

revision to comply with the 

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

of the CAA, 42 U.S.C. 7410(a)(2)(D)(i)(I), 

through the adoption of adequate 

provisions prohibiting sources and other 

activities from emitting NOX in amounts 

that will contribute significantly to 

nonattainment in, or interfere with 

maintenance by, one or more other 

States with respect to the 8-hour ozone 

NAAQS. 

(b) For each State identified in 

paragraph (c) of this section, the SIP 

revision required under paragraph (a) of 

this section will contain adequate 

provisions, for purposes of complying 

with section 110(a)(2)(D)(i)(I) of the 

CAA, 42 U.S.C. 7410(a)(2)(D)(i)(I), only 

if the SIP revision contains control 

measures that assure compliance with 

the applicable requirements of this 

section. 

(c) In addition to being subject to the 

requirements in paragraphs (b) and (d) 

of this section: 

(1) Alabama, Florida, Illinois, Indiana, 

Iowa, Kentucky, Louisiana, Maryland, 

Michigan, Mississippi, Missouri, New 

York, North Carolina, Ohio, 

Pennsylvania, South Carolina, 

Tennessee, Virginia, West Virginia, 

Wisconsin, and the District of Columbia 

shall be subject to the requirements 

contained in paragraphs (e) through (cc) 

of this section; 

(2) Georgia, Minnesota, and Texas 

shall be subject to the requirements in 

paragraphs (e) through (o) and (cc) of 

this section; and 

(3) Arkansas, Connecticut, Delaware, 

Massachusetts, and New Jersey shall be 

subject to the requirements contained in 

paragraphs (q) through (cc) of this 

section. 

(d)(1) The State’s SIP revision under 

paragraph (a) of this section must be 

submitted to EPA by no later than 

September 11, 2006. 

(2) The requirements of appendix V to 

this part shall apply to the SIP revision 

under paragraph (a) of this section.

(3) The State shall deliver 5 copies of 

the SIP revision under paragraph (a) of 

this section to the appropriate Regional 

Office, with a letter giving notice of 

such action. 

(e) The State’s SIP revision shall 

contain control measures and 

demonstrate that they will result in 

compliance with the State’s Annual 

EGU NOX Budget, if applicable, and 

achieve the State’s Annual Non-EGU 

NOX Reduction Requirement, if 

applicable, for the appropriate periods. 

The amounts of the State’s Annual EGU 

NOX Budget and Annual Non-EGU NOX

Reduction Requirement shall be 

determined as follows: 

(1)(i) The Annual EGU NOX Budget 

for the State is defined as the total 

amount of NOX emissions from all EGUs 

in that State for a year, if the State meets 

the requirements of paragraph (a)(1) of 

this section by imposing control 

measures, at least in part, on EGUs. If 

the State imposes control measures 

25320 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

under this section on only EGUs, the 

Annual EGU NOX Budget for the State 

shall not exceed the amount, during the 

indicated periods, specified in 

paragraph (e)(2) of this section. 

(ii) The Annual Non-EGU NOX

Reduction Requirement, if applicable, is 

defined as the total amount of NOX

emission reductions that the State 

demonstrates, in accordance with 

paragraph (g) of this section, it will 

achieve from non-EGUs during the 

appropriate period. If the State meets 

the requirements of paragraph (a)(1) of 

this section by imposing control 

measures on only non-EGUs, then the 

State’s Annual Non-EGU NOX

Reduction Requirement shall equal or 

exceed, during the appropriate periods, 

the amount determined in accordance 

with paragraph (e)(3) of this section. 

(iii) If a State meets the requirements 

of paragraph (a)(1) of this section by 

imposing control measures on both 

EGUs and non-EGUs, then: 

(A) The Annual Non-EGU NOX

Reduction Requirement shall equal or 

exceed the difference between the 

amount specified in paragraph (e)(2) of 

this section for the appropriate period 

and the amount of the State’s Annual 

EGU NOX Budget specified in the SIP 

revision for the appropriate period; and 

(B) The Annual EGU NOX Budget 

shall not exceed, during the indicated 

periods, the amount specified in 

paragraph (e)(2) of this section plus the 

amount of the Annual Non-EGU NOX

Reduction Requirement under 

paragraph (e)(1)(iii)(A) of this section for 

the appropriate period. 

(2) For a State that complies with the 

requirements of paragraph (a)(1) of this 

section by imposing control measures 

on only EGUs, the amount of the 

Annual EGU NOX Budget, in tons of 

NOX per year, shall be as follows, for the 

indicated State for the indicated period:

State 

Annual EGU 

NOX budget 

for 2009–2014 

(tons) 

Annual EGU 

NOX budget 

for 2015 and 

thereafter 

(tons) 

Alabama ................................................................................................................................................................... 69,020 57,517 

District of Columbia ................................................................................................................................................. 144 120 

Florida ...................................................................................................................................................................... 99,445 82,871 

Georgia .................................................................................................................................................................... 66,321 55,268 

Illinois ....................................................................................................................................................................... 76,230 63,525 

Indiana ..................................................................................................................................................................... 108,935 90,779 

Iowa ......................................................................................................................................................................... 32,692 27,243 

Kentucky .................................................................................................................................................................. 83,205 69,337 

Louisiana .................................................................................................................................................................. 35,512 29,593 

Maryland .................................................................................................................................................................. 27,724 23,104 

Michigan ................................................................................................................................................................... 65,304 54,420 

Minnesota ................................................................................................................................................................ 31,443 26,203 

Mississippi ................................................................................................................................................................ 17,807 14,839 

Missouri .................................................................................................................................................................... 59,871 49,892 

New York ................................................................................................................................................................. 45,617 38,014 

North Carolina .......................................................................................................................................................... 62,183 51,819 

Ohio ......................................................................................................................................................................... 108,667 90,556 

Pennsylvania ............................................................................................................................................................ 99,049 82,541 

South Carolina ......................................................................................................................................................... 32,662 27,219 

Tennessee ............................................................................................................................................................... 50,973 42,478 

Texas ....................................................................................................................................................................... 181,014 150,845 

Virginia ..................................................................................................................................................................... 36,074 30,062 

West Virginia ............................................................................................................................................................ 74,220 61,850 

Wisconsin ................................................................................................................................................................. 40,759 33,966 

(3) For a State that complies with the 

requirements of paragraph (a)(1) of this 

section by imposing control measures 

on only non-EGUs, the amount of the 

Annual Non-EGU NOX Reduction 

Requirement, in tons of NOX per year, 

shall be determined, for the State for 

2009 and thereafter, by subtracting the 

amount of the State’s Annual EGU NOX

Budget for the appropriate year, 

specified in paragraph (e)(2) of this 

section from the amount of the State’s 

NOX baseline EGU emissions inventory 

projected for the appropriate year, 

specified in Table 5 of ‘‘Regional and 

State SO2 and NOX Budgets’’, March 

2005 (available at http://www.epa.gov/

cleanairinterstaterule). 

(4)(i) Notwithstanding the State’s 

obligation to comply with paragraph 

(e)(2) or (3) of this section, the State’s 

SIP revision may allow sources required 

by the revision to implement control 

measures to demonstrate compliance 

using credit issued from the State’s 

compliance supplement pool, as set 

forth in paragraph (e)(4)(ii) of this 

section. 

(ii) The State-by-State amounts of the 

compliance supplement pool are as 

follows:

State 

Compliance 

supplement 

pool 

Alabama ................................ 10,166 

District of Columbia .............. 0 

Florida ................................... 8,335 

Georgia ................................. 12,397 

Illinois .................................... 11,299 

Indiana .................................. 20,155 

Iowa ...................................... 6,978 

Kentucky ............................... 14,935 

State 

Compliance 

supplement 

pool 

Louisiana .............................. 2,251 

Maryland ............................... 4,670 

Michigan ............................... 8,347 

Minnesota ............................. 6,528 

Mississippi ............................ 3,066 

Missouri ................................ 9,044 

New York .............................. 0 

North Carolina ...................... 0 

Ohio ...................................... 25,037 

Pennsylvania ........................ 16,009 

South Carolina ...................... 2,600 

Tennessee ............................ 8,944 

Texas .................................... 772 

Virginia .................................. 5,134 

West Virginia ........................ 16,929 

Wisconsin ............................. 4,898 

(iii) The SIP revision may provide for 

the distribution of credits from the 

compliance supplement pool to sources 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25321

that are required to implement control 

measures using one or both of the 

following two mechanisms: 

(A) The State may issue credit from 

compliance supplement pool to sources 

that are required by the SIP revision to 

implement NOX emission control 

measures and that implement NOX

emission reductions in 2007 and 2008 

that are not necessary to comply with 

any State or federal emissions limitation 

applicable at any time during such 

years. Such a source may be issued one 

credit from the compliance supplement 

pool for each ton of such emission 

reductions in 2007 and 2008. 

(1) The State shall complete the 

issuance process by January 1, 2010. 

(2) The emissions reductions for 

which credits are issued must have been 

demonstrated by the owners and 

operators of the source to have occurred 

during 2007 and 2008 and not to be 

necessary to comply with any 

applicable State or federal emissions 

limitation. 

(3) The emissions reductions for 

which credits are issued must have been 

quantified by the owners and operators 

of the source: 

(i) For EGUs and for fossil-fuel-fired 

non-EGUs that are boilers or combustion 

turbines with a maximum design heat 

input greater than 250 mmBut/hr, using 

emissions data determined in 

accordance with subpart H of part 75 of 

this chapter; and 

(ii) For non-EGUs not described in 

paragraph (e)(4)(iii)(A)(3)(i) of this 

section, using emissions data 

determined in accordance with subpart 

H of part 75 of this chapter or, if the 

State demonstrates that compliance 

with subpart H of part 75 of this chapter 

is not practicable, determined, to the 

extent practicable, with the same degree 

of assurance with which emissions data 

are determined for sources subject to 

subpart H of part 75. 

(4) If the SIP revision contains 

approved provisions for an emissions 

trading program, the owners and 

operators of sources that receive credit 

according to the requirements of this 

paragraph may transfer the credit to 

other sources or persons according to 

the provisions in the emissions trading 

program. 

(B) The State may issue credit from 

the compliance supplement pool to 

sources that are required by the SIP 

revision to implement NOX emission 

control measures and whose owners and 

operators demonstrate a need for an 

extension, beyond 2009, of the deadline 

for the source for implementing such 

emission controls. 

(1) The State shall complete the 

issuance process by January 1, 2010. 

(2) The State shall issue credit to a 

source only if the owners and operators 

of the source demonstrate that: 

(i) For a source used to generate 

electricity, implementation of the SIP 

revision’s applicable control measures 

by 2009 would create undue risk for the 

reliability of the electricity supply. This 

demonstration must include a showing 

that it would not be feasible for the 

owners and operators of the source to 

obtain a sufficient amount of electricity, 

to prevent such undue risk, from other 

electricity generation facilities during 

the installation of control technology at 

the source necessary to comply with the 

SIP revision. 

(ii) For a source not used to generate 

electricity, compliance with the SIP 

revision’s applicable control measures 

by 2009 would create undue risk for the 

source or its associated industry to a 

degree that is comparable to the risk 

described in paragraph (e)(4)(iii)(B)(2)(i) 

of this section. 

(iii) This demonstration must include 

a showing that it would not be possible 

for the source to comply with applicable 

control measures by obtaining sufficient 

credits under paragraph (e)(4)(iii)(A) of 

this section, or by acquiring sufficient 

credits from other sources or persons, to 

prevent undue risk. 

(f) Each SIP revision must set forth 

control measures to meet the amounts 

specified in paragraph (e) of this 

section, as applicable, including the 

following: 

(1) A description of enforcement 

methods including, but not limited to:

(i) Procedures for monitoring 

compliance with each of the selected 

control measures; 

(ii) Procedures for handling 

violations; and 

(iii) A designation of agency 

responsibility for enforcement of 

implementation. 

(2)(i) If a State elects to impose 

control measures on EGUs, then those 

measures must impose an annual NOX

mass emissions cap on all such sources 

in the State. 

(ii) If a State elects to impose control 

measures on fossil fuel-fired non-EGUs 

that are boilers or combustion turbines 

with a maximum design heat input 

greater than 250 mmBtu/hr, then those 

measures must impose an annual NOX

mass emissions cap on all such sources 

in the State. 

(iii) If a State elects to impose control 

measures on non-EGUs other than those 

described in paragraph (f)(2)(ii) of this 

section, then those measures must 

impose an annual NOX mass emissions 

cap on all such sources in the State or 

the State must demonstrate why such 

emissions cap is not practicable and 

adopt alternative requirements that 

ensure that the State will comply with 

its requirements under paragraph (e) of 

this section, as applicable, in 2009 and 

subsequent years. 

(g)(1) Each SIP revision that contains 

control measures covering non-EGUs as 

part or all of a State’s obligation in 

meeting its requirement under 

paragraph (a)(1) of this section must 

demonstrate that such control measures 

are adequate to provide for the timely 

compliance with the State’s Annual 

Non-EGU NOX Reduction Requirement 

under paragraph (e) of this section and 

are not adopted or implemented by the 

State, as of May 12, 2005, and are not 

adopted or implemented by the Federal 

government, as of the date of 

submission of the SIP revision by the 

State to EPA. 

(2) The demonstration under 

paragraph (g)(1) of this section must 

include the following, with respect to 

each source category of non-EGUs for 

which the SIP revision requires control 

measures: 

(i) A detailed historical baseline 

inventory of NOX mass emissions from 

the source category in a representative 

year consisting, at the State’s election, of 

2002, 2003, 2004, or 2005, or an average 

of 2 or more of those years, absent the 

control measures specified in the SIP 

revision. 

(A) This inventory must represent 

estimates of actual emissions based on 

monitoring data in accordance with 

subpart H of part 75 of this chapter, if 

the source category is subject to 

monitoring requirements in accordance 

with subpart H of part 75 of this 

chapter. 

(B) In the absence of monitoring data 

in accordance with subpart H of part 75 

of this chapter, actual emissions must be 

quantified, to the maximum extent 

practicable, with the same degree of 

assurance with which emissions are 

quantified for sources subject to subpart 

H of part 75 of this chapter and using 

source-specific or source-categoryspecific assumptions that ensure a 

source’s or source category’s actual 

emissions are not overestimated. If a 

State uses factors to estimate emissions, 

production or utilization, or 

effectiveness of controls or rules for a 

source category, such factors must be 

chosen to ensure that emissions are not 

overestimated. 

(C) For measures to reduce emissions 

from motor vehicles, emission estimates 

must be based on an emissions model 

that has been approved by EPA for use 

in SIP development and must be 

consistent with the planning 

assumptions regarding vehicle miles 

25322 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

traveled and other factors current at the 

time of the SIP development. 

(D) For measures to reduce emissions 

from nonroad engines or vehicles, 

emission estimates methodologies must 

be approved by EPA. 

(ii) A detailed baseline inventory of 

NOX mass emissions from the source 

category in the years 2009 and 2015, 

absent the control measures specified in 

the SIP revision and reflecting changes 

in these emissions from the historical 

baseline year to the years 2009 and 

2015, based on projected changes in the 

production input or output, population, 

vehicle miles traveled, economic 

activity, or other factors as applicable to 

this source category.

(A) These inventories must account 

for implementation of any control 

measures that are otherwise required by 

final rules already promulgated, as of 

May 12, 2005, or adopted or 

implemented by any federal agency, as 

of the date of submission of the SIP 

revision by the State to EPA, and must 

exclude any control measures specified 

in the SIP revision to meet the NOX

emissions reduction requirements of 

this section. 

(B) Economic and population 

forecasts must be as specific as possible 

to the applicable industry, State, and 

county of the source or source category 

and must be consistent with both 

national projections and relevant official 

planning assumptions, including 

estimates of population and vehicle 

miles traveled developed through 

consultation between State and local 

transportation and air quality agencies. 

However, if these official planning 

assumptions are inconsistent with 

official U.S. Census projections of 

population or with energy consumption 

projections contained in the U.S. 

Department of Energy’s most recent 

Annual Energy Outlook, then the SIP 

revision must make adjustments to 

correct the inconsistency or must 

demonstrate how the official planning 

assumptions are more accurate. 

(C) These inventories must account 

for any changes in production method, 

materials, fuels, or efficiency that are 

expected to occur between the historical 

baseline year and 2009 or 2015, as 

appropriate. 

(iii) A projection of NOX mass 

emissions in 2009 and 2015 from the 

source category assuming the same 

projected changes as under paragraph 

(g)(2)(ii) of this section and resulting 

from implementation of each of the 

control measures specified in the SIP 

revision. 

(A) These inventories must address 

the possibility that the State’s new 

control measures may cause production 

or utilization, and emissions, to shift to 

unregulated or less stringently regulated 

sources in the source category in the 

same or another State, and these 

inventories must include any such 

amounts of emissions that may shift to 

such other sources. 

(B) The State must provide EPA with 

a summary of the computations, 

assumptions, and judgments used to 

determine the degree of reduction in 

projected 2009 and 2015 NOX emissions 

that will be achieved from the 

implementation of the new control 

measures compared to the relevant 

baseline emissions inventory. 

(iv) The result of subtracting the 

amounts in paragraph (g)(2)(iii) of this 

section for 2009 and 2015, respectively, 

from the lower of the amounts in 

paragraph (g)(2)(i) or (g)(2)(ii) of this 

section for 2009 and 2015, respectively, 

may be credited towards the State’s 

Annual Non-EGU NOX Reduction 

Requirement in paragraph (e)(3) of this 

section for the appropriate period. 

(v) Each SIP revision must identify 

the sources of the data used in each 

estimate and each projection of 

emissions. 

(h) Each SIP revision must comply 

with § 51.116 (regarding data 

availability). 

(i) Each SIP revision must provide for 

monitoring the status of compliance 

with any control measures adopted to 

meet the State’s requirements under 

paragraph (e) of this section as follows: 

(1) The SIP revision must provide for 

legally enforceable procedures for 

requiring owners or operators of 

stationary sources to maintain records 

of, and periodically report to the State: 

(i) Information on the amount of NOX

emissions from the stationary sources; 

and 

(ii) Other information as may be 

necessary to enable the State to 

determine whether the sources are in 

compliance with applicable portions of 

the control measures; 

(2) The SIP revision must comply 

with § 51.212 (regarding testing, 

inspection, enforcement, and 

complaints); 

(3) If the SIP revision contains any 

transportation control measures, then 

the SIP revision must comply with 

§ 51.213 (regarding transportation 

control measures); 

(4)(i) If the SIP revision contains 

measures to control EGUs, then the SIP 

revision must require such sources to 

comply with the monitoring, 

recordkeeping, and reporting provisions 

of subpart H of part 75 of this chapter. 

(ii) If the SIP revision contains 

measures to control fossil fuel-fired nonEGUs that are boilers or combustion 

turbines with a maximum design heat 

input greater than 250 mmBtu/hr, then 

the SIP revision must require such 

sources to comply with the monitoring, 

recordkeeping, and reporting provisions 

of subpart H of part 75 of this chapter. 

(iii) If the SIP revision contains 

measures to control any other non-EGUs 

that are not described in paragraph 

(i)(4)(ii) of this section, then the SIP 

revision must require such sources to 

comply with the monitoring, 

recordkeeping, and reporting provisions 

of subpart H of part 75 of this chapter, 

or the State must demonstrate why such 

requirements are not practicable and 

adopt alternative requirements that 

ensure that the required emissions 

reductions will be quantified, to the 

maximum extent practicable, with the 

same degree of assurance with which 

emissions are quantified for sources 

subject to subpart H of part 75 of this 

chapter. 

(j) Each SIP revision must show that 

the State has legal authority to carry out 

the SIP revision, including authority to: 

(1) Adopt emissions standards and 

limitations and any other measures 

necessary for attainment and 

maintenance of the State’s relevant 

Annual EGU NOX Budget or the Annual 

Non-EGU NOX Reduction Requirement, 

as applicable, under 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; and 

(4)(i) Require owners or operators of 

stationary sources to install, maintain, 

and use emissions monitoring devices 

and to make periodic reports to the State 

on the nature and amounts of emissions 

from such stationary sources; and 

(ii) Make the data described in 

paragraph (j)(4)(i) of this section 

available to the public within a 

reasonable time after being reported and 

as correlated with any applicable 

emissions standards or limitations. 

(k)(1) The provisions of law or 

regulation that the State determines 

provide the authorities required under 

this section must be specifically 

identified, and copies of such laws or 

regulations must be submitted with the 

SIP revision. 

(2) Legal authority adequate to fulfill 

the requirements of paragraphs (j)(3) 

and (4) of this section may be delegated 

to the State under section 114 of the 

CAA. 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25323

(l)(1) A SIP revision may assign legal 

authority to local agencies in 

accordance with § 51.232. 

(2) Each SIP revision must comply 

with § 51.240 (regarding general plan 

requirements). 

(m) Each SIP revision must comply 

with § 51.280 (regarding resources). 

(n) Each SIP revision must provide for 

State compliance with the reporting 

requirements in § 51.125. 

(o)(1) Notwithstanding any other 

provision of this section, if a State 

adopts regulations substantively 

identical to subparts AA through II of 

part 96 of this chapter (CAIR NOX

Annual Trading Program), incorporates 

such subparts by reference into its 

regulations, or adopts regulations that 

differ substantively from such subparts 

only as set forth in paragraph (o)(2) of 

this section, then such emissions 

trading program in the State’s SIP 

revision is automatically approved as 

meeting the requirements of paragraph 

(e) of this section, provided that the 

State has the legal authority to take such 

action and to implement its 

responsibilities under such regulations. 

(2) If a State adopts an emissions 

trading program that differs 

substantively from subparts AA through 

II of part 96 of this chapter only as 

follows, then the emissions trading 

program is approved as set forth in 

paragraph (o)(1) of this section. 

(i) The State may decline to adopt the 

CAIR NOX opt-in provisions of: 

(A) Subpart II of this part and the 

provisions applicable only to CAIR NOX

opt-in units in subparts AA through HH 

of this part; 

(B) Section 96.188(b) of this chapter 

and the provisions of subpart II of this 

part applicable only to CAIR NOX optin units under § 96.188(b); or 

(C) Section 96.188(c) of this chapter 

and the provisions of subpart II of this 

part applicable only to CAIR NOX optin units under § 96.188(c). 

(ii) The State may decline to adopt the 

allocation provisions set forth in subpart 

EE of part 96 of this chapter and may 

instead adopt any methodology for 

allocating CAIR NOX allowances to 

individual sources, as follows: 

(A) The State’s methodology must not 

allow the State to allocate CAIR NOX

allowances for a year in excess of the 

amount in the State’s Annual EGU NOX

Budget for such year; 

(B) The State’s methodology must 

require that, for EGUs commencing 

operation before January 1, 2001, the 

State will determine, and notify the 

Administrator of, each unit’s allocation 

of CAIR NOX allowances by October 31, 

2006 for 2009, 2010, and 2011 and by 

October 31, 2008 and October 31 of each 

year thereafter for the year after the year 

of the notification deadline; and 

(C) The State’s methodology must 

require that, for EGUs commencing 

operation on or after January 1, 2001, 

the State will determine, and notify the 

Administrator of, each unit’s allocation 

of CAIR NOX allowances by October 31 

of the year for which the CAIR NOX

allowances are allocated.

(3) A State that adopts an emissions 

trading program in accordance with 

paragraph (o)(1) or (2) of this section is 

not required to adopt an emissions 

trading program in accordance with 

paragraph (aa)(1) or (2) of this section or 

§ 96.124(o)(1) or (2). 

(4) If a State adopts an emissions 

trading program that differs 

substantively from subparts AA through 

HH of part 96 of this chapter, other than 

as set forth in paragraph (o)(2) of this 

section, then such emissions trading 

program is not automatically approved 

as set forth in paragraph (o)(1) or (2) of 

this section and will be reviewed by the 

Administrator for approvability in 

accordance with the other provisions of 

this section, provided that the NOX

allowances issued under such emissions 

trading program shall not, and the SIP 

revision shall state that such NOX

allowances shall not, qualify as CAIR 

NOX allowances or CAIR NOX Ozone 

Season allowances under any emissions 

trading program approved under 

paragraphs (o)(1) or (2) or (aa)(1) or (2) 

of this section. 

(p) [Reserved] 

(q) The State’s SIP revision shall 

contain control measures and 

demonstrate that they will result in 

compliance with the State’s Ozone 

Season EGU NOX Budget, if applicable, 

and achieve the State’s Ozone Season 

Non-EGU NOX Reduction Requirement, 

if applicable, for the appropriate 

periods. The amounts of the State’s 

Ozone Season EGU NOX Budget and 

Ozone Season Non-EGU NOX Reduction 

Requirement shall be determined as 

follows: 

(1)(i) The Ozone Season EGU NOX

Budget for the State is defined as the 

total amount of NOX emissions from all 

EGUs in that State for an ozone season, 

if the State meets the requirements of 

paragraph (a)(2) of this section by 

imposing control measures, at least in 

part, on EGUs. If the State imposes 

control measures under this section on 

only EGUs, the Ozone Season EGU NOX

Budget for the State shall not exceed the 

amount, during the indicated periods, 

specified in paragraph (q)(2) of this 

section. 

(ii) The Ozone Season Non-EGU NOX

Reduction Requirement, if applicable, is 

defined as the total amount of NOX

emission reductions that the State 

demonstrates, in accordance with 

paragraph (s) of this section, it will 

achieve from non-EGUs during the 

appropriate period. If the State meets 

the requirements of paragraph (a)(2) of 

this section by imposing control 

measures on only non-EGUs, then the 

State’s Ozone Season Non-EGU NOX

Reduction Requirement shall equal or 

exceed, during the appropriate periods, 

the amount determined in accordance 

with paragraph (q)(3) of this section. 

(iii) If a State meets the requirements 

of paragraph (a)(2) of this section by 

imposing control measures on both 

EGUs and non-EGUs, then: 

(A) The Ozone Season Non-EGU NOX

Reduction Requirement shall equal or 

exceed the difference between the 

amount specified in paragraph (q)(2) of 

this section for the appropriate period 

and the amount of the State’s Ozone 

Season EGU NOX Budget specified in 

the SIP revision for the appropriate 

period; and 

(B) The Ozone Season EGU NOX

Budget shall not exceed, during the 

indicated periods, the amount specified 

in paragraph (e)(2) of this section plus 

the amount of the Ozone Season NonEGU NOX Reduction Requirement under 

paragraph (q)(1)(iii)(A) of this section 

for the appropriate period. 

(2) For a State that complies with the 

requirements of paragraph (a)(2) of this 

section by imposing control measures 

on only EGUs, the amount of the Ozone 

Season EGU NOX Budget, in tons of 

NOX per ozone season, shall be as 

follows, for the indicated State for the 

indicated period:

State 

Ozone season 

EGU NOX

budget for 

2009–2014 

(tons) 

Ozone season 

EGU NOX

budget for 

2015 and 

thereafter 

(tons) 

Alabama ................................................................................................................................................................... 32,182 26,818 

25324 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

State 

Ozone season 

EGU NOX

budget for 

2009–2014 

(tons) 

Ozone season 

EGU NOX

budget for 

2015 and 

thereafter 

(tons) 

Arkansas .................................................................................................................................................................. 11,515 9,596 

Connecticut .............................................................................................................................................................. 2,559 2,559 

Delaware .................................................................................................................................................................. 2,226 1,855 

District of Columbia ................................................................................................................................................. 112 94 

Florida ...................................................................................................................................................................... 47,912 39,926 

Illinois ....................................................................................................................................................................... 30,701 28,981 

Indiana ..................................................................................................................................................................... 45,952 39,273 

Iowa ......................................................................................................................................................................... 14,263 11,886 

Kentucky .................................................................................................................................................................. 36,045 30,587 

Louisiana .................................................................................................................................................................. 17,085 14,238 

Maryland .................................................................................................................................................................. 12,834 10,695 

Massachusetts ......................................................................................................................................................... 7,551 6,293 

Michigan ................................................................................................................................................................... 28,971 24,142 

Mississippi ................................................................................................................................................................ 8,714 7,262 

Missouri .................................................................................................................................................................... 26,678 22,231 

New Jersey .............................................................................................................................................................. 6,654 5,545 

New York ................................................................................................................................................................. 20,632 17,193 

North Carolina .......................................................................................................................................................... 28,392 23,660 

Ohio ......................................................................................................................................................................... 45,664 39,945 

Pennsylvania ............................................................................................................................................................ 42,171 35,143 

South Carolina ......................................................................................................................................................... 15,249 12,707 

Tennessee ............................................................................................................................................................... 22,842 19,035 

Virginia ..................................................................................................................................................................... 15,994 13,328 

West Virginia ............................................................................................................................................................ 26,859 26,525 

Wisconsin ................................................................................................................................................................. 17,987 14,989 

(3) For a State that complies with the 

requirements of paragraph (a)(2) of this 

section by imposing control measures 

on only non-EGUs, the amount of the 

Ozone Season Non-EGU NOX Reduction 

Requirement, in tons of NOX per ozone 

season, shall be determined, for the 

State for 2009 and thereafter, by 

subtracting the amount of the State’s 

Ozone Season EGU NOX Budget for the 

appropriate year, specified in paragraph 

(e)(2) of this section, from the amount of 

the State’s NOX baseline EGU emissions 

inventory projected for the ozone season 

in the appropriate year, specified in 

Table 7 of ‘‘Regional and State SO2 and 

NOX Budgets’’, March 2005 (available 

at: http://www.epa.gov/

cleanairinterstaterule). 

(4) Notwithstanding the State’s 

obligation to comply with paragraph 

(q)(2) or (3) of this section, the State’s 

SIP revision may allow sources required 

by the revision to implement NOX

emission control measures to 

demonstrate compliance using NOX SIP 

Call allowances allocated under the 

NOX Budget Trading Program for any 

ozone season during 2003 through 2008 

that have not been deducted by the 

Administrator under the NOX Budget 

Trading Program, if the SIP revision 

ensures that such allowances will not be 

available for such deduction under the 

NOX Budget Trading Program.

(r) Each SIP revision must set forth 

control measures to meet the amounts 

specified in paragraph (q) of this 

section, as applicable, including the 

following: 

(1) A description of enforcement 

methods including, but not limited to: 

(i) Procedures for monitoring 

compliance with each of the selected 

control measures; 

(ii) Procedures for handling 

violations; and 

(iii) A designation of agency 

responsibility for enforcement of 

implementation. 

(2)(i) If a State elects to impose 

control measures on EGUs, then those 

measures must impose an ozone season 

NOX mass emissions cap on all such 

sources in the State. 

(ii) If a State elects to impose control 

measures on fossil fuel-fired non-EGUs 

that are boilers or combustion turbines 

with a maximum design heat input 

greater than 250 mmBtu/hr, then those 

measures must impose an ozone season 

NOX mass emissions cap on all such 

sources in the State. 

(iii) If a State elects to impose control 

measures on non-EGUs other than those 

described in paragraph (r)(2)(ii) of this 

section, then those measures must 

impose an ozone season NOX mass 

emissions cap on all such sources in the 

State or the State must demonstrate why 

such emissions cap is not practicable 

and adopt alternative requirements that 

ensure that the State will comply with 

its requirements under paragraph (q) of 

this section, as applicable, in 2009 and 

subsequent years. 

(s)(1) Each SIP revision that contains 

control measures covering non-EGUs as 

part or all of a State’s obligation in 

meeting its requirement under 

paragraph (a)(2) of this section must 

demonstrate that such control measures 

are adequate to provide for the timely 

compliance with the State’s Ozone 

Season Non-EGU NOX Reduction 

Requirement under paragraph (q) of this 

section and are not adopted or 

implemented by the State, as of May 12, 

2005, and are not adopted or 

implemented by the federal government, 

as of the date of submission of the SIP 

revision by the State to EPA. 

(2) The demonstration under 

paragraph (s)(1) of this section must 

include the following, with respect to 

each source category of non-EGUs for 

which the SIP revision requires control 

measures: 

(i) A detailed historical baseline 

inventory of NOX mass emissions from 

the source category in a representative 

ozone season consisting, at the State’s 

election, of the ozone season in 2002, 

2003, 2004, or 2005, or an average of 2 

or more of those ozone seasons, absent 

the control measures specified in the 

SIP revision. 

(A) This inventory must represent 

estimates of actual emissions based on 

monitoring data in accordance with 

subpart H of part 75 of this chapter, if 

the source category is subject to 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25325

monitoring requirements in accordance 

with subpart H of part 75 of this 

chapter. 

(B) In the absence of monitoring data 

in accordance with subpart H of part 75 

of this chapter, actual emissions must be 

quantified, to the maximum extent 

practicable, with the same degree of 

assurance with which emissions are 

quantified for sources subject to subpart 

H of part 75 of this chapter and using 

source-specific or source-categoryspecific assumptions that ensure a 

source’s or source category’s actual 

emissions are not overestimated. If a 

State uses factors to estimate emissions, 

production or utilization, or 

effectiveness of controls or rules for a 

source category, such factors must be 

chosen to ensure that emissions are not 

overestimated. 

(C) For measures to reduce emissions 

from motor vehicles, emission estimates 

must be based on an emissions model 

that has been approved by EPA for use 

in SIP development and must be 

consistent with the planning 

assumptions regarding vehicle miles 

traveled and other factors current at the 

time of the SIP development.

(D) For measures to reduce emissions 

from nonroad engines or vehicles, 

emission estimates methodologies must 

be approved by EPA. 

(ii) A detailed baseline inventory of 

NOX mass emissions from the source 

category in ozone seasons 2009 and 

2015, absent the control measures 

specified in the SIP revision and 

reflecting changes in these emissions 

from the historical baseline ozone 

season to the ozone seasons 2009 and 

2015, based on projected changes in the 

production input or output, population, 

vehicle miles traveled, economic 

activity, or other factors as applicable to 

this source category. 

(A) These inventories must account 

for implementation of any control 

measures that are adopted or 

implemented by the State, as of May 12, 

2005, or adopted or implemented by the 

federal government, as of the date of 

submission of the SIP revision by the 

State to EPA, and must exclude any 

control measures specified in the SIP 

revision to meet the NOX emissions 

reduction requirements of this section. 

(B) Economic and population 

forecasts must be as specific as possible 

to the applicable industry, State, and 

county of the source or source category 

and must be consistent with both 

national projections and relevant official 

planning assumptions including 

estimates of population and vehicle 

miles traveled developed through 

consultation between State and local 

transportation and air quality agencies. 

However, if these official planning 

assumptions are inconsistent with 

official U.S. Census projections of 

population or with energy consumption 

projections contained in the U.S. 

Department of Energy’s most recent 

Annual Energy Outlook, then the SIP 

revision must make adjustments to 

correct the inconsistency or must 

demonstrate how the official planning 

assumptions are more accurate. 

(C) These inventories must account 

for any changes in production method, 

materials, fuels, or efficiency that are 

expected to occur between the historical 

baseline ozone season and ozone season 

2009 or ozone season 2015, as 

appropriate. 

(iii) A projection of NOX mass 

emissions in ozone season 2009 and 

ozone season 2015 from the source 

category assuming the same projected 

changes as under paragraph (s)(2)(ii) of 

this section and resulting from 

implementation of each of the control 

measures specified in the SIP revision. 

(A) These inventories must address 

the possibility that the State’s new 

control measures may cause production 

or utilization, and emissions, to shift to 

unregulated or less stringently regulated 

sources in the source category in the 

same or another State, and these 

inventories must include any such 

amounts of emissions that may shift to 

such other sources. 

(B) The State must provide EPA with 

a summary of the computations, 

assumptions, and judgments used to 

determine the degree of reduction in 

projected ozone season 2009 and ozone 

season 2015 NOX emissions that will be 

achieved from the implementation of 

the new control measures compared to 

the relevant baseline emissions 

inventory. 

(iv) The result of subtracting the 

amounts in paragraph (s)(2)(iii) of this 

section for ozone season 2009 and ozone 

season 2015, respectively, from the 

lower of the amounts in paragraph 

(s)(2)(i) or (s)(2)(ii) of this section for 

ozone season 2009 and ozone season 

2015, respectively, may be credited 

towards the State’s Ozone Season NonEGU NOX Reduction Requirement in 

paragraph (q)(3) of this section for the 

appropriate period. 

(v) Each SIP revision must identify 

the sources of the data used in each 

estimate and each projection of 

emissions. 

(t) Each SIP revision must comply 

with § 51.116 (regarding data 

availability). 

(u) Each SIP revision must provide for 

monitoring the status of compliance 

with any control measures adopted to 

meet the State’s requirements under 

paragraph (q) of this section as follows: 

(1) The SIP revision must provide for 

legally enforceable procedures for 

requiring owners or operators of 

stationary sources to maintain records 

of, and periodically report to the State:

(i) Information on the amount of NOX

emissions from the stationary sources; 

and 

(ii) Other information as may be 

necessary to enable the State to 

determine whether the sources are in 

compliance with applicable portions of 

the control measures; 

(2) The SIP revision must comply 

with § 51.212 (regarding testing, 

inspection, enforcement, and 

complaints); 

(3) If the SIP revision contains any 

transportation control measures, then 

the SIP revision must comply with 

§ 51.213 (regarding transportation 

control measures); 

(4)(i) If the SIP revision contains 

measures to control EGUs, then the SIP 

revision must require such sources to 

comply with the monitoring, 

recordkeeping, and reporting provisions 

of subpart H of part 75 of this chapter. 

(ii) If the SIP revision contains 

measures to control fossil fuel-fired nonEGUs that are boilers or combustion 

turbines with a maximum design heat 

input greater than 250 mmBtu/hr, then 

the SIP revision must require such 

sources to comply with the monitoring, 

recordkeeping, and reporting provisions 

of subpart H of part 75 of this chapter. 

(iii) If the SIP revision contains 

measures to control any other non-EGUs 

that are not described in paragraph 

(u)(4)(ii) of this section, then the SIP 

revision must require such sources to 

comply with the monitoring, 

recordkeeping, and reporting provisions 

of subpart H of part 75 of this chapter, 

or the State must demonstrate why such 

requirements are not practicable and 

adopt alternative requirements that 

ensure that the required emissions 

reductions will be quantified, to the 

maximum extent practicable, with the 

same degree of assurance with which 

emissions are quantified for sources 

subject to subpart H of part 75 of this 

chapter. 

(v) Each SIP revision must show that 

the State has legal authority to carry out 

the SIP revision, including authority to: 

(1) Adopt emissions standards and 

limitations and any other measures 

necessary for attainment and 

maintenance of the State’s relevant 

Ozone Season EGU NOX Budget or the 

Ozone Season Non-EGU NOX Reduction 

Requirement, as applicable, under 

paragraph (q) of this section; 

25326 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

(2) Enforce applicable laws, 

regulations, and standards and seek 

injunctive relief; 

(3) Obtain information necessary to 

determine whether air pollution sources 

are in compliance with applicable laws, 

regulations, and standards, including 

authority to require recordkeeping and 

to make inspections and conduct tests of 

air pollution sources; and 

(4)(i) Require owners or operators of 

stationary sources to install, maintain, 

and use emissions monitoring devices 

and to make periodic reports to the State 

on the nature and amounts of emissions 

from such stationary sources; and 

(ii) Make the data described in 

paragraph (v)(4)(i) of this section 

available to the public within a 

reasonable time after being reported and 

as correlated with any applicable 

emissions standards or limitations. 

(w)(1) The provisions of law or 

regulation that the State determines 

provide the authorities required under 

this section must be specifically 

identified, and copies of such laws or 

regulations must be submitted with the 

SIP revision. 

(2) Legal authority adequate to fulfill 

the requirements of paragraphs (v)(3) 

and (4) of this section may be delegated 

to the State under section 114 of the 

CAA. 

(x)(1) A SIP revision may assign legal 

authority to local agencies in 

accordance with § 51.232. 

(2) Each SIP revision must comply 

with § 51.240 (regarding general plan 

requirements). 

(y) Each SIP revision must comply 

with § 51.280 (regarding resources). 

(z) Each SIP revision must provide for 

State compliance with the reporting 

requirements in § 51.125. 

(aa)(1) Notwithstanding any other 

provision of this section, if a State 

adopts regulations substantively 

identical to subparts AAAA through IIII 

of part 96 of this chapter (CAIR Ozone 

Season NOX Trading Program), 

incorporates such subparts by reference 

into its regulations, or adopts 

regulations that differ substantively 

from such subparts only as set forth in 

paragraph (aa)(2) of this section, then 

such emissions trading program in the 

State’s SIP revision is automatically 

approved as meeting the requirements 

of paragraph (q) of this section, 

provided that the State has the legal 

authority to take such action and to 

implement its responsibilities under 

such regulations. 

(2) If a State adopts an emissions 

trading program that differs 

substantively from subparts AAAA 

through IIII of part 96 of this chapter 

only as follows, then the emissions 

trading program is approved as set forth 

in paragraph (aa)(1) of this section. 

(i) The State may expand the 

applicability provisions in § 96.304 to 

include all non-EGUs subject to the 

State’s emissions trading program 

approved under § 51.121(p). 

(ii) The State may decline to adopt the 

CAIR NOX Ozone Season opt-in 

provisions of: 

(A) Subpart IIII of this part and the 

provisions applicable only to CAIR NOX

Ozone Season opt-in units in subparts 

AAAA through HHHH of this part; 

(B) Section 96.388(b) of this chapter 

and the provisions of subpart IIII of this 

part applicable only to CAIR NOX

Ozone Season opt-in units under 

§ 96.388(b); or 

(C) Section 96.388(c) of this chapter 

and the provisions of subpart IIII of this 

part applicable only to CAIR NOX

Ozone Season opt-in units under 

§ 96.388(c).

(iii) The State may decline to adopt 

the allocation provisions set forth in 

subpart EEEE of part 96 of this chapter 

and may instead adopt any methodology 

for allocating CAIR NOX Ozone Season 

allowances to individual sources, as 

follows: 

(A) The State may provide for 

issuance of an amount of CAIR Ozone 

Season NOX allowances for an ozone 

season, in addition to the amount in the 

State’s Ozone Season EGU NOX Budget 

for such ozone season, not exceeding 

the amount of NOX SIP Call allowances 

allocated for the ozone season under the 

NOX Budget Trading Program to nonEGUs that the applicability provisions 

in § 96.304 are expanded to include 

under paragraph (aa)(2)(i) of this 

section; 

(B) The State’s methodology must not 

allow the State to allocate CAIR Ozone 

Season NOX allowances for an ozone 

season in excess of the amount in the 

State’s Ozone Season EGU NOX Budget 

for such ozone season plus any 

additional amount of CAIR Ozone 

Season NOX allowances issued under 

paragraph (aa)(2)(iii)(A) of this section 

for such ozone season; 

(C) The State’s methodology must 

require that, for EGUs commencing 

operation before January 1, 2001, the 

State will determine, and notify the 

Administrator of, each unit’s allocation 

of CAIR NOX allowances by October 31, 

2006 for the ozone seasons 2009, 2010, 

and 2011 and by October 31, 2008 and 

October 31 of each year thereafter for 

the ozone season in the 4th year after 

the year of the notification deadline; 

and 

(D) The State’s methodology must 

require that, for EGUs commencing 

operation on or after January 1, 2001, 

the State will determine, and notify the 

Administrator of, each unit’s allocation 

of CAIR Ozone Season NOX allowances 

by July 31 of the calendar year of the 

ozone season for which the CAIR Ozone 

Season NOX allowances are allocated. 

(3) A State that adopts an emissions 

trading program in accordance with 

paragraph (aa)(1) or (2) of this section is 

not required to adopt an emissions 

trading program in accordance with 

paragraph (o)(1) or (2) of this section or 

§ 51.153(o)(1) or (2). 

(4) If a State adopts an emissions 

trading program that differs 

substantively from subparts AAAA 

through IIII of part 96 of this chapter, 

other than as set forth in paragraph 

(aa)(2) of this section, then such 

emissions trading program is not 

automatically approved as set forth in 

paragraph (aa)(1) or (2) of this section 

and will be reviewed by the 

Administrator for approvability in 

accordance with the other provisions of 

this section, provided that the NOX

allowances issued under such emissions 

trading program shall not, and the SIP 

revision shall state that such NOX

allowances shall not, qualify as CAIR 

NOX allowances or CAIR Ozone Season 

NOX allowances under any emissions 

trading program approved under 

paragraphs (o)(1) or (2) or (aa)(1) or (2) 

of this section. 

(bb)(1)(i) The State may revise its SIP 

to provide that, for each ozone season 

during which a State implements 

control measures on EGUs or non-EGUs 

through an emissions trading program 

approved under paragraph (aa)(1) or (2) 

of this section, such EGUs and nonEGUs shall not be subject to the 

requirements of the State’s SIP meeting 

the requirements of § 51.121, if the State 

meets the requirement in paragraph 

(bb)(1)(ii) of this section. 

(ii) For a State under paragraph 

(bb)(1)(i) of this section, if the State’s 

amount of tons specified in paragraph 

(q)(2) of this section exceeds the State’s 

amount of NOX SIP Call allowances 

allocated for the ozone season in 2009 

or in any year thereafter for the same 

types and sizes of units as those covered 

by the amount of tons specified in 

paragraph (q)(2) of this section, then the 

State must replace the former amount 

for such ozone season by the latter 

amount for such ozone season in 

applying paragraph (q) of this section. 

(2) Rhode Island may revise its SIP to 

provide that, for each ozone season 

during which Rhode Island implements 

control measures on EGUs and nonEGUs through an emissions trading 

program adopted in regulations that 

differ substantively from subparts 

AAAA through IIII of part 96 of this 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25327

chapter as set forth in this paragraph, 

such EGUs and non-EGUs shall not be 

subject to the requirements of the State’s 

SIP meeting the requirements of 

§ 51.121. 

(i) Rhode Island must expand the 

applicability provisions in § 96.304 to 

include all non-EGUs subject to Rhode 

Island’s emissions trading program 

approved under § 51.121(p). 

(ii) Rhode Island may decline to adopt 

the CAIR NOX Ozone Season opt-in 

provisions of: 

(A) Subpart IIII of this part and the 

provisions applicable only to CAIR NOX

Ozone Season opt-in units in subparts 

AAAA through HHHH of this part; 

(B) Section 96.388(b) of this chapter 

and the provisions of subpart IIII of this 

part applicable only to CAIR NOX

Ozone Season opt-in units under 

§ 96.388(b); or 

(C) Section 96.388(c) of this chapter 

and the provisions of subpart IIII of this 

part applicable only to CAIR NOX

Ozone Season opt-in units under 

§ 96.388(c). 

(iii) Rhode Island may adopt the 

allocation provisions set forth in subpart 

EEEE of part 96 of this chapter, 

provided that Rhode Island must 

provide for issuance of an amount of 

CAIR Ozone Season NOX allowances for 

an ozone season not exceeding 936 tons 

for 2009 and thereafter; 

(iv) Rhode Island may adopt any 

methodology for allocating CAIR NOX

Ozone Season allowances to individual 

sources, as follows:

(A) Rhode Island’s methodology must 

not allow Rhode Island to allocate CAIR 

Ozone Season NOX allowances for an 

ozone season in excess of 936 tons for 

2009 and thereafter; 

(B) Rhode Island’s methodology must 

require that, for EGUs commencing 

operation before January 1, 2001, Rhode 

Island will determine, and notify the 

Administrator of, each unit’s allocation 

of CAIR NOX allowances by October 31, 

2006 for the ozone seasons 2009, 2010, 

and 2011 and by October 31, 2008 and 

October 31 of each year thereafter for 

the ozone season in the 4th year after 

the year of the notification deadline; 

and 

(C) Rhode Island’s methodology must 

require that, for EGUs commencing 

operation on or after January 1, 2001, 

Rhode Island will determine, and notify 

the Administrator of, each unit’s 

allocation of CAIR Ozone Season NOX

allowances by July 31 of the calendar 

year of the ozone season for which the 

CAIR Ozone Season NOX allowances are 

allocated. 

(3) Notwithstanding a SIP revision by 

a State authorized under paragraph 

(bb)(1) of this section or by Rhode Island 

under paragraph (bb)(2) of this section, 

if the State’s or Rhode Island’s SIP that, 

without such SIP revision, imposes 

control measures on EGUs or non-EGUs 

under § 51.121 is determined by the 

Administrator to meet the requirements 

of § 51.121, such SIP shall be deemed to 

continue to meet the requirements of 

§ 51.121. 

(cc) The terms used in this section 

shall have the following meanings: 

Administrator means the 

Administrator of the United States 

Environmental Protection Agency or the 

Administrator’s duly authorized 

representative. 

Allocate or allocation means, with 

regard to allowances, the determination 

of the amount of allowances to be 

initially credited to a source. 

Boiler means an enclosed fossil- or 

other-fuel-fired combustion device used 

to produce heat and to transfer heat to 

recirculating water, steam, or other 

medium. 

Bottoming-cycle cogeneration unit

means a cogeneration unit in which the 

energy input to the unit is first used to 

produce useful thermal energy and at 

least some of the reject heat from the 

useful thermal energy application or 

process is then used for electricity 

production. 

Clean Air Act or CAA means the 

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

Cogeneration unit means a stationary, 

fossil-fuel-fired boiler or stationary, 

fossil-fuel-fired combustion turbine: 

(1) Having equipment used to produce 

electricity and useful thermal energy for 

industrial, commercial, heating, or 

cooling purposes through the sequential 

use of energy; and 

(2) Producing during the 12-month 

period starting on the date the unit first 

produces electricity and during any 

calendar year after which the unit first 

produces electricity—

(i) For a topping-cycle cogeneration 

unit, 

(A) Useful thermal energy not less 

than 5 percent of total energy output; 

and 

(B) Useful power that, when added to 

one-half of useful thermal energy 

produced, is not less then 42.5 percent 

of total energy input, if useful thermal 

energy produced is 15 percent or more 

of total energy output, or not less than 

45 percent of total energy input, if 

useful thermal energy produced is less 

than 15 percent of total energy output. 

(ii) For a bottoming-cycle 

cogeneration unit, useful power not less 

than 45 percent of total energy input. 

Combustion turbine means: 

(1) An enclosed device comprising a 

compressor, a combustor, and a turbine 

and in which the flue gas resulting from 

the combustion of fuel in the combustor 

passes through the turbine, rotating the 

turbine; and 

(2) If the enclosed device under 

paragraph (1) of this definition is 

combined cycle, any associated heat 

recovery steam generator and steam 

turbine. 

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. 

Electric generating unit or EGU

means:

(1) Except as provided in paragraph 

(2) of this definition, a stationary, fossilfuel-fired boiler or stationary, fossilfuel-fired combustion turbine serving at 

any time, since the start-up of the unit’s 

combustion chamber, a generator with 

nameplate capacity of more than 25 

MWe producing electricity for sale. 

(2) For a unit that qualifies as a 

cogeneration unit during the 12-month 

period starting on the date the unit first 

produces electricity and continues to 

qualify as a cogeneration unit, a 

cogeneration unit serving at any time a 

generator with nameplate capacity of 

more than 25 MWe and supplying in 

any calendar year more than one-third 

of the unit’s potential electric output 

capacity or 219,000 MWh, whichever is 

greater, to any utility power distribution 

system for sale. If a unit qualifies as a 

cogeneration unit during the 12-month 

period starting on the date the unit first 

produces electricity but subsequently no 

longer qualifies as a cogeneration unit, 

the unit shall be subject to paragraph (1) 

of this definition starting on the day on 

which the unit first no longer qualifies 

as a cogeneration unit. 

Fossil fuel means natural gas, 

petroleum, coal, or any form of solid, 

liquid, or gaseous fuel derived from 

such material. 

Fossil-fuel-fired means, with regard to 

a unit, combusting any amount of fossil 

fuel in any calendar year. 

Generator means a device that 

produces electricity. 

Maximum design heat input means: 

(1) Starting from the initial 

installation of a unit, the maximum 

amount of fuel per hour (in Btu/hr) that 

a unit is capable of combusting on a 

steady state basis as specified by the 

manufacturer of the unit; 

(2)(i) Except as provided in paragraph 

(2)(ii) of this definition, starting from 

the completion of any subsequent 

physical change in the unit resulting in 

an increase in the maximum amount of 

fuel per hour (in Btu/hr) that a unit is 

capable of combusting on a steady state 

basis, such increased maximum amount 

25328 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

as specified by the person conducting 

the physical change; or 

(ii) For purposes of applying the 

definition of the term ‘‘potential 

electrical output capacity,’’ starting from 

the completion of any subsequent 

physical change in the unit resulting in 

a decrease in the maximum amount of 

fuel per hour (in Btu/hr) that a unit is 

capable of combusting on a steady state 

basis, such decreased maximum amount 

as specified by the person conducting 

the physical change. 

NAAQS means National Ambient Air 

Quality Standard. 

Nameplate capacity means, starting 

from the initial installation of a 

generator, the maximum electrical 

generating output (in MWe) that the 

generator is capable of producing on a 

steady state basis and during continuous 

operation (when not restricted by 

seasonal or other deratings) as specified 

by the manufacturer of the generator or, 

starting from the completion of any 

subsequent physical change in the 

generator resulting in an increase in the 

maximum electrical generating output 

(in MWe) that the generator is capable 

of producing on a steady state basis and 

during continuous operation (when not 

restricted by seasonal or other 

deratings), such increased maximum 

amount as specified by the person 

conducting the physical change. 

Non-EGU means a source of NOX

emissions that is not an EGU. 

NOX Budget Trading Program means 

a multi-state nitrogen oxides air 

pollution control and emission 

reduction program approved and 

administered by the Administrator in 

accordance with subparts A through I of 

this part and § 51.121, as a means of 

mitigating interstate transport of ozone 

and nitrogen oxides. 

NOX SIP Call allowance means a 

limited authorization issued by the 

Administrator under the NOX Budget 

Trading Program to emit up to one ton 

of nitrogen oxides during the ozone 

season of the specified year or any year 

thereafter, provided that the provision 

in § 51.121(b)(2)(ii)(E) shall not be used 

in applying this definition. 

Ozone season means the period, 

which begins May 1 and ends 

September 30 of any year.

Potential electrical output capacity

means 33 percent of a unit’s maximum 

design heat input, divided by 3,413 Btu/

kWh, divided by 1,000 kWh/MWh, and 

multiplied by 8,760 hr/yr. 

Sequential use of energy means: 

(1) For a topping-cycle cogeneration 

unit, the use of reject heat from 

electricity production in a useful 

thermal energy application or process; 

or 

(2) For a bottoming-cycle cogeneration 

unit, the use of reject heat from useful 

thermal energy application or process in 

electricity production. 

Topping-cycle cogeneration unit

means a cogeneration unit in which the 

energy input to the unit is first used to 

produce useful power, including 

electricity, and at least some of the 

reject heat from the electricity 

production is then used to provide 

useful thermal energy. 

Total energy input means, with regard 

to a cogeneration unit, total energy of all 

forms supplied to the cogeneration unit, 

excluding energy produced by the 

cogeneration unit itself. 

Total energy output means, with 

regard to a cogeneration unit, the sum 

of useful power and useful thermal 

energy produced by the cogeneration 

unit. 

Unit means a stationary, fossil-fuelfired boiler or a stationary, fossil-fuelfired combustion turbine. 

Useful power means, with regard to a 

cogeneration unit, electricity or 

mechanical energy made available for 

use, excluding any such energy used in 

the power production process (which 

process includes, but is not limited to, 

any on-site processing or treatment of 

fuel combusted at the unit and any onsite emission controls). 

Useful thermal energy means, with 

regard to a cogeneration unit, thermal 

energy that is: 

(1) Made available to an industrial or 

commercial process, excluding any heat 

contained in condensate return or 

makeup water; 

(2) Used in a heat application (e.g., 

space heating or domestic hot water 

heating); or 

(3) Used in a space cooling 

application (i.e., thermal energy used by 

an absorption chiller). 

Utility power distribution system

means the portion of an electricity grid 

owned or operated by a utility and 

dedicated to delivering electricity to 

customers. 

(dd) New Hampshire may revise its 

SIP to implements control measures on 

EGUs and non-EGUs through an 

emissions trading program adopted in 

regulations that differ substantively 

from subparts AAAA through IIII of part 

96 of this chapter as set forth in this 

paragraph. 

(1) New Hampshire must expand the 

applicability provisions in § 96.304 of 

this chapter to include all non-EGUs 

subject to New Hampshire’s emissions 

trading program at New Hampshire 

Code of Administrative Rules, chapter 

Env-A 3200 (2004). 

(2) New Hampshire may decline to 

adopt the CAIR NOX Ozone Season optin provisions of: 

(i) Subpart IIII of this part and the 

provisions applicable only to CAIR NOX

Ozone Season opt-in units in subparts 

AAAA through HHHH of this part; 

(ii) Section 96.388(b) of this chapter 

and the provisions of subpart IIII of this 

part applicable only to CAIR NOX

Ozone Season opt-in units under 

§ 96.388(b); or 

(iii) Section 96.388(c) of this chapter 

and the provisions of subpart IIII of this 

part applicable only to CAIR NOX

Ozone Season opt-in units under 

§ 96.388(c). 

(3) New Hampshire may adopt the 

allocation provisions set forth in subpart 

EEEE of part 96 of this chapter, 

provided that New Hampshire must 

provide for issuance of an amount of 

CAIR Ozone Season NOX allowances for 

an ozone season not exceeding 3,000 

tons for 2009 and thereafter; 

(4) New Hampshire may adopt any 

methodology for allocating CAIR NOX

Ozone Season allowances to individual 

sources, as follows: 

(i) New Hampshire’s methodology 

must not allow New Hampshire to 

allocate CAIR Ozone Season NOX

allowances for an ozone season in 

excess of 3,000 tons for 2009 and 

thereafter;

(ii) New Hampshire’s methodology 

must require that, for EGUs 

commencing operation before January 1, 

2001, New Hampshire will determine, 

and notify the Administrator of, each 

unit’s allocation of CAIR NOX

allowances by October 31, 2006 for the 

ozone seasons 2009, 2010, and 2011 and 

by October 31, 2008 and October 31 of 

each year thereafter for the ozone season 

in the 4th year after the year of the 

notification deadline; and 

(iii) New Hampshire’s methodology 

must require that, for EGUs 

commencing operation on or after 

January 1, 2001, New Hampshire will 

determine, and notify the Administrator 

of, each unit’s allocation of CAIR Ozone 

Season NOX allowances by July 31 of 

the calendar year of the ozone season for 

which the CAIR Ozone Season NOX

allowances are allocated.

■ 5. Part 51 is amended by adding 

§ 51.124 to Subpart G to read as follows:

§ 51.124 Findings and requirements for 

submission of State implementation plan 

revisions relating to emissions of sulfur 

dioxide pursuant to the Clean Air Interstate 

Rule. 

(a) Under section 110(a)(1) of the 

CAA, 42 U.S.C. 7410(a)(1), the 

Administrator determines that each 

State identified in paragraph (c) of this 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25329

section must submit a SIP revision to 

comply with the requirements of section 

110(a)(2)(D)(i)(I) of the CAA, 42 U.S.C. 

7410(a)(2)(D)(i)(I), through the adoption 

of adequate provisions prohibiting 

sources and other activities from 

emitting SO2 in amounts that will 

contribute significantly to 

nonattainment in, or interfere with 

maintenance by, one or more other 

States with respect to the fine particles 

(PM2.5) NAAQS. 

(b) For each State identified in 

paragraph (c) of this section, the SIP 

revision required under paragraph (a) of 

this section will contain adequate 

provisions, for purposes of complying 

with section 110(a)(2)(D)(i)(I) of the 

CAA, 42 U.S.C. 7410(a)(2)(D)(i)(I), only 

if the SIP revision contains control 

measures that assure compliance with 

the applicable requirements of this 

section. 

(c) The following States are subject to 

the requirements of this section: 

Alabama, Florida, Georgia, Illinois, 

Indiana, Iowa, Kentucky, Louisiana, 

Maryland, Michigan, Minnesota, 

Mississippi, Missouri, New York, North 

Carolina, Ohio, Pennsylvania, South 

Carolina, Tennessee, Texas, Virginia, 

West Virginia, and Wisconsin, and the 

District of Columbia. 

(d)(1) The SIP revision under 

paragraph (a) of this section must be 

submitted to EPA by no later than 

September 11, 2006. 

(2) The requirements of appendix V to 

this part shall apply to the SIP revision 

under paragraph (a) of this section. 

(3) The State shall deliver 5 copies of 

the SIP revision under paragraph (a) of 

this section to the appropriate Regional 

Office, with a letter giving notice of 

such action. 

(e) The State’s SIP revision shall 

contain control measures and 

demonstrate that they will result in 

compliance with the State’s Annual 

EGU SO2 Budget, if applicable, and 

achieve the State’s Annual Non-EGU 

SO2 Reduction Requirement, if 

applicable, for the appropriate periods. 

The amounts of the State’s Annual EGU 

SO2 Budget and Annual Non-EGU SO2

Reduction Requirement shall be 

determined as follows: 

(1)(i) The Annual EGU SO2 Budget for 

the State is defined as the total amount 

of SO2 emissions from all EGUs in that 

State for a year, if the State meets the 

requirements of paragraph (a) of this 

section by imposing control measures, 

at least in part, on EGUs. If the State 

imposes control measures under this 

section on only EGUs, the Annual EGU 

SO2 Budget for the State shall not 

exceed the amount, during the indicated 

periods, specified in paragraph (e)(2) of 

this section. 

(ii) The Annual Non-EGU SO2

Reduction Requirement, if applicable, is 

defined as the total amount of SO2

emission reductions that the State 

demonstrates, in accordance with 

paragraph (g) of this section, it will 

achieve from non-EGUs during the 

appropriate period. If the State meets 

the requirements of paragraph (a) of this 

section by imposing control measures 

on only non-EGUs, then the State’s 

Annual Non-EGU SO2 Reduction 

Requirement shall equal or exceed, 

during the appropriate periods, the 

amount determined in accordance with 

paragraph (e)(3) of this section.

(iii) If a State meets the requirements 

of paragraph (a) of this section by 

imposing control measures on both 

EGUs and non-EGUs, then: 

(A) The Annual Non-EGU SO2

Reduction Requirement shall equal or 

exceed the difference between the 

amount specified in paragraph (e)(2) of 

this section for the appropriate period 

and the amount of the State’s Annual 

EGU SO2 Budget specified in the SIP 

revision for the appropriate period; and 

(B) The Annual EGU SO2 Budget shall 

not exceed, during the indicated 

periods, the amount specified in 

paragraph (e)(2) of this section plus the 

amount of the Annual Non-EGU SO2

Reduction Requirement under 

paragraph (e)(1)(iii)(A) of this section for 

the appropriate period. 

(2) For a State that complies with the 

requirements of paragraph (a) of this 

section by imposing control measures 

on only EGUs, the amount of the 

Annual EGU SO2 Budget, in tons of SO2

per year, shall be as follows, for the 

indicated State for the indicated period:

State 

Annual EGU SO2

budget for 2010–2014 

(tons) 

Annual EGU SO2

budget for 2015 and 

thereafter (tons) 

Alabama ........................................................................................................................................... 157,582 110,307 

District of Columbia ......................................................................................................................... 708 495 

Florida .............................................................................................................................................. 253,450 177,415 

Georgia ............................................................................................................................................ 213,057 149,140 

Illinois ............................................................................................................................................... 192,671 134,869 

Indiana ............................................................................................................................................. 254,599 178,219 

Iowa ................................................................................................................................................. 64,095 44,866 

Kentucky .......................................................................................................................................... 188,773 132,141 

Louisiana .......................................................................................................................................... 59,948 41,963 

Maryland .......................................................................................................................................... 70,697 49,488 

Michigan ........................................................................................................................................... 178,605 125,024 

Minnesota ........................................................................................................................................ 49,987 34,991 

Mississippi ........................................................................................................................................ 33,763 23,634 

Missouri ............................................................................................................................................ 137,214 96,050 

New York ......................................................................................................................................... 135,139 94,597 

North Carolina .................................................................................................................................. 137,342 96,139 

Ohio ................................................................................................................................................. 333,520 233,464 

Pennsylvania .................................................................................................................................... 275,990 193,193 

South Carolina ................................................................................................................................. 57,271 40,089 

Tennessee ....................................................................................................................................... 137,216 96,051 

Texas ............................................................................................................................................... 320,946 224,662 

Virginia ............................................................................................................................................. 63,478 44,435 

West Virginia .................................................................................................................................... 215,881 151,117 

Wisconsin ......................................................................................................................................... 87,264 61,085 

25330 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

(3) For a State that complies with the 

requirements of paragraph (a) of this 

section by imposing control measures 

on only non-EGUs, the amount of the 

Annual Non-EGU SO2 Reduction 

Requirement, in tons of SO2 per year, 

shall be determined, for the State for 

2010 and thereafter, by subtracting the 

amount of the State’s Annual EGU SO2

Budget for the appropriate year, 

specified in paragraph (e)(2) of this 

section, from an amount equal to 2 

times the State’s Annual EGU SO2

Budget for 2010 through 2014, specified 

in paragraph (e)(2) of this section. 

(f) Each SIP revision must set forth 

control measures to meet the amounts 

specified in paragraph (e) of this 

section, as applicable, including the 

following: 

(1) A description of enforcement 

methods including, but not limited to: 

(i) Procedures for monitoring 

compliance with each of the selected 

control measures; 

(ii) Procedures for handling 

violations; and 

(iii) A designation of agency 

responsibility for enforcement of 

implementation. 

(2)(i) If a State elects to impose 

control measures on EGUs, then those 

measures must impose an annual SO2

mass emissions cap on all such sources 

in the State. 

(ii) If a State elects to impose control 

measures on fossil fuel-fired non-EGUs 

that are boilers or combustion turbines 

with a maximum design heat input 

greater than 250 mmBtu/hr, then those 

measures must impose an annual SO2

mass emissions cap on all such sources 

in the State. 

(iii) If a State elects to impose control 

measures on non-EGUs other than those 

described in paragraph (f)(2)(ii) of this 

section, then those measures must 

impose an annual SO2 mass emissions 

cap on all such sources in the State, or 

the State must demonstrate why such 

emissions cap is not practicable, and 

adopt alternative requirements that 

ensure that the State will comply with 

its requirements under paragraph (e) of 

this section, as applicable, in 2010 and 

subsequent years.

(g)(1) Each SIP revision that contains 

control measures covering non-EGUs as 

part or all of a State’s obligation in 

meeting its requirement under 

paragraph (a) of this section must 

demonstrate that such control measures 

are adequate to provide for the timely 

compliance with the State’s Annual 

Non-EGU SO2 Reduction Requirement 

under paragraph (e) of this section and 

are not adopted or implemented by the 

State, as of May 12, 2005, and are not 

adopted or implemented by the federal 

government, as of the date of 

submission of the SIP revision by the 

State to EPA. 

(2) The demonstration under 

paragraph (g)(1) of this section must 

include the following, with respect to 

each source category of non-EGUs for 

which the SIP revision requires control 

measures: 

(i) A detailed historical baseline 

inventory of SO2 mass emissions from 

the source category in a representative 

year consisting, at the State’s election, of 

2002, 2003, 2004, or 2005, or an average 

of 2 or more of those years, absent the 

control measures specified in the SIP 

revision. 

(A) This inventory must represent 

estimates of actual emissions based on 

monitoring data in accordance with part 

75 of this chapter, if the source category 

is subject to part 75 monitoring 

requirements in accordance with part 75 

of this chapter. 

(B) In the absence of monitoring data 

in accordance with part 75 of this 

chapter, actual emissions must be 

quantified, to the maximum extent 

practicable, with the same degree of 

assurance with which emissions are 

quantified for sources subject to part 75 

of this chapter and using source-specific 

or source-category-specific assumptions 

that ensure a source’s or source 

category’s actual emissions are not 

overestimated. If a State uses factors to 

estimate emissions, production or 

utilization, or effectiveness of controls 

or rules for a source category, such 

factors must be chosen to ensure that 

emissions are not overestimated. 

(C) For measures to reduce emissions 

from motor vehicles, emission estimates 

must be based on an emissions model 

that has been approved by EPA for use 

in SIP development and must be 

consistent with the planning 

assumptions regarding vehicle miles 

traveled and other factors current at the 

time of the SIP development. 

(D) For measures to reduce emissions 

from nonroad engines or vehicles, 

emission estimates methodologies must 

be approved by EPA. 

(ii) A detailed baseline inventory of 

SO2 mass emissions from the source 

category in the years 2010 and 2015, 

absent the control measures specified in 

the SIP revision and reflecting changes 

in these emissions from the historical 

baseline year to the years 2010 and 

2015, based on projected changes in the 

production input or output, population, 

vehicle miles traveled, economic 

activity, or other factors as applicable to 

this source category. 

(A) These inventories must account 

for implementation of any control 

measures that are adopted or 

implemented by the State, as of May 12, 

2005, or adopted or implemented by the 

federal government, as of the date of 

submission of the SIP revision by the 

State to EPA, and must exclude any 

control measures specified in the SIP 

revision to meet the SO2 emissions 

reduction requirements of this section. 

(B) Economic and population 

forecasts must be as specific as possible 

to the applicable industry, State, and 

county of the source or source category 

and must be consistent with both 

national projections and relevant official 

planning assumptions, including 

estimates of population and vehicle 

miles traveled developed through 

consultation between State and local 

transportation and air quality agencies. 

However, if these official planning 

assumptions are inconsistent with 

official U.S. Census projections of 

population or with energy consumption 

projections contained in the U.S. 

Department of Energy’s most recent 

Annual Energy Outlook, then the SIP 

revision must make adjustments to 

correct the inconsistency or must 

demonstrate how the official planning 

assumptions are more accurate. 

(C) These inventories must account 

for any changes in production method, 

materials, fuels, or efficiency that are 

expected to occur between the historical 

baseline year and 2010 or 2015, as 

appropriate. 

(iii) A projection of SO2 mass 

emissions in 2010 and 2015 from the 

source category assuming the same 

projected changes as under paragraph 

(g)(2)(ii) of this section and resulting 

from implementation of each of the 

control measures specified in the SIP 

revision. 

(A) These inventories must address 

the possibility that the State’s new 

control measures may cause production 

or utilization, and emissions, to shift to 

unregulated or less stringently regulated 

sources in the source category in the 

same or another State, and these 

inventories must include any such 

amounts of emissions that may shift to 

such other sources. 

(B) The State must provide EPA with 

a summary of the computations, 

assumptions, and judgments used to 

determine the degree of reduction in 

projected 2010 and 2015 SO2 emissions 

that will be achieved from the 

implementation of the new control 

measures compared to the relevant 

baseline emissions inventory. 

(iv) The result of subtracting the 

amounts in paragraph (g)(2)(iii) of this 

section for 2010 and 2015, respectively, 

from the lower of the amounts in 

paragraph (g)(2)(i) or (g)(2)(ii) of this 

section for 2010 and 2015, respectively, 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25331

may be credited towards the State’s 

Annual Non-EGU SO2 Reduction 

Requirement in paragraph (e)(3) of this 

section for the appropriate period.

(v) Each SIP revision must identify 

the sources of the data used in each 

estimate and each projection of 

emissions. 

(h) Each SIP revision must comply 

with § 51.116 (regarding data 

availability). 

(i) Each SIP revision must provide for 

monitoring the status of compliance 

with any control measures adopted to 

meet the State’s requirements under 

paragraph (e) of this section, as follows: 

(1) The SIP revision must provide for 

legally enforceable procedures for 

requiring owners or operators of 

stationary sources to maintain records 

of, and periodically report to the State: 

(i) Information on the amount of SO2

emissions from the stationary sources; 

and 

(ii) Other information as may be 

necessary to enable the State to 

determine whether the sources are in 

compliance with applicable portions of 

the control measures; 

(2) The SIP revision must comply 

with § 51.212 (regarding testing, 

inspection, enforcement, and 

complaints); 

(3) If the SIP revision contains any 

transportation control measures, then 

the SIP revision must comply with 

§ 51.213 (regarding transportation 

control measures); 

(4)(i) If the SIP revision contains 

measures to control EGUs, then the SIP 

revision must require such sources to 

comply with the monitoring, 

recordkeeping, and reporting provisions 

of part 75 of this chapter. 

(ii) If the SIP revision contains 

measures to control fossil fuel-fired nonEGUs that are boilers or combustion 

turbines with a maximum design heat 

input greater than 250 mmBtu/hr, then 

the SIP revision must require such 

sources to comply with the monitoring, 

recordkeeping, and reporting provisions 

of part 75 of this chapter. 

(iii) If the SIP revision contains 

measures to control any other non-EGUs 

that are not described in paragraph 

(i)(4)(ii) of this section, then the SIP 

revision must require such sources to 

comply with the monitoring, 

recordkeeping, and reporting provisions 

of part 75 of this chapter, or the State 

must demonstrate why such 

requirements are not practicable and 

adopt alternative requirements that 

ensure that the required emissions 

reductions will be quantified, to the 

maximum extent practicable, with the 

same degree of assurance with which 

emissions are quantified for sources 

subject to part 75 of this chapter. 

(j) Each SIP revision must show that 

the State has legal authority to carry out 

the SIP revision, including authority to: 

(1) Adopt emissions standards and 

limitations and any other measures 

necessary for attainment and 

maintenance of the State’s relevant 

Annual EGU SO2 Budget or the Annual 

Non-EGU SO2 Reduction Requirement, 

as applicable, under 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; and 

(4)(i) Require owners or operators of 

stationary sources to install, maintain, 

and use emissions monitoring devices 

and to make periodic reports to the State 

on the nature and amounts of emissions 

from such stationary sources; and 

(ii) Make the data described in 

paragraph (j)(4)(i) of this section 

available to the public within a 

reasonable time after being reported and 

as correlated with any applicable 

emissions standards or limitations. 

(k)(1) The provisions of law or 

regulation that the State determines 

provide the authorities required under 

this section must be specifically 

identified, and copies of such laws or 

regulations must be submitted with the 

SIP revision. 

(2) Legal authority adequate to fulfill 

the requirements of paragraphs (j)(3) 

and (4) of this section may be delegated 

to the State under section 114 of the 

CAA. 

(l)(1) A SIP revision may assign legal 

authority to local agencies in 

accordance with § 51.232.

(2) Each SIP revision must comply 

with § 51.240 (regarding general plan 

requirements). 

(m) Each SIP revision must comply 

with § 51.280 (regarding resources). 

(n) Each SIP revision must provide for 

State compliance with the reporting 

requirements in § 51.125. 

(o)(1) Notwithstanding any other 

provision of this section, if a State 

adopts regulations substantively 

identical to subparts AAA through III of 

part 96 of this chapter (CAIR SO2

Trading Program), incorporates such 

subparts by reference into its 

regulations, or adopts regulations that 

differ substantively from such subparts 

only as set forth in paragraph (o)(2) of 

this section, then such emissions 

trading program in the State’s SIP 

revision is automatically approved as 

meeting the requirements of paragraph 

(e) of this section, provided that the 

State has the legal authority to take such 

action and to implement its 

responsibilities under such regulations. 

(2) If a State adopts an emissions 

trading program that differs 

substantively from subparts AAA 

through III of part 96 of this chapter 

only as follows, then the emissions 

trading program is approved as set forth 

in paragraph (o)(1) of this section. 

(i) The State may decline to adopt the 

CAIR SO2 opt-in provisions of subpart 

III of this part and the provisions 

applicable only to CAIR SO2 opt-in 

units in subparts AAA through HHH of 

this part. 

(ii) The State may decline to adopt the 

CAIR SO2 opt-in provisions of 

§ 96.288(b) of this chapter and the 

provisions of subpart III of this part 

applicable only to CAIR SO2 opt-in 

units under § 96.288(b). 

(iii) The State may decline to adopt 

the CAIR SO2 opt-in provisions of 

§ 96.288(c) of this chapter and the 

provisions of subpart II of this part 

applicable only to CAIR SO2 opt-in 

units under § 96.288(c). 

(3) A State that adopts an emissions 

trading program in accordance with 

paragraph (o)(1) or (2) of this section is 

not required to adopt an emissions 

trading program in accordance with 

§ 96.123 (o)(1) or (2) or (aa)(1) or (2) of 

this chapter. 

(4) If a State adopts an emissions 

trading program that differs 

substantively from subparts AAA 

through III of part 96 of this chapter, 

other than as set forth in paragraph 

(o)(2) of this section, then such 

emissions trading program is not 

automatically approved as set forth in 

paragraph (o)(1) or (2) of this section 

and will be reviewed by the 

Administrator for approvability in 

accordance with the other provisions of 

this section, provided that the SO2

allowances issued under such emissions 

trading program shall not, and the SIP 

revision shall state that such SO2

allowances shall not, qualify as CAIR 

SO2 allowances under any emissions 

trading program approved under 

paragraph (o)(1) or (2) of this section. 

(p) If a State’s SIP revision does not 

contain an emissions trading program 

approved under paragraph (o)(1) or (2) 

of this section but contains control 

measures on EGUs as part or all of a 

State’s obligation in meeting its 

requirement under paragraph (a) of this 

section: 

(1) The SIP revision shall provide, for 

each year that the State has such 

25332 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

obligation, for the permanent retirement 

of an amount of Acid Rain allowances 

allocated to sources in the State for that 

year and not deducted by the 

Administrator under the Acid Rain 

Program and any emissions trading 

program approved under paragraph 

(o)(1) or (2) of this section, equal to the 

difference between—

(A) The total amount of Acid Rain 

allowances allocated under the Acid 

Rain Program to the sources in the State 

for that year; and 

(B) If the State’s SIP revision contains 

only control measures on EGUs, the 

State’s Annual EGU SO2 Budget for the 

appropriate period as specified in 

paragraph (e)(2) of this section or, if the 

State’s SIP revision contains control 

measures on EGUs and non-EGUs, the 

State’s Annual EGU SO2 Budget for the 

appropriate period as specified in the 

SIP revision. 

(2) The SIP revision providing for 

permanent retirement of Acid Rain 

allowances under paragraph (p)(1) of 

this section must ensure that such 

allowances are not available for 

deduction by the Administrator under 

the Acid Rain Program and any 

emissions trading program approved 

under paragraph (o)(1) or (2) of this 

section. 

(q) The terms used in this section 

shall have the following meanings: 

Acid Rain allowance means a limited 

authorization issued by the 

Administrator under the Acid Rain 

Program to emit up to one ton of sulfur 

dioxide during the specified year or any 

year thereafter, except as otherwise 

provided by the Administrator. 

Acid Rain Program means a multiState sulfur dioxide and nitrogen oxides 

air pollution control and emissions 

reduction program established by the 

Administrator under title IV of the CAA 

and parts 72 through 78 of this chapter. 

Administrator means the 

Administrator of the United States 

Environmental Protection Agency or the 

Administrator’s duly authorized 

representative. 

Allocate or allocation means, with 

regard to allowances, the determination 

of the amount of allowances to be 

initially credited to a source. 

Boiler means an enclosed fossil- or 

other-fuel-fired combustion device used 

to produce heat and to transfer heat to 

recirculating water, steam, or other 

medium.

Bottoming-cycle cogeneration unit

means a cogeneration unit in which the 

energy input to the unit is first used to 

produce useful thermal energy and at 

least some of the reject heat from the 

useful thermal energy application or 

process is then used for electricity 

production. 

Clean Air Act or CAA means the 

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

Cogeneration unit means a stationary, 

fossil-fuel-fired boiler or stationary, 

fossil-fuel-fired combustion turbine: 

(1) Having equipment used to produce 

electricity and useful thermal energy for 

industrial, commercial, heating, or 

cooling purposes through the sequential 

use of energy; and 

(2) Producing during the 12-month 

period starting on the date the unit first 

produces electricity and during any 

calendar year after which the unit first 

produces electricity—

(i) For a topping-cycle cogeneration 

unit, 

(A) Useful thermal energy not less 

than 5 percent of total energy output; 

and 

(B) Useful power that, when added to 

one-half of useful thermal energy 

produced, is not less then 42.5 percent 

of total energy input, if useful thermal 

energy produced is 15 percent or more 

of total energy output, or not less than 

45 percent of total energy input, if 

useful thermal energy produced is less 

than 15 percent of total energy output. 

(ii) For a bottoming-cycle 

cogeneration unit, useful power not less 

than 45 percent of total energy input. 

Combustion turbine means: 

(1) An enclosed device comprising a 

compressor, a combustor, and a turbine 

and in which the flue gas resulting from 

the combustion of fuel in the combustor 

passes through the turbine, rotating the 

turbine; and 

(2) If the enclosed device under 

paragraph (1) of this definition is 

combined cycle, any associated heat 

recovery steam generator and steam 

turbine. 

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. 

Electric generating unit or EGU

means: 

(1) Except as provided in paragraph 

(2) of this definition, a stationary, fossilfuel-fired boiler or stationary, fossilfuel-fired combustion turbine serving at 

any time, since the start-up of the unit’s 

combustion chamber, a generator with 

nameplate capacity of more than 25 

MWe producing electricity for sale. 

(2) For a unit that qualifies as a 

cogeneration unit during the 12-month 

period starting on the date the unit first 

produces electricity and continues to 

qualify as a cogeneration unit, a 

cogeneration unit serving at any time a 

generator with nameplate capacity of 

more than 25 MWe and supplying in 

any calendar year more than one-third 

of the unit’s potential electric output 

capacity or 219,000 MWh, whichever is 

greater, to any utility power distribution 

system for sale. If a unit qualifies as a 

cogeneration unit during the 12-month 

period starting on the date the unit first 

produces electricity but subsequently no 

longer qualifies as a cogeneration unit, 

the unit shall be subject to paragraph (1) 

of this definition starting on the day on 

which the unit first no longer qualifies 

as a cogeneration unit. 

Fossil fuel means natural gas, 

petroleum, coal, or any form of solid, 

liquid, or gaseous fuel derived from 

such material. 

Fossil-fuel-fired means, with regard to 

a unit, combusting any amount of fossil 

fuel in any calendar year. 

Generator means a device that 

produces electricity. 

Maximum design heat input means: 

(1) Starting from the initial 

installation of a unit, the maximum 

amount of fuel per hour (in Btu/hr) that 

a unit is capable of combusting on a 

steady state basis as specified by the 

manufacturer of the unit; 

(2)(i) Except as provided in paragraph 

(2)(ii) of this definition, starting from 

the completion of any subsequent 

physical change in the unit resulting in 

an increase in the maximum amount of 

fuel per hour (in Btu/hr) that a unit is 

capable of combusting on a steady state 

basis, such increased maximum amount 

as specified by the person conducting 

the physical change; or 

(ii) For purposes of applying the 

definition of the term ‘‘potential 

electrical output capacity,’’ starting from 

the completion of any subsequent 

physical change in the unit resulting in 

a decrease in the maximum amount of 

fuel per hour (in Btu/hr) that a unit is 

capable of combusting on a steady state 

basis, such decreased maximum amount 

as specified by the person conducting 

the physical change. 

NAAQS means National Ambient Air 

Quality Standard. 

Nameplate capacity means, starting 

from the initial installation of a 

generator, the maximum electrical 

generating output (in MWe) that the 

generator is capable of producing on a 

steady state basis and during continuous 

operation (when not restricted by 

seasonal or other deratings) as specified 

by the manufacturer of the generator or, 

starting from the completion of any 

subsequent physical change in the 

generator resulting in an increase in the 

maximum electrical generating output 

(in MWe) that the generator is capable 

of producing on a steady state basis and 

during continuous operation (when not 

restricted by seasonal or other 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25333

deratings), such increased maximum 

amount as specified by the person 

conducting the physical change. 

Non-EGU means a source of SO2

emissions that is not an EGU. 

Potential electrical output capacity

means 33 percent of a unit’s maximum 

design heat input, divided by 3,413 Btu/

kWh, divided by 1,000 kWh/MWh, and 

multiplied by 8,760 hr/yr.

Sequential use of energy means: 

(1) For a topping-cycle cogeneration 

unit, the use of reject heat from 

electricity production in a useful 

thermal energy application or process; 

or 

(2) For a bottoming-cycle cogeneration 

unit, the use of reject heat from useful 

thermal energy application or process in 

electricity production. 

Topping-cycle cogeneration unit

means a cogeneration unit in which the 

energy input to the unit is first used to 

produce useful power, including 

electricity, and at least some of the 

reject heat from the electricity 

production is then used to provide 

useful thermal energy. 

Total energy input means, with regard 

to a cogeneration unit, total energy of all 

forms supplied to the cogeneration unit, 

excluding energy produced by the 

cogeneration unit itself. 

Total energy output means, with 

regard to a cogeneration unit, the sum 

of useful power and useful thermal 

energy produced by the cogeneration 

unit. 

Unit means a stationary, fossil-fuelfired boiler or a stationary, fossil-fuel 

fired combustion turbine. 

Useful power means, with regard to a 

cogeneration unit, electricity or 

mechanical energy made available for 

use, excluding any such energy used in 

the power production process (which 

process includes, but is not limited to, 

any on-site processing or treatment of 

fuel combusted at the unit and any onsite emission controls). 

Useful thermal energy means, with 

regard to a cogeneration unit, thermal 

energy that is: 

(1) Made available to an industrial or 

commercial process, excluding any heat 

contained in condensate return or 

makeup water; 

(2) Used in a heat application (e.g., 

space heating or domestic hot water 

heating); or 

(3) Used in a space cooling 

application (i.e., thermal energy used by 

an absorption chiller). 

Utility power distribution system

means the portion of an electricity grid 

owned or operated by a utility and 

dedicated to delivering electricity to 

customers.

■ 6. Part 51 is amended by adding 

§ 51.125 to Subpart G to read as follows:

§ 51.125 Emissions reporting 

requirements for SIP revisions relating to 

budgets for SO2 and NOX emissions. 

(a) For its transport SIP revision under 

§ 51.123 and/or 51.124, each State must 

submit to EPA SO2 and/or NOX

emissions data as described in this 

section. 

(1) Alabama, Florida, Georgia, Illinois, 

Indiana, Iowa, Kentucky, Louisiana, 

Maryland, Michigan, Minnesota, 

Mississippi, Missouri, New York, North 

Carolina, Ohio, Pennsylvania, South 

Carolina, Tennessee, Texas, Virginia, 

West Virginia, Wisconsin and the 

District of Columbia, must report annual 

(12 months) emissions of SO2 and NOX. 

(2) Alabama, Arkansas, Connecticut, 

Deleware, Florida, Illinois, Indinia, 

Iowa, Kentucky, Lousianna, Maryland, 

Massachusetts, Michigan, Mississippi, 

Missouri, New Jersey, New York, North 

Carolina, Ohio, Pennsylvania, South 

Carolina, Tennessee, Virginia, West 

Virginia, Wisconsin and the District of 

Columbia must report ozone season 

(May 1 through September 30) 

emissions of NOX. 

(b) Each revision must provide for 

periodic reporting by the State of SO2

and/or NOX emissions data as specified 

in paragraph (a) of this section to 

demonstrate whether the State’s 

emissions are consistent with the 

projections contained in its approved 

SIP submission. 

(1) Every-year reporting cycle. As 

applicable, each revision must provide 

for reporting of SO2 and NOX emissions 

data every year as follows: 

(i) The States identified in paragraph 

(a)(1) of this section must report to EPA 

annual emissions data every year from 

all SO2 and NOX sources within the 

State for which the State specified 

control measures in its SIP submission 

under §§ 51.123 and/or 51.124. 

(ii) The States identified in paragraph 

(a)(2) of this section must report to EPA 

ozone season and summer daily 

emissions data every year from all NOX

sources within the State for which the 

State specified control measures in its 

SIP submission under § 51.123. 

(iii) If sources report SO2 and NOX

emissions data to EPA in a given year 

pursuant to a trading program approved 

under § 51.123(o) or § 51.124(o) of this 

part or pursuant to the monitoring and 

reporting requirements of 40 CFR part 

75, then the State need not provide 

annual reporting of these pollutants to 

EPA for such sources. 

(2) Three-year reporting cycle. As 

applicable, each plan must provide for 

triennial (i.e., every third year) reporting 

of SO2 and NOX emissions data from all 

sources within the State. 

(i) The States identified in paragraph 

(a)(1) of this section must report to EPA 

annual emissions data every third year 

from all SO2 and NOX sources within 

the State. 

(ii) The States identified in paragraph 

(a)(2) of this section must report to EPA 

ozone season and ozone daily emissions 

data every third year from all NOX

sources within the State. 

(3) The data availability requirements 

in § 51.116 must be followed for all data 

submitted to meet the requirements of 

paragraphs (b)(1) and (2) of this section.

(c) The data reported in paragraph (b) 

of this section must meet the 

requirements of subpart A of this part. 

(d) Approval of annual and ozone 

season calculation by EPA. Each State 

must submit for EPA approval an 

example of the calculation procedure 

used to calculate annual and ozone 

season emissions along with sufficient 

information for EPA to verify the 

calculated value of annual and ozone 

season emissions. 

(e) Reporting schedules. (1) Reports 

are to begin with data for emissions 

occurring in the year 2008, which is the 

first year of the 3-year cycle. 

(2) After 2008, 3-year cycle reports are 

to be submitted every third year and 

every-year cycle reports are to be 

submitted each year that a triennial 

report is not required. 

(3) States must submit data for a 

required year no later than 17 months 

after the end of the calendar year for 

which the data are collected. 

(f) Data reporting procedures are given 

in subpart A of this part. When 

submitting a formal NOX budget 

emissions report and associated data, 

States shall notify the appropriate EPA 

Regional Office. 

(g) Definitions. (1) As used in this 

section, ‘‘ozone season’’ is defined as 

follows: 

Ozone season.—The five month 

period from May 1 through September 

30. 

(2) Other words and terms shall have 

the meanings set forth in appendix A of 

subpart A of this part.

PART 72—PERMITS REGULATION

■ 1. The authority citation for part 72 

continues to read as follows:

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

§ 72.2 [Amended]

■ 2. Section 72.2 is amended by:

■ a. Amend the definition of ‘‘Acid rain 

emissions limitation’’ by replacing, in 

paragraph (1)(i), the words ‘‘an affected 

unit’’ with the words ‘‘the affected units 

25334 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

at a source’’ and replacing, in paragraph 

(1)(ii)(C), the words ‘‘compliance 

subaccount for that unit’’ with the words 

‘‘compliance account for that source’’;

■ b. Amend the definition of ‘‘Advance 

allowance’’ by replacing the word 

‘‘unit’s’’ with the word ‘‘source’’;

■ c. Amend the definition of ‘‘Allocate or 

allocation’’ by replacing the words ‘‘unit 

account’’ with the words ‘‘compliance 

account’’;

■ d. Amend the definition of ‘‘Allowance 

deduction, or deduct’’ by replacing the 

words ‘‘compliance subaccount, or 

future year subaccount,’’ with the words 

‘‘compliance account’’ and replacing the 

words ‘‘from an affected unit’’ with the 

words ‘‘from the affected units at an 

affected source’’;

■ e. Amend the definition of ‘‘Allowance 

transfer deadline’’ by replacing the 

words ‘‘affected unit’s compliance 

subaccount’’ with the words ‘‘an affected 

source’s compliance account’’ and 

replacing the words ‘‘the unit’s’’ with the 

words ‘‘the source’s’’;

■ f. Amend the definition of ‘‘Authorized 

account representative’’ by replacing the 

words ‘‘unit account’’ with the words 

‘‘compliance account’’ and replacing the 

words ‘‘affected unit’’ with the words 

‘‘affected source and the affected units at 

the source’’;

■ g. Amend the definition of 

‘‘Compliance use date’’ by replacing the 

word ‘‘unit’s’’ with the word ‘‘source’s’’;

■ h. Amend the definition of ‘‘Excess 

emissions’’ by, in paragraph (1), 

replacing the words ‘‘an affected unit’’

with the words ‘‘the affected units at an 

affected source’’ and replacing the words 

‘‘for the unit’’ with the words ‘‘for the 

source’’;

■ i. Amend the definition of ‘‘General 

account’’ by replacing the words ‘‘unit 

account’’ with the words ‘‘compliance 

account’’;

■ j. Amend the definition of ‘‘Offset 

Plan’’ by replacing the word ‘‘unit’’ with 

the word ‘‘source’’;

■ k. Amend the definition of 

‘‘Recordation, record, or recorded’’ by 

removing the words ‘‘or subaccount’’;

■ l. Amend the definition of ‘‘Source’’ by 

replacing the words ‘‘under the Act.’’

with the words ‘‘under the Act, provided 

that one or more combustion or process 

sources that have, under § 74.4(c) of this 

chapter, a different designated 

representative than the designated 

representative for one or more affected 

utility units at a source shall be treated 

as being included in a separate source 

from the source that includes such utility 

units for purposes of parts 72 through 78 

of this chapter, but shall be treated as 

being included in the same source as the 

source that includes such utility units for 

purposes of section 502(c) of the Act.’’

■ m. Amend the definition of ‘‘Spot 

allowance’’ by replacing the word 

‘‘unit’s’’ with the word ‘‘source’s’’; and

■ n. Revise the definition of 

‘‘Cogeneration unit’’;

■ o. Add a new definition of 

‘‘Compliance account’’; and

■ p. Remove the definitions of 

‘‘Compliance subaccount’’, ‘‘Current 

year subaccount’’, ‘‘Direct Sale 

Subaccount’’, ‘‘Future year subaccount’’, 

and ‘‘Unit account’’.

§ 72.2 Definitions.

* * * * *

Cogeneration unit means a unit that 

has equipment used to produce electric 

energy and forms of useful thermal 

energy (such as heat or steam) for 

industrial, commercial, heating, or 

cooling purposes, through sequential 

use of energy.

* * * * *

Compliance account means an 

Allowance Tracking System account, 

established by the Administrator under 

§ 73.31(a) or (b) of this chapter or 

§ 74.40(a) of this chapter for an affected 

source and for each affected unit at the 

source.

* * * * *

§ 72.7 [Amended]

■ 3. Section 72.7 is amended in 

paragraph (c)(1)(ii), in the first sentence, 

by replacing the word ‘‘unit’s Allowance 

Tracking System account’’ with the 

words ‘‘compliance account of the 

source that includes the unit’’, and by 

removing the third sentence of paragraph 

(c)(1)(ii).

§ 72.9 [Amended]

■ 4. Section 72.9 is amended by:

■ a. In paragraph (b)(2), replace the word 

‘‘unit’’ with the words ‘‘source or unit, as 

appropriate,’’;

■ b. In paragraph (c)(1)(i), replace the 

words ‘‘unit’s compliance subaccount’’

with the words ‘‘source’s compliance 

account’’ and replace the words ‘‘from 

the unit’’ with the words ‘‘from the 

affected units at the source’’;

■ c. In paragraphs (e)(1) and (e)(2) 

introductory text, replace the words ‘‘an 

affected unit’’ with the words ‘‘an 

affected source’’;

■ d. In paragraph (g)(6), remove the 

second sentence; and

■ e. In paragraph (h)(2), replace the word 

‘‘unit’’ with the word ‘‘source’’ wherever 

it appears.

§ 72.21 [Amended]

■ 5. Section 72.21 is amended by:

■ a. In paragraph (b)(1), remove the word 

‘‘affected’’ wherever it appears; and

■ b. In paragraph (e)(2), replace the 

words ‘‘unit account’’ with the words 

‘‘compliance account’’.

§ 72.24 [Amended]

■ 6. Section 72.24 is amended by 

removing and reserving paragraphs 

(a)(5), (a)(7), and (a)(10).

§ 72.40 [Amended]

■ 7–8. Section 72.40 is amended, in 

paragraph (a)(1), replace the words 

‘‘unit’s compliance subaccount’’ with 

the words ‘‘compliance account of the 

source where the unit is located’’; 

remove the words ‘‘, or in the compliance 

subaccount of another affected unit at the 

source to the extent provided in 

§ 73.35(b)(3),’’; and replace the words 

‘‘from the unit’’ with the words ‘‘from the 

affected units at the source’’.

§ 72.72 [Amended]

■ 9. Section 72.72 is amended by:

■ a. In paragraph (a)(1), add the words 

‘‘or affected source’’ after the words 

‘‘affected unit’’;

■ b. In paragraph (a)(2), add the words 

‘‘or an affected source’s’’ after the words 

‘‘affected unit’s’’; and

■ c. In paragraph (a)(3), add the words 

‘‘or affected source’’ after the words 

‘‘affected unit’’ whenever they appear.

§ 72.73 [Amended]

■ 10. Section 72.73 is amended in 

paragraph (b)(2) by replacing the words 

‘‘the first Acid Rain permit’’ with the 

words ‘‘an Acid Rain permit’’.

§ 72.90 [Amended]

■ 11. Section 72.90 is amended by, in 

paragraph (a), add, after the words ‘‘each 

calendar year’’, the words ‘‘during 1995 

through 2005’’.

§ 72.95 [Amended]

■ 12. Section 72.95 is amended by:

■ a. In the introductory text, replace the 

words ‘‘an affected unit’s compliance 

subaccount’’ with the words ‘‘an affected 

source’s compliance account’’; and

■ b. In paragraph (a), replace the words 

‘‘by the unit’’ with the words ‘‘by the 

affected units at the source’’.

§ 72.96 [Amended]

■ 13. Section 72.96 is amended in 

paragraph (b), by replacing the words 

‘‘unit’’s Allowance Tracking System 

account’’ with the words ‘‘source’s 

compliance account’’.

PART 73—SULFUR DIOXIDE 

ALLOWANCE SYSTEM

■ 1. The authority citation for part 73 

continues to read as follows:

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

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25335

§ 73.10 [Amended]

■ 2. Section 73.10 is amended by:

■ a. In paragraph (a), replace the words 

‘‘unit account for each’’ with the words 

‘‘compliance account for each source 

that includes a’’ and remove the words 

‘‘in each future year subaccount’’; and

■ b. In paragraphs (b)(1) and (b)(2), 

replace the words ‘‘unit account for 

each’’ with the words ‘‘compliance 

account for each source that includes a’’

and replace the words ‘‘in the future year 

subaccounts representing calendar 

years’’ with the words ‘‘for the years’’.

§ 73.27 [Amended]

■ 3. Section 73.27 is amended in 

paragraphs (c)(3) and (c)(5) by replacing 

the words ‘‘unit’s Allowance Tracking 

System account’’ with the words 

‘‘compliance account of the source that 

includes the unit’’.

§ 73.30 [Amended]

■ 4. Section 73.30 is amended by:

■ a. In paragraph (a), add the word 

‘‘compliance’’ after the word ‘‘establish’’; 

replace the words ‘‘affected units’’ with 

the words ‘‘affected sources’’; and 

replace the words ‘‘unit’s Allowance 

Tracking System account’’ with the 

words ‘‘source’s compliance account’’; 

and

■ b. In paragraph (b), replace the word 

‘‘unit’’ with the word ‘‘source’’ and 

replace the words ‘‘Allowance Tracking 

System account’’ with the words 

‘‘general account’’.

§ 73.31 [Amended]

■ 5. Section 73.31 is amended by:

■ a. In paragraph (a), replace the words 

‘‘an Allowance Tracking System 

account’’ with the words ‘‘a compliance 

account’’ and replace the words ‘‘each 

unit’’ with the words ‘‘each source that 

includes a unit’’;

■ b. In paragraph (b), replace the words 

‘‘an Allowance Tracking System account 

for the unit.’’ with the words ‘‘a 

compliance account for the source that 

includes the unit, unless the source 

already has a compliance account.’’; and

■ c. In paragraph (c)(1)(v), replace the 

words ‘‘Allowance Tracking System 

account’’ with the words ‘‘general 

account’’ and remove the words ‘‘I shall 

abide by any fiduciary responsibilities 

assigned pursuant to the binding 

agreement.’’.

§ 73.32 [Removed and Reserved]

■ 6. Section 73.32 is removed and 

reserved.

§ 73.33 [Amended]

■ 7. Section 73.33 is amended by 

removing and reserving paragraphs (b) 

and (c).

§ 73.34 [Amended]

■ 8. Section 73.34 is amended by:

■ a. Revise paragraphs (a) and (b) to read 

as set forth below;

■ b. In paragraph (c) introductory text, 

remove the paragraph heading and 

replace the words ‘‘compliance, current 

year, and future year’’ with the words 

‘‘compliance account and general 

account’’.

§ 73.34 Recordation in accounts. 

(a) After a compliance account is 

established under § 73.31(a) or (b), the 

Administrator will record in the 

compliance account any allowance 

allocated to any affected unit at the 

source for 30 years starting with the 

later of 1995 or the year in which the 

compliance account is established and 

any allowance allocated for 30 years 

starting with the later of 1995 or the 

year in which the compliance account is 

established and transferred to the source 

with the transfer submitted in 

accordance with § 73.50. In 1996 and 

each year thereafter, after Administrator 

has completed the deductions pursuant 

to § 73.35(b), the Administrator will 

record in the compliance account any 

allowance allocated to any affected unit 

at the source for the new 30th year (i.e., 

the year that is 30 years after the 

calendar year for which such 

deductions are made) and any 

allowance allocated for the new 30th 

year and transferred to the source with 

the transfer submitted in accordance 

with § 73.50. 

(b) After a general account is 

established under § 73.31(c), the 

Administrator will record in the general 

account any allowance allocated for 30 

years starting with the later of 1995 or 

the year in which the general account is 

established and transferred to the 

general account with the transfer 

submitted in accordance with § 73.50. In 

1996 and each year thereafter, after the 

Administrator has completed the 

deductions pursuant to § 73.35(b), the 

Administrator will record in the general 

account any allowance allocated for the 

new 30th year (i.e., the year that is 30 

years after the calendar year for which 

such deductions are made) and 

transferred to the general account with 

the transfer submitted in accordance 

with § 73.50.

* * * * *

§ 73.35 [Amended]

■ 9. Section 73.35 is amended by:

■ a. In paragraph (a) introductory text 

and paragraph (a)(1), replace the words 

‘‘unit’s’’ with the word ‘‘source’s’’;

■ b. In paragraph (a)(2), replace the word 

‘‘Such’’ with the word ‘‘The’’;

■ c. In paragraph (a)(2)(i), replace the 

words ‘‘the unit’s compliance 

subaccount’’ with the words ‘‘the 

source’s compliance account’’;

■ d. In paragraph (a)(2)(ii), replace the 

words ‘‘the unit’s compliance 

subaccount’’ with the words ‘‘the 

source’s compliance account’’, replace 

the words ‘‘compliance subaccount for 

the unit’’ with the words ‘‘source’s 

compliance account’’, and replace the 

word ‘‘or’’ with the word ‘‘and’’;

■ e. Remove paragraph (a)(2)(iii);

■ f. Add a new paragraph (a)(3);

■ g. In paragraph (b)(1), replace the 

words ‘‘compliance subaccount’’ with 

the words ‘‘compliance account’’, add 

the words ‘‘available for deduction 

under paragraph (a) of this section’’ after 

the words ‘‘deduct allowances’’, and 

replace the words ‘‘each affected unit’s 

compliance subaccount’’ with the words 

‘‘each affected source’s compliance 

account’’;

■ h. In paragraph (b)(2), replace the 

words ‘‘allowances remain in the 

compliance subaccount’’ with the words 

‘‘allowances available for deduction 

under paragraph (a) of this section 

remain in the compliance account’’;

■ i. Remove paragraph (b)(3);

■ j. Revise paragraph (c)(1) to read as set 

forth below;

■ k. In paragraph (c)(2), replace the 

words ‘‘for the unit’’ with the words ‘‘for 

the units at the source’’, replace the 

words ‘‘in its compliance subaccount.’’

with the words ‘‘in the source’s 

compliance account.’’, replace the words 

‘‘from the compliance subaccount’’ with 

the words ‘‘from the compliance 

account’’, and replace the words ‘‘unit’s 

compliance subaccount’’ with the words 

‘‘source’s compliance account’’;

■ l. In paragraph (d), replace the words 

‘‘for each unit’’ with the words ‘‘for each 

source’’ and replace the word ‘‘unit’s’’

with the word ‘‘source’s’’; and

■ m. Remove paragraph (e).

§ 73.35 Compliance. 

(a) * * * 

(3) The allowance was not previously 

deducted by the Administrator in 

accordance with a State SO2 mass 

emissions reduction program under 

§ 51.124(o) of this chapter or otherwise 

permanently retired in accordance with 

§ 51.124(p) of this chapter.

* * * * *

(c)(1) Identification of allowances by 

serial number. The authorized account 

representative for a source’s compliance 

account may request that specific 

allowances, identified by serial number, 

in the compliance account be deducted 

for a calendar year in accordance with 

paragraph (b) or (d) of this section. Such 

request shall be submitted to the 

25336 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

Administrator by the allowance transfer 

deadline for the year and include, in a 

format prescribed by the Administrator, 

the identification of the source and the 

appropriate serial numbers.

* * * * *

§ 73.36 [Amended]

■ 10. Section 73.36 is amended by:

■ a. In paragraph (a), replace the words 

‘‘Unit accounts.’’ with the words 

‘‘Compliance accounts.’’ and replace 

with words ‘‘compliance subaccount’’

with the words ‘‘compliance account’’

whenever they appear; and

■ b. In paragraph (b), replace the words 

‘‘current year subaccount’’ with the 

words ‘‘general account’’ whenever they 

appear and replace the words ‘‘at the end 

of the current calendar year’’ with the 

words ‘‘not transferred pursuant to 

subpart D to another Allowance Tracking 

System account’’.

■ 11. Section 73.37 is revised to read as 

follows:

§ 73.37 Account error. 

The Administrator may, at his or her 

sole discretion and on his or her own 

motion, correct any error in any 

Allowance Tracking System account. 

Within 10 business days of making such 

correction, the Administrator will notify 

the authorized account representative 

for the account.

§ 73.38 [Amended]

■ 12. Section 73.38 is amended by:

■ a. In paragraph (a), replace the words 

‘‘delete the general account from the 

Allowance Tracking System.’’ with the 

words ‘‘close the general account.’’; and

■ b. In paragraph (b), replace the words 

‘‘for a period of a year or more’’ with the 

words ‘‘for a 12-month period or longer’’; 

remove the words ‘‘in its subaccounts’’; 

replace the words ‘‘will notify’’ with the 

words ‘‘may notify’’; remove the words 

‘‘and eliminated from the Allowance 

Tracking System’’; and remove the last 

sentence.

§ 73.50 [Amended]

■ 13. Section 73.50 is amended by:

■ a. In paragraph (a), remove the words 

‘‘, including, but not limited to, transfers 

of an allowance to and from 

contemporaneous future year 

subaccounts, and transfers of an 

allowance to and from compliance 

subaccounts and current year 

subaccounts, and transfers of all 

allowances allocated for a unit for each 

calendar year in perpetuity’’;

■ b. In paragraph (b)(1)(ii), remove the 

words ‘‘, or correct indication on the 

allowance transfer where a request 

involves the transfer of the unit’s 

allowance in perpetuity’’;

■ c. In paragraph (b)(2)(ii), remove the 

words ‘‘Allowance Tracking System’’

and ‘‘under 40 CFR part 73, or any other 

remedies’’ and remove the comma after 

the words ‘‘under State or Federal law’’; 

and

■ d. Remove paragraph (b)(3).

§ 73.51 [Removed and Reserved]

■ 14. Section 73.51 is removed and 

reserved.

§ 73.52 [Amended]

■ 15. Section 73.52 is amended by:

■ a. In paragraph (a) introductory text, 

remove the words ‘‘§ 73.50, § 73.51, and’’

and add the words ‘‘(or longer as 

necessary to perform a transfer in 

perpetuity of allowances allocated to a 

unit)’’ after the words ‘‘five business 

days’’;

■ b. Revise paragraphs (a)(1), (a)(2) and 

(a)(3);

■ c. Remove paragraph (a)(4);

■ d. Revise paragraph (b); and

■ e. Add a new paragraph (c) to read as 

follows:

§ 73.52 EPA recordation. 

(a) * * *

(1) The transfer is correctly submitted 

under § 73.50; 

(2) The transferor account includes 

each allowance identified by serial 

number in the transfer; and 

(3) If the allowances identified by 

serial number specified pursuant to 

§ 73.50(b)(1)(ii) are subject to the 

limitation on transfer imposed pursuant 

to § 72.44(h)(1)(i) of this chapter, § 74.42 

of this chapter, or § 74.47(c) of this 

chapter, the transfer is in accordance 

with such limitation. 

(b) To the extent an allowance transfer 

submitted for recordation after the 

allowance transfer deadline includes 

allowances allocated for any year before 

the year in which the allowance transfer 

deadline occurs, the transfer of such 

allowance will not be recorded until 

after completion of the deductions 

pursuant to § 73.35(b) for year before the 

year in which the allowance transfer 

deadline occurs. 

(c) Where an allowance transfer 

submitted for recordation fails to meet 

the requirements of paragraph (a) of this 

section, the Administrator will not 

record such transfer.

§ 73.70 [Amended]

■ 16. Section 73.70 is amended by:

■ a. In paragraph (e), remove the last two 

sentences.

■ b. In paragraph (f), replace the words 

‘‘the subaccount’’ by the words ‘‘the 

Allowance Tracking System account’’; 

and

■ c. In paragraph (i)(1), add the words 

‘‘source that includes a’’ after the words 

‘‘Allowance Tracking System account of 

each’’.

PART 74—SULFUR DIOXIDE OPT-INS

■ 1. The authority citation for part 74 

continues to read as follows:

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

§ 74.4 [Amended]

■ 2. Section 74.4 is amended by:

■ a. In paragraph (c)(1), replace the 

words ‘‘a combustion or process source 

that is located’’ with the words ‘‘one or 

more combustion or process sources that 

are located’’, replace the words ‘‘such 

combustion or process source and 

thereafter, does’’ with the words ‘‘such 

combustion or process sources and 

thereafter, do’’, and replace the words 

‘‘designate, for such combustion or 

process source’’ with the words 

‘‘designate, for such combustion or 

process sources’’; and

■ b. In paragraph (c)(2), replace the 

words ‘‘the combustion or process 

source’’ with the words ‘‘the combustion 

or process sources’’ whenever they occur 

and replace the word ‘‘meets’’ with the 

word ‘‘meet’’ in the first sentence.

§ 74.18 [Amended]

■ 3. Section 74.18 is amended in 

paragraph (d) by removing the last 

sentence.

§ 74.40 [Amended]

■ 4. Section 74.40 is amended by:

■ a. In paragraph (a), replace the words 

‘‘an opt-in account’’ with the words ‘‘a 

compliance account’’, replace the words 

‘‘an account’’ with the words ‘‘a 

compliance account (unless the source 

that includes the opt-in source already 

has a compliance account or the opt-in 

source has, under § 74.4(c), a different 

designated representative than the 

designated representative for the 

source)’’, and remove the last sentence.

■ b. In paragraph (b), replace the words 

‘‘allowance account in the Allowance 

Tracking System’’ with the words 

‘‘compliance account (unless the source 

that includes the opt-in source already 

has a compliance account or the opt-in 

source has, under § 74.4(c), a different 

designated representative than the 

designated representative for the 

source)’’.

■ 5. Section 74.42 is revised to read as 

follows:

§ 74.42 Limitation on transfers. 

(a) With regard to a transfer request 

submitted for recordation during the 

period starting January 1 and ending 

with the allowance transfer deadline in 

the same year, the Administrator will 

not record a transfer of an opt-in 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25337

allowance that is allocated to an opt-in 

source for the year in which the transfer 

request is submitted or a subsequent 

year. 

(b) With regard to a transfer request 

during the period starting with the day 

after an allowance transfer deadline and 

ending December 31 in the same year, 

the Administrator will not record a 

transfer of an opt-in allowance that is 

allocated to an opt-in source for a year 

after the year in which the transfer 

request is submitted.

§ 74.43 [Amended]

■ 6. Section 74.43 is amended by:

■ a. In paragraph (a), remove the words 

‘‘in lieu of any annual compliance 

certification report required under 

subpart I of part 72 of this chapter’’;

■ b. In paragraph (b)(7), replace the word 

‘‘At’’ with the words, ‘‘In an annual 

compliance certification report for a year 

during 1995 through 2005, at’’; and

■ c. In paragraph (b)(8), replace the word 

‘‘The’’ with the words, ‘‘In an annual 

compliance certification report for a year 

during 1995 through 2005, the’’.

§ 74.44 [Amended]

■ 7. Section 74.44 is amended by:

■ a. In paragraph (c)(1)(ii), remove the 

words ‘‘opt-in source’s’’ and add the 

words ‘‘of the source that includes the 

opt-in source’’ after the word ‘‘System’’;

■ b. In paragraphs (c)(2)(iii)(C), 

(c)(2)(iii)(D), (c)(2)(iii)(E) introductory 

text, and (c)(2)(iii)(E)(3), replace the 

words ‘‘opt-in source’s compliance 

subaccount’’ with the words 

‘‘compliance account of the source that 

includes the opt-in source’’ whenever 

they occur; and

■ c. In paragraph (c)(2)(iii)(F), replace 

the words ‘‘opt-in source’s compliance 

subaccount’’ with the words 

‘‘compliance account of the source that 

includes the opt-in source’’ and replace 

the words ‘‘source’s compliance 

subaccount’’ with the words 

‘‘compliance account of the source that 

includes the opt-in source’’.

§ 74.46 [Amended]

■ 8. Section 74.46 is amended by 

removing and reserving paragraph (b)(2).

§ 74.47 [Amended]

■ 9. Section 74.47 is amended by:

■ a. In paragraph (a)(3)(iv), remove the 

words ‘‘opt-in source’s’’ and add the 

words ‘‘of the source that includes the 

opt-in source’’ after the word ‘‘System’’;

■ b. In paragraph (a)(3)(v), replace the 

word ‘‘Each’’ with the word ‘‘The’’, 

remove the words ‘‘replacement unit’s’’

and ‘‘(ATS)’’, and add the words ‘‘of each 

source that includes a replacement unit’’

after the word ‘‘System’’;

■ c. In paragraph (a)(6), replace the 

words ‘‘Allowance Tracking System 

account of each replacement unit’’ with 

the words ‘‘compliance account of each 

source that includes a replacement 

unit’’;

■ d. In paragraph (c), replace the words 

‘‘unit account’’ with the words 

‘‘compliance account of the source that 

includes the replacement unit’’ and 

replace the words ‘‘account in the 

Allowance Tracking System’’ with the 

words ‘‘Allowance Tracking System 

account’’;

■ e. In paragraph (d)(1)(ii)(C), remove the 

words ‘‘opt-in source’s’’ and ‘‘(ATS)’’

and add the words ‘‘of the source that 

includes the opt-in source’’ after the 

word ‘‘System’’;

■ f. In paragraph (d)(1)(ii)(D), replace the 

words ‘‘(ATS) for each’’ with the words 

‘‘of each source that includes a’’;

■ g. In paragraph (d)(2)(i), replace the 

words ‘‘Allowance Tracking System 

accounts for the opt-in source and for 

each replacement unit’’ with the words 

‘‘compliance account for each source 

that includes the opt-in source or a 

replacement unit’’;

■ h. In paragraph (d)(2)(i)(B), replace the 

words ‘‘Allowance Tracking System 

account of the opt-in source’’ with the 

words ‘‘compliance account of the 

source that includes the opt-in source’’; 

and

■ i. In paragraph (d)(2)(ii), replace the 

words ‘‘Allowance Tracking System 

accounts for the opt-in source and for 

each replacement unit’’ with the words 

‘‘compliance account for each source 

that includes the opt-in source or a 

replacement unit’’.

§ 74.49 [Amended]

■ 10. Section 74.49 is amended, in 

paragraph (a) introductory text, by 

replacing the words ‘‘an opt-in source’s 

compliance subaccount’’ with the words 

‘‘the compliance account of a source that 

includes an opt-in source’’.

§ 74.50 [Amended]

■ 11. Section 74.50 is amended by:

■ a. In paragraph (a)(2) introductory text, 

add the words ‘‘source that includes’’

after the words ‘‘the account of the’’;

■ b. In paragraph (a)(2)(i), replace the 

words ‘‘opt-in source’s compliance 

subaccount’’ with the words ‘‘the 

compliance account of the source that 

includes the opt-in source’’; and

■ c. In paragraph (b), replace the words 

‘‘the opt-in source’s unit account’’ with 

the words ‘‘the compliance account of 

the source that includes the opt-in 

source’’; and

■ d. In paragraph (d), replace the words 

‘‘an opt-in source does not hold’’ with 

the words ‘‘the source that includes the 

opt-in source does not hold’’.

PART 77—EXCESS EMISSIONS

■ 1. The authority citation for part 77 

continues to read as follows:

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

§ 77.3 [Amended]

■ 2. Section 77.3 is amended by:

■ a. In paragraph (a), replace the words 

‘‘affected unit’’ with the words ‘‘affected 

source’’ and replace the word ‘‘unit’s 

Allowance Tracking System account’’

with the words ‘‘source’s compliance 

account’’;

■ b. In paragraphs (b) and (c), replace the 

word ‘‘unit’’ with the word ‘‘source’’

wherever it appears; and

■ c. In paragraph (d) introductory text 

and paragraphs (d)(1) and (d)(2), replace 

the word ‘‘unit’’ with the word ‘‘source’’

whenever it appears;

■ d. In paragraphs (d)(3) and (d)(4), 

replace the words ‘‘unit’s Allowance 

Tracking System account’’ with the 

words ‘‘source’s compliance account’s’’

whenever they appear; and

■ e. In paragraph (d)(5), replace the 

words ‘‘unit’s compliance subaccount’’

with the words ‘‘source’s compliance 

account’’.

§ 77.4 [Amended]

■ 3. Section 77.4 is amended by:

■ a. In paragraph (b)(1), replace the 

words ‘‘unit’s compliance subaccount’’

with the words ‘‘source’s compliance 

account’’; and

■ b. In paragraphs (c)(1)(ii)(A), (d)(1), 

(d)(2), (d)(3), (e)(iv), (g)(2)(ii), (g)(3)(ii), 

and (g)(3)(iii), replace the word ‘‘unit’’

with the word ‘‘source’’; and

■ c. In paragraph (k)(2), replace the 

words ‘‘unit’s compliance subaccount’’

with the words ‘‘source’s compliance 

account’’ and replace the word ‘‘unit’’

with the word ‘‘source’’.

§ 77.5 [Amended]

■ 4. Section 77.5 is amended by:

■ a. In paragraph (b), replace the words 

‘‘compliance subaccount’’ with the 

words ‘‘compliance account’’;

■ b. In paragraph (c), replace the words 

‘‘, from the unit’s compliance 

subaccount’’ with the words ‘‘allocated 

for the year after the year in which the 

source has excess emissions, from the 

source’s compliance account’’, and 

replace the word ‘‘unit’s’’ with the word 

‘‘source’s’’; and

■ c. Remove paragraph (d).

§ 77.6 [Amended]

■ 5. Section 77.6 is amended by:

■ a. In paragraph (a)(1), add the words 

‘‘occur at the affected source’’ after the 

25338 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

words ‘‘sulfur dioxide’’ and replace the 

words ‘‘owners and operators of the 

affected unit’’ with the words ‘‘owners 

and operators respectively of the affected 

source and the affected units at the 

source or of the affected unit’’;

■ b. In paragraph (b)(1)(i)(A), replace the 

word ‘‘unit’’ with the words ‘‘source or 

unit as appropriate’’; and

■ c. In paragraphs (b)(3),(c), and (f), 

replace the word ‘‘unit’’ with the words 

‘‘source or unit as appropriate’’.

PART 78—APPEAL PROCEDURES

■ 1. The title of part 78 is revised to read 

as set forth above.

■ 2. The authority citation for part 78 

continues to read as follows:

Authority: 42 U.S.C. 7401, 7403, 7410, 

7426, 7601, and 7651, et seq.

§ 78.1 [Amended]

■ 3. Section 78.1 is amended by:

■ a. In paragraph (a)(1), replace the 

words ‘‘parts 72, 73, 74, 75, 76, or 77 of 

this chapter or part 97 of this chapter’’

with the words ‘‘part 72, 73, 74, 75, 76, 

or 77 of this chapter, subparts AA 

through II of part 96 of this chapter, 

subparts AAA through III of part 96 of 

this chapter, and subparts AAAA 

through subparts IIII of part 96 of this 

chapter, or part 97 of this chapter’’;

■ b. Revise paragraph (b)(2)(i);

■ c. Add new paragraphs (b)(7), (b)(8), 

and (b)(9) to read as follows:

§ 78.1 Purpose and scope.

* * * * *

(b) * * *

(2) * * *

(i) The correction of an error in an 

Allowance Tracking System account;

* * * * *

(7) Under subparts AA through II of 

part 96 of this chapter, 

(i) The decision on the allocation of 

CAIR NOX allowances under 

§ 96.141(b)(2) or (c)(2) of this chapter. 

(ii) The decision on the deduction of 

CAIR NOX allowances, and the 

adjustment of the information in a 

submission and the decision on the 

deduction or transfer of CAIR NOX

allowances based on the information as 

adjusted, under § 96.154 of this chapter; 

(iii) The correction of an error in a 

CAIR NOX Allowance Tracking System 

account under § 96.156 of this chapter; 

(iv) The decision on the transfer of 

CAIR NOX allowances under § 96.161 of 

this chapter; 

(v) The finalization of control period 

emissions data, including retroactive 

adjustment based on audit; 

(vi) The approval or disapproval of a 

petition under § 96.175 of this chapter. 

(8) Under subparts AAA through III of 

part 96 of this chapter, 

(i) The decision on the deduction of 

CAIR SO2 allowances, and the 

adjustment of the information in a 

submission and the decision on the 

deduction or transfer of CAIR SO2

allowances based on the information as 

adjusted, under § 96.254 of this chapter; 

(ii) The correction of an error in a 

CAIR SO2 Allowance Tracking System 

account under § 97.256 of this chapter; 

(iii) The decision on the transfer of 

CAIR SO2 allowances under § 96.261 of 

this chapter; 

(iv) The finalization of control period 

emissions data, including retroactive 

adjustment based on audit; 

(v) The approval or disapproval of a 

petition under § 96.275 of this chapter. 

(9) Under subparts AAAA through IIII 

of part 96 of this chapter, 

(i) The decision on the allocation of 

CAIR NOX Ozone Season allowances 

under § 96.341(b)(2) or (c)(2)of this 

chapter. 

(ii) The decision on the deduction of 

CAIR NOX Ozone Season allowances, 

and the adjustment of the information in 

a submission and the decision on the 

deduction or transfer of CAIR NOX

Ozone Season allowances based on the 

information as adjusted, under § 96.354 

of this chapter; 

(iii) The correction of an error in a 

CAIR NOX Ozone Season Allowance 

Tracking System account under § 96.356 

of this chapter; 

(iv) The decision on the transfer of 

CAIR NOX Ozone Season allowances 

under § 96.361; 

(v) The finalization of control period 

emissions data, including retroactive 

adjustment based on audit; 

(vi) The approval or disapproval of a 

petition under § 96.375 of this chapter.

* * * * *

§ 78.3 [Amended]

■ 4. Section 78.3 is amended by:

■ a. In paragraph (b)(3)(i), add the words 

‘‘or the CAIR designated representative 

or CAIR authorized account 

representative under paragraph (a)(4), 

(5), or (6) of this section (unless the CAIR 

designated representative or CAIR 

authorized account representative is the 

petitioner)’’ after the words ‘‘(unless the 

NOX authorized account representative 

is the petitioner)’’;

■ b. In paragraph (c)(7), replace the 

words ‘‘or part 97 of this chapter, as 

appropriate’’ with the words ‘‘, subparts 

AA through II of part 96 of this chapter, 

subparts AAA through III of part 96 of 

this chapter, subparts AAAA through IIII 

of part 96 of this chapter, or part 97 of 

this chapter, as appropriate’’;

■ c. In paragraph (d)(3), add the words 

‘‘or on an account certificate of 

representation submitted by a CAIR 

designated representative or an 

application for a general account 

submitted by a CAIR authorized account 

representative under subparts AA 

through II, subparts AAA through III, or 

subparts AAAA through IIII of part 96 of 

this chapter’’ after the words ‘‘under the 

NOX Budget Trading Program’’;

■ d. Add new paragraphs (a)(4), (a)(5), 

(a)(6), (d)(5), (d)(6), and (d)(7) to read as 

follows:

§ 78.3 Petition for administrative review 

and request for evidentiary hearing. 

(a) * * *

(4) The following persons may 

petition for administrative review of a 

decision of the Administrator that is 

made under subparts AA through II of 

part 96 of this chapter and that is 

appealable under § 78.1(a): 

(i) The CAIR designated 

representative for a unit or source, or 

the CAIR authorized account 

representative for any CAIR NOX

Allowance Tracking System account, 

covered by the decision; or 

(ii) Any interested person. 

(5) The following persons may 

petition for administrative review of a 

decision of the Administrator that is 

made under subparts AAA through III of 

part 96 of this chapter and that is 

appealable under § 78.1(a): 

(i) The CAIR designated 

representative for a unit or source, or 

the CAIR authorized account 

representative for any CAIR SO2

Allowance Tracking System account, 

covered by the decision; or

(ii) Any interested person. 

(6) The following persons may 

petition for administrative review of a 

decision of the Administrator that is 

made under subparts AAAA through IIII 

of part 96 of this chapter and that is 

appealable under § 78.1(a): 

(i) The CAIR designated 

representative for a unit or source, or 

the CAIR authorized account 

representative for any CAIR Ozone 

Season NOX Allowance Tracking 

System account, covered by the 

decision; or 

(ii) Any interested person.

* * * * *

(d) * * * 

(5) Any provision or requirement of 

subparts AA through II of part 96 of this 

chapter, including the standard 

requirements under § 96.106 of this 

chapter and any emission monitoring or 

reporting requirements. 

(6) Any provision or requirement of 

subparts AAA through III of part 96 of 

this chapter, including the standard 

requirements under § 96.206 of this 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25339

chapter and any emission monitoring or 

reporting requirements. 

(7) Any provision or requirement of 

subparts AAAA through IIII of part 96 

of this chapter, including the standard 

requirements under § 96.306 of this 

chapter and any emission monitoring or 

reporting requirements.

§ 78.4 [Amended]

■ 5. Section 78.4 is amended by adding 

two new sentences after the fifth 

sentence in paragraph (a) to read as 

follows:

§ 78.4 Filings. 

(a) * * * Any filings on behalf of 

owners and operators of a CAIR NOX, 

SO2, or NOX Ozone Season unit or 

source shall be signed by the CAIR 

designated representative. Any filings 

on behalf of persons with an interest in 

CAIR NOX allowances, CAIR SO2

allowances, or CAIR NOX Ozone Season 

allowances in a general account shall be 

signed by the CAIR authorized account 

representative. * * *

* * * * *

§ 78.5 [Amended]

■ 6. Section 78.5 is amended, in 

paragraph (a), by removing the words ‘‘, 

or a claim or error notification was 

submitted,’’ the words ‘‘or in the claim 

of error notification’’, and the words ‘‘or 

the period for submitting a claim of error 

notification’’.

§ 78.12 [Amended]

■ 7. Section 78.12 is amended by:

■ a. In paragraph (a) introductory text, 

remove the words ‘‘, or to submit a claim 

of error notification’’; and

■ b. In paragraph (a)(2), replace the 

words ‘‘NOX Budget permit’’ with the 

words ‘‘, NOX Budget permit, CAIR 

permit,’’.

§ 78.13 [Amended]

■ 8. Section 78.13 is amended by, in 

paragraph (b), removing the word ‘‘also’’.

PART 96—[AMENDED]

■ 1. Authority citation for Part 96 is 

revised to read as follows:

Authority: 42 U.S.C. 7401, 7403, 7410, 

7601, and 7651, et seq.

■ 2. Part 96 is amended by adding 

subparts AA through II, to read as 

follows:

Subpart AA—CAIR NOX Annual Trading 

Program General Provisions 

Sec. 

96.101 Purpose. 

96.102 Definitions. 

96.103 Measurements, abbreviations, and 

acronyms. 

96.104 Applicability. 

96.105 Retired unit exemption. 

96.106 Standard requirements. 

96.107 Computation of time. 

96.108 Appeal procedures.

Subpart BB—CAIR Designated 

Representative for CAIR NOX Sources 

96.110 Authorization and responsibilities of 

CAIR designated representative. 

96.111 Alternate CAIR designated 

representative. 

96.112 Changing CAIR designated 

representative and alternate CAIR 

designated representative; changes in 

owners and operators.

96.113 Certificate of representation. 

96.114 Objections concerning CAIR 

designated representative.

Subpart CC—Permits 

96.120 General CAIR NOX Annual Trading 

Program permit requirements. 

96.121 Submission of CAIR permit 

applications. 

96.122 Information requirements for CAIR 

permit applications. 

96.123 CAIR permit contents and term. 

96.124 CAIR permit revisions.

Subpart DD—[Reserved]

Subpart EE—CAIR NOX Allowance 

Allocations 

96.140 State trading budgets. 

96.141 Timing requirements for CAIR NOX

allowance allocations. 

96.142 CAIR NOX allowance allocations. 

96.143 Compliance supplement pool.

Subpart FF—CAIR NOX Allowance Tracking 

System 

96.150 [Reserved] 

96.151 Establishment of accounts. 

96.152 Responsibilities of CAIR authorized 

account representative. 

96.153 Recordation of CAIR NOX allowance 

allocations. 

96.154 Compliance with CAIR NOX

emissions limitation. 

96.155 Banking. 

96.156 Account error. 

96.157 Closing of general accounts.

Subpart GG—CAIR NOX Allowance 

Transfers 

96.160 Submission of CAIR NOX allowance 

transfers. 

96.161 EPA recordation. 

96.162 Notification.

Subpart HH—Monitoring and Reporting 

96.170 General requirements. 

96.171 Initial certification and 

recertification procedures. 

96.172 Out of control periods. 

96.173 Notifications. 

96.174 Recordkeeping and reporting. 

96.175 Petitions. 

96.176 Additional requirements to provide 

heat input data.

Subpart II—CAIR NOX Opt-in Units 

96.180 Applicability. 

96.181 General. 

96.182 CAIR designated representative. 

96.183 Applying for CAIR opt-in permit. 

96.184 Opt-in process. 

96.185 CAIR opt-in permit contents. 

96.186 Withdrawal from CAIR NOX Annual 

Trading Program. 

96.187 Change in regulatory status. 

96.188 NOX allowance allocations to CAIR 

NOX opt-in units.

Subpart AA—CAIR NOX Annual 

Trading Program General Provisions

§ 96.101 Purpose. 

This subpart and subparts BB through 

II establish the model rule comprising 

general provisions and the designated 

representative, permitting, allowance, 

monitoring, and opt-in provisions for 

the State Clean Air Interstate Rule 

(CAIR) NOX Annual Trading Program, 

under section 110 of the Clean Air Act 

and § 51.123 of this chapter, as a means 

of mitigating interstate transport of fine 

particulates and nitrogen oxides. The 

owner or operator of a unit or a source 

shall comply with the requirements of 

this subpart and subparts BB through II 

as a matter of federal law only if the 

State with jurisdiction over the unit and 

the source incorporates by reference 

such subparts or otherwise adopts the 

requirements of such subparts in 

accordance with § 51.123(o)(1) or (2) of 

this chapter, the State submits to the 

Administrator one or more revisions of 

the State implementation plan that 

include such adoption, and the 

Administrator approves such revisions. 

If the State adopts the requirements of 

such subparts in accordance with 

§ 51.123(o)(1) or (2) of this chapter, then 

the State authorizes the Administrator 

to assist the State in implementing the 

CAIR NOX Annual Trading Program by 

carrying out the functions set forth for 

the Administrator in such subparts.

§ 96.102 Definitions. 

The terms used in this subpart and 

subparts BB through II shall have the 

meanings set forth in this section as 

follows: 

Account number means the 

identification number given by the 

Administrator to each CAIR NOX

Allowance Tracking System account. 

Acid Rain emissions limitation means 

a limitation on emissions of sulfur 

dioxide or nitrogen oxides under the 

Acid Rain Program. 

Acid Rain Program means a multistate sulfur dioxide and nitrogen oxides 

air pollution control and emission 

reduction program established by the 

Administrator under title IV of the CAA 

and parts 72 through 78 of this chapter. 

Administrator means the 

Administrator of the United States 

Environmental Protection Agency or the 

Administrator’s duly authorized 

representative. 

25340 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

Allocate or allocation means, with 

regard to CAIR NOX allowances issued 

under subpart EE, the determination by 

the permitting authority or the 

Administrator of the amount of such 

CAIR NOX allowances to be initially 

credited to a CAIR NOX unit or a new 

unit set-aside and, with regard to CAIR 

NOX allowances issued under § 96.188, 

the determination by the permitting 

authority of the amount of such CAIR 

NOX allowances to be initially credited 

to a CAIR NOX unit. 

Allowance transfer deadline means, 

for a control period, midnight of March 

1, if it is a business day, or, if March 1 

is not a business day, midnight of the 

first business day thereafter 

immediately following the control 

period and is the deadline by which a 

CAIR NOX allowance transfer must be 

submitted for recordation in a CAIR 

NOX source’s compliance account in 

order to be used to meet the source’s 

CAIR NOX emissions limitation for such 

control period in accordance with 

§ 96.154. 

Alternate CAIR designated 

representative means, for a CAIR NOX

source and each CAIR NOX unit at the 

source, the natural person who is 

authorized by the owners and operators 

of the source and all such units at the 

source in accordance with subparts BB 

and II of this part, to act on behalf of the 

CAIR designated representative in 

matters pertaining to the CAIR NOX

Annual Trading Program. If the CAIR 

NOX source is also a CAIR SO2 source, 

then this natural person shall be the 

same person as the alternate CAIR 

designated representative under the 

CAIR SO2 Trading Program. If the CAIR 

NOX source is also a CAIR NOX Ozone 

Season source, then this natural person 

shall be the same person as the alternate 

CAIR designated representative under 

the CAIR NOX Ozone Season Trading 

Program. If the CAIR NOX source is also 

subject to the Acid Rain Program, then 

this natural person shall be the same 

person as the alternate designated 

representative under the Acid Rain 

Program. 

Automated data acquisition and 

handling system or DAHS means that 

component of the continuous emission 

monitoring system, or other emissions 

monitoring system approved for use 

under subpart HH of this part, designed 

to interpret and convert individual 

output signals from pollutant 

concentration monitors, flow monitors, 

diluent gas monitors, and other 

component parts of the monitoring 

system to produce a continuous record 

of the measured parameters in the 

measurement units required by subpart 

HH of this part. 

Boiler means an enclosed fossil- or 

other-fuel-fired combustion device used 

to produce heat and to transfer heat to 

recirculating water, steam, or other 

medium. 

Bottoming-cycle cogeneration unit

means a cogeneration unit in which the 

energy input to the unit is first used to 

produce useful thermal energy and at 

least some of the reject heat from the 

useful thermal energy application or 

process is then used for electricity 

production. 

CAIR authorized account 

representative means, with regard to a 

general account, a responsible natural 

person who is authorized, in accordance 

with subparts BB and II of this part, to 

transfer and otherwise dispose of CAIR 

NOX allowances held in the general 

account and, with regard to a 

compliance account, the CAIR 

designated representative of the source. 

CAIR designated representative

means, for a CAIR NOX source and each 

CAIR NOX unit at the source, the natural 

person who is authorized by the owners 

and operators of the source and all such 

units at the source, in accordance with 

subparts BB and II of this part, to 

represent and legally bind each owner 

and operator in matters pertaining to the 

CAIR NOX Annual Trading Program. If 

the CAIR NOX source is also a CAIR SO2

source, then this natural person shall be 

the same person as the CAIR designated 

representative under the CAIR SO2

Trading Program. If the CAIR NOX

source is also a CAIR NOX Ozone 

Season source, then this natural person 

shall be the same person as the CAIR 

designated representative under the 

CAIR NOX Ozone Season Trading 

Program. If the CAIR NOX source is also 

subject to the Acid Rain Program, then 

this natural person shall be the same 

person as the designated representative 

under the Acid Rain Program. 

CAIR NOX allowance means a limited 

authorization issued by the permitting 

authority under subpart EE of this part 

or § 96.188 to emit one ton of nitrogen 

oxides during a control period of the 

specified calendar year for which the 

authorization is allocated or of any 

calendar year thereafter under the CAIR 

NOX Program. An authorization to emit 

nitrogen oxides that is not issued under 

provisions of a State implementation 

plan that are approved under 

§ 51.123(o)(1) or (2) of this chapter shall 

not be a CAIR NOX allowance. 

CAIR NOX allowance deduction or 

deduct CAIR NOX allowances means the 

permanent withdrawal of CAIR NOX

allowances by the Administrator from a 

compliance account in order to account 

for a specified number of tons of total 

nitrogen oxides emissions from all CAIR 

NOX units at a CAIR NOX source for a 

control period, determined in 

accordance with subpart HH of this part, 

or to account for excess emissions.

CAIR NOX Allowance Tracking 

System means the system by which the 

Administrator records allocations, 

deductions, and transfers of CAIR NOX

allowances under the CAIR NOX Annual 

Trading Program. Such allowances will 

be allocated, held, deducted, or 

transferred only as whole allowances. 

CAIR NOX Allowance Tracking 

System account means an account in the 

CAIR NOX Allowance Tracking System 

established by the Administrator for 

purposes of recording the allocation, 

holding, transferring, or deducting of 

CAIR NOX allowances. 

CAIR NOX allowances held or hold 

CAIR NOX allowances means the CAIR 

NOX allowances recorded by the 

Administrator, or submitted to the 

Administrator for recordation, in 

accordance with subparts FF, GG, and II 

of this part, in a CAIR NOX Allowance 

Tracking System account. 

CAIR NOX Annual Trading Program

means a multi-state nitrogen oxides air 

pollution control and emission 

reduction program approved and 

administered by the Administrator in 

accordance with subparts AA through II 

of this part and § 51.123 of this chapter, 

as a means of mitigating interstate 

transport of fine particulates and 

nitrogen oxides. 

CAIR NOX emissions limitation

means, for a CAIR NOX source, the 

tonnage equivalent of the CAIR NOX

allowances available for deduction for 

the source under § 96.154(a) and (b) for 

a control period. 

CAIR NOX Ozone Season source

means a source that includes one or 

more CAIR NOX Ozone Season units. 

CAIR NOX Ozone Season Trading 

Program means a multi-state nitrogen 

oxides air pollution control and 

emission reduction program approved 

and administered by the Administrator 

in accordance with subparts AAAA 

through IIII of this part and § 51.123 of 

this chapter, as a means of mitigating 

interstate transport of ozone and 

nitrogen oxides. 

CAIR NOX Ozone Season unit means 

a unit that is subject to the CAIR NOX

Ozone Season Trading Program under 

§ 96.304 and a CAIR NOX Ozone Season 

opt-in unit under subpart IIII of this 

part. 

CAIR NOX source means a source that 

includes one or more CAIR NOX units. 

CAIR NOX unit means a unit that is 

subject to the CAIR NOX Annual 

Trading Program under § 96.104 and, 

except for purposes of § 96.105 and 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25341

subpart EE of this part, a CAIR NOX optin unit under subpart II of this part. 

CAIR permit means the legally 

binding and federally enforceable 

written document, or portion of such 

document, issued by the permitting 

authority under subpart CC of this part, 

including any permit revisions, 

specifying the CAIR NOX Annual 

Trading Program requirements 

applicable to a CAIR NOX source, to 

each CAIR NOX unit at the source, and 

to the owners and operators and the 

CAIR designated representative of the 

source and each such unit. 

CAIR SO2 source means a source that 

includes one or more CAIR SO2 units. 

CAIR SO2 Trading Program means a 

multi-state sulfur dioxide air pollution 

control and emission reduction program 

approved and administered by the 

Administrator in accordance with 

subparts AAA through III of this part 

and § 51.124 of this chapter, as a means 

of mitigating interstate transport of fine 

particulates and sulfur dioxide. 

CAIR SO2 unit means a unit that is 

subject to the CAIR SO2 Trading 

Program under § 96.204 and a CAIR SO2

opt-in unit under subpart III of this part. 

Clean Air Act or CAA means the 

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

Coal means any solid fuel classified as 

anthracite, bituminous, subbituminous, 

or lignite. 

Coal-derived fuel means any fuel 

(whether in a solid, liquid, or gaseous 

state) produced by the mechanical, 

thermal, or chemical processing of coal. 

Coal-fired means:

(1) Except for purposes of subpart EE 

of this part, combusting any amount of 

coal or coal-derived fuel, alone or in 

combination with any amount of any 

other fuel, during any year; or

(2) For purposes of subpart EE of this 

part, combusting any amount of coal or 

coal-derived fuel, alone or in 

combination with any amount of any 

other fuel, during a specified year. 

Cogeneration unit means a stationary, 

fossil-fuel-fired boiler or stationary, 

fossil-fuel-fired combustion turbine: 

(1) Having equipment used to produce 

electricity and useful thermal energy for 

industrial, commercial, heating, or 

cooling purposes through the sequential 

use of energy; and 

(2) Producing during the 12-month 

period starting on the date the unit first 

produces electricity and during any 

calendar year after which the unit first 

produces electricity—

(i) For a topping-cycle cogeneration 

unit, 

(A) Useful thermal energy not less 

than 5 percent of total energy output; 

and 

(B) Useful power that, when added to 

one-half of useful thermal energy 

produced, is not less then 42.5 percent 

of total energy input, if useful thermal 

energy produced is 15 percent or more 

of total energy output, or not less than 

45 percent of total energy input, if 

useful thermal energy produced is less 

than 15 percent of total energy output. 

(ii) For a bottoming-cycle 

cogeneration unit, useful power not less 

than 45 percent of total energy input. 

Combustion turbine means: 

(1) An enclosed device comprising a 

compressor, a combustor, and a turbine 

and in which the flue gas resulting from 

the combustion of fuel in the combustor 

passes through the turbine, rotating the 

turbine; and 

(2) If the enclosed device under 

paragraph (1) of this definition is 

combined cycle, any associated heat 

recovery steam generator and steam 

turbine. 

Commence commercial operation

means, with regard to a unit serving a 

generator: 

(1) To have begun to produce steam, 

gas, or other heated medium used to 

generate electricity for sale or use, 

including test generation, except as 

provided in § 96.105. 

(i) For a unit that is a CAIR NOX unit 

under § 96.104 on the date the unit 

commences commercial operation as 

defined in paragraph (1) of this 

definition and that subsequently 

undergoes a physical change (other than 

replacement of the unit by a unit at the 

same source), such date shall remain the 

unit’s date of commencement of 

commercial operation. 

(ii) For a unit that is a CAIR NOX unit 

under § 96.104 on the date the unit 

commences commercial operation as 

defined in paragraph (1) of this 

definition and that is subsequently 

replaced by a unit at the same source 

(e.g., repowered), the replacement unit 

shall be treated as a separate unit with 

a separate date for commencement of 

commercial operation as defined in 

paragraph (1), (2), or (3) of this 

definition as appropriate. 

(2) Notwithstanding paragraph (1) of 

this definition and except as provided 

in § 96.105, for a unit that is not a CAIR 

NOX unit under § 96.104 on the date the 

unit commences commercial operation 

as defined in paragraph (1) of this 

definition and is not a unit under 

paragraph (3) of this definition, the 

unit’s date for commencement of 

commercial operation shall be the date 

on which the unit becomes a CAIR NOX

unit under § 96.104. 

(i) For a unit with a date for 

commencement of commercial 

operation as defined in paragraph (2) of 

this definition and that subsequently 

undergoes a physical change (other than 

replacement of the unit by a unit at the 

same source), such date shall remain the 

unit’s date of commencement of 

commercial operation. 

(ii) For a unit with a date for 

commencement of commercial 

operation as defined in paragraph (2) of 

this definition and that is subsequently 

replaced by a unit at the same source 

(e.g., repowered), the replacement unit 

shall be treated as a separate unit with 

a separate date for commencement of 

commercial operation as defined in 

paragraph (1), (2), or (3) of this 

definition as appropriate. 

(3) Notwithstanding paragraph (1) of 

this definition and except as provided 

in § 96.184(h) or § 96.187(b)(3), for a 

CAIR NOX opt-in unit or a unit for 

which a CAIR opt-in permit application 

is submitted and not withdrawn and a 

CAIR opt-in permit is not yet issued or 

denied under subpart II of this part, the 

unit’s date for commencement of 

commercial operation shall be the date 

on which the owner or operator is 

required to start monitoring and 

reporting the NOX emissions rate and 

the heat input of the unit under 

§ 96.184(b)(1)(i). 

(i) For a unit with a date for 

commencement of commercial 

operation as defined in paragraph (3) of 

this definition and that subsequently 

undergoes a physical change (other than 

replacement of the unit by a unit at the 

same source), such date shall remain the 

unit’s date of commencement of 

commercial operation. 

(ii) For a unit with a date for 

commencement of commercial 

operation as defined in paragraph (3) of 

this definition and that is subsequently 

replaced by a unit at the same source 

(e.g., repowered), the replacement unit 

shall be treated as a separate unit with 

a separate date for commencement of 

commercial operation as defined in 

paragraph (1), (2), or (3) of this 

definition as appropriate. 

(4) Notwithstanding paragraphs (1) 

through (3) of this definition, for a unit 

not serving a generator producing 

electricity for sale, the unit’s date of 

commencement of operation shall also 

be the unit’s date of commencement of 

commercial operation. 

Commence operation means:

(1) To have begun any mechanical, 

chemical, or electronic process, 

including, with regard to a unit, start-up 

of a unit’s combustion chamber, except 

as provided in § 96.105. 

(i) For a unit that is a CAIR NOX unit 

under § 96.104 on the date the unit 

commences operation as defined in 

paragraph (1) of this definition and that 

subsequently undergoes a physical 

change (other than replacement of the 

25342 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

unit by a unit at the same source), such 

date shall remain the unit’s date of 

commencement of operation. 

(ii) For a unit that is a CAIR NOX unit 

under § 96.104 on the date the unit 

commences operation as defined in 

paragraph (1) of this definition and that 

is subsequently replaced by a unit at the 

same source (e.g., repowered), the 

replacement unit shall be treated as a 

separate unit with a separate date for 

commencement of operation as defined 

in paragraph (1), (2), or (3) of this 

definition as appropriate. 

(2) Notwithstanding paragraph (1) of 

this definition and except as provided 

in § 96.105, for a unit that is not a CAIR 

NOX unit under § 96.104 on the date the 

unit commences operation as defined in 

paragraph (1) of this definition and is 

not a unit under paragraph (3) of this 

definition, the unit’s date for 

commencement of operation shall be the 

date on which the unit becomes a CAIR 

NOX unit under § 96.104. 

(i) For a unit with a date for 

commencement of operation as defined 

in paragraph (2) of this definition and 

that subsequently undergoes a physical 

change (other than replacement of the 

unit by a unit at the same source), such 

date shall remain the unit’s date of 

commencement of operation. 

(ii) For a unit with a date for 

commencement of operation as defined 

in paragraph (2) of this definition and 

that is subsequently replaced by a unit 

at the same source (e.g., repowered), the 

replacement unit shall be treated as a 

separate unit with a separate date for 

commencement of operation as defined 

in paragraph (1), (2), or (3) of this 

definition as appropriate. 

(3) Notwithstanding paragraph (1) of 

this definition and except as provided 

in § 96.184(h) or § 96.187(b)(3), for a 

CAIR NOX opt-in unit or a unit for 

which a CAIR opt-in permit application 

is submitted and not withdrawn and a 

CAIR opt-in permit is not yet issued or 

denied under subpart II of this part, the 

unit’s date for commencement of 

operation shall be the date on which the 

owner or operator is required to start 

monitoring and reporting the NOX

emissions rate and the heat input of the 

unit under § 96.184(b)(1)(i). 

(i) For a unit with a date for 

commencement of operation as defined 

in paragraph (3) of this definition and 

that subsequently undergoes a physical 

change (other than replacement of the 

unit by a unit at the same source), such 

date shall remain the unit’s date of 

commencement of operation. 

(ii) For a unit with a date for 

commencement of operation as defined 

in paragraph (3) of this definition and 

that is subsequently replaced by a unit 

at the same source (e.g., repowered), the 

replacement unit shall be treated as a 

separate unit with a separate date for 

commencement of operation as defined 

in paragraph (1), (2), or (3) of this 

definition as appropriate. 

Common stack means a single flue 

through which emissions from 2 or 

more units are exhausted. 

Compliance account means a CAIR 

NOX Allowance Tracking System 

account, established by the 

Administrator for a CAIR NOX source 

under subpart FF or II of this part, in 

which any CAIR NOX allowance 

allocations for the CAIR NOX units at 

the source are initially recorded and in 

which are held any CAIR NOX

allowances available for use for a 

control period in order to meet the 

source’s CAIR NOX emissions limitation 

in accordance with § 96.154. 

Continuous emission monitoring 

system or CEMS means the equipment 

required under subpart HH of this part 

to sample, analyze, measure, and 

provide, by means of readings recorded 

at least once every 15 minutes (using an 

automated data acquisition and 

handling system (DAHS)), a permanent 

record of nitrogen oxides emissions, 

stack gas volumetric flow rate, stack gas 

moisture content, and oxygen or carbon 

dioxide concentration (as applicable), in 

a manner consistent with part 75 of this 

chapter. The following systems are the 

principal types of continuous emission 

monitoring systems required under 

subpart HH of this part:

(1) A flow monitoring system, 

consisting of a stack flow rate monitor 

and an automated data acquisition and 

handling system and providing a 

permanent, continuous record of stack 

gas volumetric flow rate, in standard 

cubic feet per hour (scfh); 

(2) A nitrogen oxides concentration 

monitoring system, consisting of a NOX

pollutant concentration monitor and an 

automated data acquisition and 

handling system and providing a 

permanent, continuous record of NOX

emissions, in parts per million (ppm); 

(3) A nitrogen oxides emission rate (or 

NOX-diluent) monitoring system, 

consisting of a NOX pollutant 

concentration monitor, a diluent gas 

(CO2 or O2) monitor, and an automated 

data acquisition and handling system 

and providing a permanent, continuous 

record of NOX concentration, in parts 

per million (ppm), diluent gas 

concentration, in percent CO2 or O2; and 

NOX emission rate, in pounds per 

million British thermal units (lb/

mmBtu); 

(4) A moisture monitoring system, as 

defined in § 75.11(b)(2) of this chapter 

and providing a permanent, continuous 

record of the stack gas moisture content, 

in percent H2O; 

(5) A carbon dioxide monitoring 

system, consisting of a CO2 pollutant 

concentration monitor (or an oxygen 

monitor plus suitable mathematical 

equations from which the CO2

concentration is derived) and an 

automated data acquisition and 

handling system and providing a 

permanent, continuous record of CO2

emissions, in percent CO2; and 

(6) An oxygen monitoring system, 

consisting of an O2 concentration 

monitor and an automated data 

acquisition and handling system and 

providing a permanent, continuous 

record of O2, in percent O2. 

Control period means the period 

beginning January 1 of a calendar year 

and ending on December 31 of the same 

year, inclusive. 

Emissions means air pollutants 

exhausted from a unit or source into the 

atmosphere, as measured, recorded, and 

reported to the Administrator by the 

CAIR designated representative and as 

determined by the Administrator in 

accordance with subpart HH of this part. 

Excess emissions means any ton of 

nitrogen oxides emitted by the CAIR 

NOX units at a CAIR NOX source during 

a control period that exceeds the CAIR 

NOX emissions limitation for the source. 

Fossil fuel means natural gas, 

petroleum, coal, or any form of solid, 

liquid, or gaseous fuel derived from 

such material. 

Fossil-fuel-fired means, with regard to 

a unit, combusting any amount of fossil 

fuel in any calendar year. 

Fuel oil means any petroleum-based 

fuel (including diesel fuel or petroleum 

derivatives such as oil tar) and any 

recycled or blended petroleum products 

or petroleum by-products used as a fuel 

whether in a liquid, solid, or gaseous 

state. 

General account means a CAIR NOX

Allowance Tracking System account, 

established under subpart FF of this 

part, that is not a compliance account. 

Generator means a device that 

produces electricity. 

Gross electrical output means, with 

regard to a cogeneration unit, electricity 

made available for use, including any 

such electricity used in the power 

production process (which process 

includes, but is not limited to, any onsite processing or treatment of fuel 

combusted at the unit and any on-site 

emission controls). 

Heat input means, with regard to a 

specified period of time, the product (in 

mmBtu/time) of the gross calorific value 

of the fuel (in Btu/lb) divided by 

1,000,000 Btu/mmBtu and multiplied by 

the fuel feed rate into a combustion 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25343

device (in lb of fuel/time), as measured, 

recorded, and reported to the 

Administrator by the CAIR designated 

representative and determined by the 

Administrator in accordance with 

subpart HH of this part and excluding 

the heat derived from preheated 

combustion air, recirculated flue gases, 

or exhaust from other sources. 

Heat input rate means the amount of 

heat input (in mmBtu) divided by unit 

operating time (in hr) or, with regard to 

a specific fuel, the amount of heat input 

attributed to the fuel (in mmBtu) 

divided by the unit operating time (in 

hr) during which the unit combusts the 

fuel.

Life-of-the-unit, firm power 

contractual arrangement means a unit 

participation power sales agreement 

under which a utility or industrial 

customer reserves, or is entitled to 

receive, a specified amount or 

percentage of nameplate capacity and 

associated energy generated by any 

specified unit and pays its proportional 

amount of such unit’s total costs, 

pursuant to a contract: 

(1) For the life of the unit; 

(2) For a cumulative term of no less 

than 30 years, including contracts that 

permit an election for early termination; 

or 

(3) For a period no less than 25 years 

or 70 percent of the economic useful life 

of the unit determined as of the time the 

unit is built, with option rights to 

purchase or release some portion of the 

nameplate capacity and associated 

energy generated by the unit at the end 

of the period. 

Maximum design heat input means, 

starting from the initial installation of a 

unit, the maximum amount of fuel per 

hour (in Btu/hr) that a unit is capable of 

combusting on a steady state basis as 

specified by the manufacturer of the 

unit, or, starting from the completion of 

any subsequent physical change in the 

unit resulting in a decrease in the 

maximum amount of fuel per hour (in 

Btu/hr) that a unit is capable of 

combusting on a steady state basis, such 

decreased maximum amount as 

specified by the person conducting the 

physical change. 

Monitoring system means any 

monitoring system that meets the 

requirements of subpart HH of this part, 

including a continuous emissions 

monitoring system, an alternative 

monitoring system, or an excepted 

monitoring system under part 75 of this 

chapter. 

Most stringent State or Federal NOX

emissions limitation means, with regard 

to a unit, 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, starting 

from the initial installation of a 

generator, the maximum electrical 

generating output (in MWe) that the 

generator is capable of producing on a 

steady state basis and during continuous 

operation (when not restricted by 

seasonal or other deratings) as specified 

by the manufacturer of the generator or, 

starting from the completion of any 

subsequent physical change in the 

generator resulting in an increase in the 

maximum electrical generating output 

(in MWe) that the generator is capable 

of producing on a steady state basis and 

during continuous operation (when not 

restricted by seasonal or other 

deratings), such increased maximum 

amount as specified by the person 

conducting the physical change. 

Oil-fired means, for purposes of 

subpart EE of this part, combusting fuel 

oil for more than 15.0 percent of the 

annual heat input in a specified year. 

Operator means any person who 

operates, controls, or supervises a CAIR 

NOX unit or a CAIR NOX source and 

shall include, but not be limited to, any 

holding company, utility system, or 

plant manager of such a unit or source. 

Owner means any of the following 

persons: 

(1) With regard to a CAIR NOX source 

or a CAIR NOX unit at a source, 

respectively: 

(i) Any holder of any portion of the 

legal or equitable title in a CAIR NOX

unit at the source or the CAIR NOX unit; 

(ii) Any holder of a leasehold interest 

in a CAIR NOX unit at the source or the 

CAIR NOX unit; or 

(iii) Any purchaser of power from a 

CAIR NOX unit at the source or the 

CAIR NOX unit under a life-of-the-unit, 

firm power contractual arrangement; 

provided that, unless expressly 

provided for in a leasehold agreement, 

owner shall not include a passive lessor, 

or a person who has an equitable 

interest through such lessor, whose 

rental payments are not based (either 

directly or indirectly) on the revenues or 

income from such CAIR NOX unit; or 

(2) With regard to any general 

account, any person who has an 

ownership interest with respect to the 

CAIR NOX allowances held in the 

general account and who is subject to 

the binding agreement for the CAIR 

authorized account representative to 

represent the person’s ownership 

interest with respect to CAIR NOX

allowances. 

Permitting authority means the State 

air pollution control agency, local 

agency, other State agency, or other 

agency authorized by the Administrator 

to issue or revise permits to meet the 

requirements of the CAIR NOX Annual 

Trading Program in accordance with 

subpart CC of this part or, if no such 

agency has been so authorized, the 

Administrator. 

Potential electrical output capacity

means 33 percent of a unit’s maximum 

design heat input, divided by 3,413 Btu/

kWh, divided by 1,000 kWh/MWh, and 

multiplied by 8,760 hr/yr. 

Receive or receipt of means, when 

referring to the permitting authority or 

the Administrator, to come into 

possession of a document, information, 

or correspondence (whether sent in hard 

copy or by authorized electronic 

transmission), as indicated in an official 

correspondence log, or by a notation 

made on the document, information, or 

correspondence, by the permitting 

authority or the Administrator in the 

regular course of business. 

Recordation, record, or recorded

means, with regard to CAIR NOX

allowances, the movement of CAIR NOX

allowances by the Administrator into or 

between CAIR NOX Allowance Tracking 

System accounts, for purposes of 

allocation, transfer, or deduction. 

Reference method means any direct 

test method of sampling and analyzing 

for an air pollutant as specified in 

§ 75.22 of this chapter.

Repowered means, with regard to a 

unit, replacement of a coal-fired boiler 

with one of the following coal-fired 

technologies at the same source as the 

coal-fired boiler: 

(1) Atmospheric or pressurized 

fluidized bed combustion; 

(2) Integrated gasification combined 

cycle; 

(3) Magnetohydrodynamics; 

(4) Direct and indirect coal-fired 

turbines; 

(5) Integrated gasification fuel cells; or 

(6) As determined by the 

Administrator in consultation with the 

Secretary of Energy, a derivative of one 

or more of the technologies under 

paragraphs (1) through (5) of this 

definition and any other coal-fired 

technology capable of controlling 

multiple combustion emissions 

simultaneously with improved boiler or 

generation efficiency and with 

significantly greater waste reduction 

relative to the performance of 

technology in widespread commercial 

use as of January 1, 2005. 

Serial number means, for a CAIR NOX

allowance, the unique identification 

number assigned to each CAIR NOX

allowance by the Administrator. 

Sequential use of energy means: 

(1) For a topping-cycle cogeneration 

unit, the use of reject heat from 

25344 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

electricity production in a useful 

thermal energy application or process; 

or 

(2) For a bottoming-cycle cogeneration 

unit, the use of reject heat from useful 

thermal energy application or process in 

electricity production. 

Source means all buildings, 

structures, or installations located in 

one or more contiguous or adjacent 

properties under common control of the 

same person or persons. For purposes of 

section 502(c) of the Clean Air Act, a 

‘‘source,’’ including a ‘‘source’’ with 

multiple units, shall be considered a 

single ‘‘facility.’’

State means one of the States or the 

District of Columbia that adopts the 

CAIR NOX Annual Trading Program 

pursuant to § 51.123(o)(1) or (2) of this 

chapter. 

Submit or serve means to send or 

transmit a document, information, or 

correspondence to the person specified 

in accordance with the applicable 

regulation: 

(1) In person; 

(2) By United States Postal Service; or 

(3) By other means of dispatch or 

transmission and delivery. Compliance 

with any ‘‘submission’’ or ‘‘service’’

deadline shall be determined by the 

date of dispatch, transmission, or 

mailing and not the date of receipt. 

Title V operating permit means a 

permit issued under title V of the Clean 

Air Act and part 70 or part 71 of this 

chapter. 

Title V operating permit regulations

means the regulations that the 

Administrator has approved or issued as 

meeting the requirements of title V of 

the Clean Air Act and part 70 or 71 of 

this chapter. 

Ton means 2,000 pounds. For the 

purpose of determining compliance 

with the CAIR NOX emissions 

limitation, total tons of nitrogen oxides 

emissions for a control period shall be 

calculated as the sum of all recorded 

hourly emissions (or the mass 

equivalent of the recorded hourly 

emission rates) in accordance with 

subpart HH of this part, but with any 

remaining fraction of a ton equal to or 

greater than 0.50 tons deemed to equal 

one ton and any remaining fraction of a 

ton less than 0.50 tons deemed to equal 

zero tons. 

Topping-cycle cogeneration unit

means a cogeneration unit in which the 

energy input to the unit is first used to 

produce useful power, including 

electricity, and at least some of the 

reject heat from the electricity 

production is then used to provide 

useful thermal energy. 

Total energy input means, with regard 

to a cogeneration unit, total energy of all 

forms supplied to the cogeneration unit, 

excluding energy produced by the 

cogeneration unit itself. 

Total energy output means, with 

regard to a cogeneration unit, the sum 

of useful power and useful thermal 

energy produced by the cogeneration 

unit. 

Unit means a stationary, fossil-fuelfired boiler or combustion turbine or 

other stationary, fossil-fuel-fired 

combustion device. 

Unit operating day means a calendar 

day in which a unit combusts any fuel. 

Unit operating hour or hour of unit 

operation means an hour in which a 

unit combusts any fuel. 

Useful power means, with regard to a 

cogeneration unit, electricity or 

mechanical energy made available for 

use, excluding any such energy used in 

the power production process (which 

process includes, but is not limited to, 

any on-site processing or treatment of 

fuel combusted at the unit and any onsite emission controls). 

Useful thermal energy means, with 

regard to a cogeneration unit, thermal 

energy that is: 

(1) Made available to an industrial or 

commercial process (not a power 

production process), excluding any heat 

contained in condensate return or 

makeup water; 

(2) Used in a heating application (e.g., 

space heating or domestic hot water 

heating); or 

(3) Used in a space cooling 

application (i.e., thermal energy used by 

an absorption chiller). 

Utility power distribution system

means the portion of an electricity grid 

owned or operated by a utility and 

dedicated to delivering electricity to 

customers.

§ 96.103 Measurements, abbreviations, 

and acronyms. 

Measurements, abbreviations, and 

acronyms used in this part are defined 

as follows:

Btu—British thermal unit. 

CO2—carbon dioxide. 

NOX—nitrogen oxides. 

hr—hour. 

kW—kilowatt electrical. 

kWh—kilowatt hour. 

mmBtu—million Btu. 

MWe—megawatt electrical. 

MWh—megawatt hour. 

O2—oxygen. 

ppm—parts per million. 

lb—pound. 

scfh—standard cubic feet per hour. 

SO2—sulfur dioxide. 

H2O—water. 

yr—year.

§ 96.104 Applicability. 

The following units in a State shall be 

CAIR NOX units, and any source that 

includes one or more such units shall be 

a CAIR NOX source, subject to the 

requirements of this subpart and 

subparts BB through HH of this part: 

(a) Except as provided in paragraph 

(b) of this section, a stationary, fossilfuel-fired boiler or stationary, fossilfuel-fired combustion turbine serving at 

any time, since the start-up of the unit’s 

combustion chamber, a generator with 

nameplate capacity of more than 25 

MWe producing electricity for sale. 

(b) For a unit that qualifies as a 

cogeneration unit during the 12-month 

period starting on the date the unit first 

produces electricity and continues to 

qualify as a cogeneration unit, a 

cogeneration unit serving at any time a 

generator with nameplate capacity of 

more than 25 MWe and supplying in 

any calendar year more than one-third 

of the unit’s potential electric output 

capacity or 219,000 MWh, whichever is 

greater, to any utility power distribution 

system for sale. If a unit qualifies as a 

cogeneration unit during the 12-month 

period starting on the date the unit first 

produces electricity but subsequently no 

longer qualifies as a cogeneration unit, 

the unit shall be subject to paragraph (a) 

of this section starting on the day on 

which the unit first no longer qualifies 

as a cogeneration unit.

§ 96.105 Retired unit exemption. 

(a)(1) Any CAIR NOX unit that is 

permanently retired and is not a CAIR 

NOX opt-in unit under subpart II of this 

part shall be exempt from the CAIR NOX

Annual Trading Program, except for the 

provisions of this section, § 96.102, 

§ 96.103, § 96.104, § 96.106(c)(4) 

through (8), § 96.107, and subparts EE 

through GG of this part. 

(2) The exemption under paragraph 

(a)(1) of this section shall become 

effective the day on which the CAIR 

NOX unit is permanently retired. Within 

30 days of the unit’s permanent 

retirement, the CAIR designated 

representative shall submit a statement 

to the permitting authority otherwise 

responsible for administering any CAIR 

permit for the unit and shall submit a 

copy of the statement to the 

Administrator. The statement shall 

state, in a format prescribed by the 

permitting authority, that the unit was 

permanently retired on a specific date 

and will comply with the requirements 

of paragraph (b) of this section. 

(3) After receipt of the statement 

under paragraph (a)(2) of this section, 

the permitting authority will amend any 

permit under subpart CC of this part 

covering the source at which the unit is 

located to add the provisions and 

requirements of the exemption under 

paragraphs (a)(1) and (b) of this section. 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25345

(b) Special provisions. (1) A unit 

exempt under paragraph (a) of this 

section shall not emit any nitrogen 

oxides, starting on the date that the 

exemption takes effect. 

(2) The permitting authority will 

allocate CAIR NOX allowances under 

subpart EE of this part to a unit exempt 

under paragraph (a) of this section. 

(3) For a period of 5 years from the 

date the records are created, the owners 

and operators of a unit exempt under 

paragraph (a) of 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 before the end of the 

period, in writing by the permitting 

authority or the Administrator. The 

owners and operators bear the burden of 

proof that the unit is permanently 

retired. 

(4) The owners and operators and, to 

the extent applicable, the CAIR 

designated representative of a unit 

exempt under paragraph (a) of this 

section shall comply with the 

requirements of the CAIR NOX Annual 

Trading Program concerning all periods 

for which the exemption is not in effect, 

even if such requirements arise, or must 

be complied with, after the exemption 

takes effect. 

(5) A unit exempt under paragraph (a) 

of this section and located at a source 

that is required, or but for this 

exemption would be required, to have a 

title V operating permit shall not resume 

operation unless the CAIR designated 

representative of the source submits a 

complete CAIR permit application 

under § 96.122 for the unit not less than 

18 months (or such lesser time provided 

by the permitting authority) before the 

later of January 1, 2009 or the date on 

which the unit resumes operation. 

(6) On the earlier of the following 

dates, a unit exempt under paragraph (a) 

of this section shall lose its exemption: 

(i) The date on which the CAIR 

designated representative submits a 

CAIR permit application for the unit 

under paragraph (b)(5) of this section;

(ii) The date on which the CAIR 

designated representative is required 

under paragraph (b)(5) of this section to 

submit a CAIR permit application for 

the unit; or 

(iii) The date on which the unit 

resumes operation, if the CAIR 

designated representative is not 

required to submit a CAIR permit 

application for the unit. 

(7) For the purpose of applying 

monitoring, reporting, and 

recordkeeping requirements under 

subpart HH of this part, a unit that loses 

its exemption under paragraph (a) of 

this section shall be treated as a unit 

that commences operation and 

commercial operation on the first date 

on which the unit resumes operation.

§ 96.106 Standard requirements. 

(a) Permit requirements. (1) The CAIR 

designated representative of each CAIR 

NOX source required to have a title V 

operating permit and each CAIR NOX

unit required to have a title V operating 

permit at the source shall: 

(i) Submit to the permitting authority 

a complete CAIR permit application 

under § 96.122 in accordance with the 

deadlines specified in § 96.121(a) and 

(b); and 

(ii) Submit in a timely manner any 

supplemental information that the 

permitting authority determines is 

necessary in order to review a CAIR 

permit application and issue or deny a 

CAIR permit. 

(2) The owners and operators of each 

CAIR NOX source required to have a 

title V operating permit and each CAIR 

NOX unit required to have a title V 

operating permit at the source shall 

have a CAIR permit issued by the 

permitting authority under subpart CC 

of this part for the source and operate 

the source and the unit in compliance 

with such CAIR permit. 

(3) Except as provided in subpart II of 

this part, the owners and operators of a 

CAIR NOX source that is not otherwise 

required to have a title V operating 

permit and each CAIR NOX unit that is 

not otherwise required to have a title V 

operating permit are not required to 

submit a CAIR permit application, and 

to have a CAIR permit, under subpart 

CC of this part for such CAIR NOX

source and such CAIR NOX unit. 

(b) Monitoring, reporting, and 

recordkeeping requirements. (1) The 

owners and operators, and the CAIR 

designated representative, of each CAIR 

NOX source and each CAIR NOX unit at 

the source shall comply with the 

monitoring, reporting, and 

recordkeeping requirements of subpart 

HH of this part. 

(2) The emissions measurements 

recorded and reported in accordance 

with subpart HH of this part shall be 

used to determine compliance by each 

CAIR NOX source with the CAIR NOX

emissions limitation under paragraph 

(c) of this section. 

(c) Nitrogen oxides emission 

requirements. (1) As of the allowance 

transfer deadline for a control period, 

the owners and operators of each CAIR 

NOX source and each CAIR NOX unit at 

the source shall hold, in the source’s 

compliance account, CAIR NOX

allowances available for compliance 

deductions for the control period under 

§ 96.154(a) in an amount not less than 

the tons of total nitrogen oxides 

emissions for the control period from all 

CAIR NOX units at the source, as 

determined in accordance with subpart 

HH of this part. 

(2) A CAIR NOX unit shall be subject 

to the requirements under paragraph 

(c)(1) of this section starting on the later 

of January 1, 2009 or the deadline for 

meeting the unit’s monitor certification 

requirements under § 96.170(b)(1),(2), or 

(5). 

(3) A CAIR NOX allowance shall not 

be deducted, for compliance with the 

requirements under paragraph (c)(1) of 

this section, for a control period in a 

calendar year before the year for which 

the CAIR NOX allowance was allocated. 

(4) CAIR NOX allowances shall be 

held in, deducted from, or transferred 

into or among CAIR NOX Allowance 

Tracking System accounts in accordance 

with subpart EE of this part. 

(5) A CAIR NOX allowance is a 

limited authorization to emit one ton of 

nitrogen oxides in accordance with the 

CAIR NOX Annual Trading Program. No 

provision of the CAIR NOX Annual 

Trading Program, the CAIR permit 

application, the CAIR permit, or an 

exemption under § 96.105 and no 

provision of law shall be construed to 

limit the authority of the State or the 

United States to terminate or limit such 

authorization.

(6) A CAIR NOX allowance does not 

constitute a property right. 

(7) Upon recordation by the 

Administrator under subpart FF, GG, or 

II of this part, every allocation, transfer, 

or deduction of a CAIR NOX allowance 

to or from a CAIR NOX unit’s 

compliance account is incorporated 

automatically in any CAIR permit of the 

source that includes the CAIR NOX unit. 

(d) Excess emissions requirements. (1) 

If a CAIR NOX source emits nitrogen 

oxides during any control period in 

excess of the CAIR NOX emissions 

limitation, then: 

(i) The owners and operators of the 

source and each CAIR NOX unit at the 

source shall surrender the CAIR NOX

allowances required for deduction 

under § 96.154(d)(1) and pay any fine, 

penalty, or assessment or comply with 

any other remedy imposed, for the same 

violations, under the Clean Air Act or 

applicable State law; and 

(ii) Each ton of such excess emissions 

and each day of such control period 

shall constitute a separate violation of 

this subpart, the Clean Air Act, and 

applicable State law. 

(2) [Reserved.] 

(e) Recordkeeping and reporting 

requirements. (1) Unless otherwise 

provided, the owners and operators of 

25346 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

the CAIR NOX source and each CAIR 

NOX 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 before the end of 5 years, in 

writing by the permitting authority or 

the Administrator. 

(i) The certificate of representation 

under § 96.113 for the CAIR designated 

representative for the source and each 

CAIR NOX unit at the source and all 

documents that demonstrate the truth of 

the statements in the certificate of 

representation; provided that the 

certificate and documents shall be 

retained on site at the source beyond 

such 5-year period until such 

documents are superseded because of 

the submission of a new certificate of 

representation under § 96.113 changing 

the CAIR designated representative. 

(ii) All emissions monitoring 

information, in accordance with subpart 

HH of this part, provided that to the 

extent that subpart HH of this part 

provides for a 3-year period for 

recordkeeping, the 3-year period shall 

apply. 

(iii) Copies of all reports, compliance 

certifications, and other submissions 

and all records made or required under 

the CAIR NOX Annual Trading Program. 

(iv) Copies of all documents used to 

complete a CAIR permit application and 

any other submission under the CAIR 

NOX Annual Trading Program or to 

demonstrate compliance with the 

requirements of the CAIR NOX Annual 

Trading Program. 

(2) The CAIR designated 

representative of a CAIR NOX source 

and each CAIR NOX unit at the source 

shall submit the reports required under 

the CAIR NOX Annual Trading Program, 

including those under subpart HH of 

this part. 

(f) Liability. (1) Each CAIR NOX

source and each CAIR NOX unit shall 

meet the requirements of the CAIR NOX

Annual Trading Program. 

(2) Any provision of the CAIR NOX

Annual Trading Program that applies to 

a CAIR NOX source or the CAIR 

designated representative of a CAIR 

NOX source shall also apply to the 

owners and operators of such source 

and of the CAIR NOX units at the 

source. 

(3) Any provision of the CAIR NOX

Annual Trading Program that applies to 

a CAIR NOX unit or the CAIR designated 

representative of a CAIR NOX unit shall 

also apply to the owners and operators 

of such unit. 

(g) Effect on other authorities. No 

provision of the CAIR NOX Annual 

Trading Program, a CAIR permit 

application, a CAIR permit, or an 

exemption under § 96.105 shall be 

construed as exempting or excluding the 

owners and operators, and the CAIR 

designated representative, of a CAIR 

NOX source or CAIR NOX unit from 

compliance with any other provision of 

the applicable, approved State 

implementation plan, a federally 

enforceable permit, or the Clean Air Act.

§ 96.107 Computation of time. 

(a) Unless otherwise stated, any time 

period scheduled, under the CAIR NOX

Annual Trading Program, to begin on 

the occurrence of an act or event shall 

begin on the day the act or event occurs. 

(b) Unless otherwise stated, any time 

period scheduled, under the CAIR NOX

Annual Trading Program, to begin 

before the occurrence of an act or event 

shall be computed so that the period 

ends the day before the act or event 

occurs. 

(c) Unless otherwise stated, if the final 

day of any time period, under the CAIR 

NOX Annual Trading Program, falls on 

a weekend or a State or Federal holiday, 

the time period shall be extended to the 

next business day.

§ 96.108 Appeal procedures. 

The appeal procedures for decisions 

of the Administrator under the CAIR 

NOX Annual Trading Program are set 

forth in part 78 of this chapter.

Subpart BB—CAIR Designated 

Representative for CAIR NOX Sources

§ 96.110 Authorization and responsibilities 

of CAIR designated representative. 

(a) Except as provided under § 96.111, 

each CAIR NOX source, including all 

CAIR NOX units at the source, shall 

have one and only one CAIR designated 

representative, with regard to all matters 

under the CAIR NOX Annual Trading 

Program concerning the source or any 

CAIR NOX unit at the source. 

(b) The CAIR designated 

representative of the CAIR NOX source 

shall be selected by an agreement 

binding on the owners and operators of 

the source and all CAIR NOX units at 

the source and shall act in accordance 

with the certification statement in 

§ 96.113(a)(4)(iv). 

(c) Upon receipt by the Administrator 

of a complete certificate of 

representation under § 96.113, the CAIR 

designated representative of the source 

shall represent and, by his or her 

representations, actions, inactions, or 

submissions, legally bind each owner 

and operator of the CAIR NOX source 

represented and each CAIR NOX unit at 

the source in all matters pertaining to 

the CAIR NOX Annual Trading Program, 

notwithstanding any agreement between 

the CAIR designated representative and 

such owners and operators. The owners 

and operators shall be bound by any 

decision or order issued to the CAIR 

designated representative by the 

permitting authority, the Administrator, 

or a court regarding the source or unit. 

(d) No CAIR permit will be issued, no 

emissions data reports will be accepted, 

and no CAIR NOX Allowance Tracking 

System account will be established for 

a CAIR NOX unit at a source, until the 

Administrator has received a complete 

certificate of representation under 

§ 96.113 for a CAIR designated 

representative of the source and the 

CAIR NOX units at the source. 

(e)(1) Each submission under the 

CAIR NOX Annual Trading Program 

shall be submitted, signed, and certified 

by the CAIR designated representative 

for each CAIR NOX source on behalf of 

which the submission is made. Each 

such submission shall include the 

following certification statement by the 

CAIR designated representative: ‘‘I am 

authorized to make this submission on 

behalf of the owners and operators of 

the source or units for which the 

submission is made. I certify under 

penalty of law that I have personally 

examined, and am familiar with, the 

statements and information submitted 

in this document and all its 

attachments. Based on my inquiry of 

those individuals with primary 

responsibility for obtaining the 

information, I certify that the statements 

and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’

(2) The permitting authority and the 

Administrator will accept or act on a 

submission made on behalf of owner or 

operators of a CAIR NOX source or a 

CAIR NOX unit only if the submission 

has been made, signed, and certified in 

accordance with paragraph (e)(1) of this 

section.

§ 96.111 Alternate CAIR designated 

representative.

(a) A certificate of representation 

under § 96.113 may designate one and 

only one alternate CAIR designated 

representative, who may act on behalf of 

the CAIR designated representative. The 

agreement by which the alternate CAIR 

designated representative is selected 

shall include a procedure for 

authorizing the alternate CAIR 

designated representative to act in lieu 

of the CAIR designated representative. 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25347

(b) Upon receipt by the Administrator 

of a complete certificate of 

representation under § 96.113, any 

representation, action, inaction, or 

submission by the alternate CAIR 

designated representative shall be 

deemed to be a representation, action, 

inaction, or submission by the CAIR 

designated representative. 

(c) Except in this section and 

§§ 96.102, 96.110(a) and (d), 96.112, 

96.113, 96.151 and 96.182, whenever 

the term ‘‘CAIR designated 

representative’’ is used in subparts AA 

through II of this part, the term shall be 

construed to include the CAIR 

designated representative or any 

alternate CAIR designated 

representative.

§ 96.112 Changing CAIR designated 

representative and alternate CAIR 

designated representative; changes in 

owners and operators. 

(a) Changing CAIR designated 

representative. The CAIR designated 

representative may be changed at any 

time upon receipt by the Administrator 

of a superseding complete certificate of 

representation under § 96.113. 

Notwithstanding any such change, all 

representations, actions, inactions, and 

submissions by the previous CAIR 

designated representative before the 

time and date when the Administrator 

receives the superseding certificate of 

representation shall be binding on the 

new CAIR designated representative and 

the owners and operators of the CAIR 

NOX source and the CAIR NOX units at 

the source. 

(b) Changing alternate CAIR 

designated representative. The alternate 

CAIR designated representative may be 

changed at any time upon receipt by the 

Administrator of a superseding 

complete certificate of representation 

under § 96.113. Notwithstanding any 

such change, all representations, 

actions, inactions, and submissions by 

the previous alternate CAIR designated 

representative before the time and date 

when the Administrator receives the 

superseding certificate of representation 

shall be binding on the new alternate 

CAIR designated representative and the 

owners and operators of the CAIR NOX

source and the CAIR NOX units at the 

source. 

(c) Changes in owners and operators.

(1) In the event a new owner or operator 

of a CAIR NOX source or a CAIR NOX

unit is not included in the list of owners 

and operators in the certificate of 

representation under § 96.113, such new 

owner or operator shall be deemed to be 

subject to and bound by the certificate 

of representation, the representations, 

actions, inactions, and submissions of 

the CAIR designated representative and 

any alternate CAIR designated 

representative of the source or unit, and 

the decisions and orders of the 

permitting authority, the Administrator, 

or a court, as if the new owner or 

operator were included in such list. 

(2) Within 30 days following any 

change in the owners and operators of 

a CAIR NOX source or a CAIR NOX unit, 

including the addition of a new owner 

or operator, the CAIR designated 

representative or any alternate CAIR 

designated representative shall submit a 

revision to the certificate of 

representation under § 96.113 amending 

the list of owners and operators to 

include the change.

§ 96.113 Certificate of representation. 

(a) A complete certificate of 

representation for a CAIR designated 

representative or an alternate CAIR 

designated representative shall include 

the following elements in a format 

prescribed by the Administrator: 

(1) Identification of the CAIR NOX

source, and each CAIR NOX unit at the 

source, for which the certificate of 

representation is submitted. 

(2) The name, address, e-mail address 

(if any), telephone number, and 

facsimile transmission number (if any) 

of the CAIR designated representative 

and any alternate CAIR designated 

representative. 

(3) A list of the owners and operators 

of the CAIR NOX source and of each 

CAIR NOX unit at the source.

(4) The following certification 

statements by the CAIR designated 

representative and any alternate CAIR 

designated representative—

(i) ‘‘I certify that I was selected as the 

CAIR designated representative or 

alternate CAIR designated 

representative, as applicable, by an 

agreement binding on the owners and 

operators of the source and each CAIR 

NOX unit at the source.’’

(ii) ‘‘I certify that I have all the 

necessary authority to carry out my 

duties and responsibilities under the 

CAIR NOX Annual Trading Program on 

behalf of the owners and operators of 

the source and of each CAIR NOX unit 

at the source and that each such owner 

and operator shall be fully bound by my 

representations, actions, inactions, or 

submissions.’’

(iii) ‘‘I certify that the owners and 

operators of the source and of each 

CAIR NOX unit at the source shall be 

bound by any order issued to me by the 

Administrator, the permitting authority, 

or a court regarding the source or unit.’’

(iv) ‘‘Where there are multiple holders 

of a legal or equitable title to, or a 

leasehold interest in, a CAIR NOX unit, 

or where a customer purchases power 

from a CAIR NOX unit under a life-ofthe-unit, firm power contractual 

arrangement, I certify that: I have given 

a written notice of my selection as the 

‘CAIR designated representative’ or 

‘alternate CAIR designated 

representative’, as applicable, and of the 

agreement by which I was selected to 

each owner and operator of the source 

and of each CAIR NOX unit at the 

source; and CAIR NOX allowances and 

proceeds of transactions involving CAIR 

NOX allowances will be deemed to be 

held or distributed in proportion to each 

holder’s legal, equitable, leasehold, or 

contractual reservation or entitlement, 

except that, if such multiple holders 

have expressly provided for a different 

distribution of CAIR NOX allowances by 

contract, CAIR NOX allowances and 

proceeds of transactions involving CAIR 

NOX allowances will be deemed to be 

held or distributed in accordance with 

the contract.’’

(5) The signature of the CAIR 

designated representative and any 

alternate CAIR designated 

representative and the dates signed. 

(b) Unless otherwise required by the 

permitting authority or the 

Administrator, documents of agreement 

referred to in the certificate of 

representation shall not be submitted to 

the permitting authority or the 

Administrator. Neither the permitting 

authority nor the Administrator shall be 

under any obligation to review or 

evaluate the sufficiency of such 

documents, if submitted.

§ 96.114 Objections concerning CAIR 

designated representative. 

(a) Once a complete certificate of 

representation under § 96.113 has been 

submitted and received, the permitting 

authority and the Administrator will 

rely on the certificate of representation 

unless and until a superseding complete 

certificate of representation under 

§ 96.113 is received by the 

Administrator. 

(b) Except as provided in § 96.112(a) 

or (b), no objection or other 

communication submitted to the 

permitting authority or the 

Administrator concerning the 

authorization, or any representation, 

action, inaction, or submission, of the 

CAIR designated representative shall 

affect any representation, action, 

inaction, or submission of the CAIR 

designated representative or the finality 

of any decision or order by the 

permitting authority or the 

Administrator under the CAIR NOX

Annual Trading Program. 

(c) Neither the permitting authority 

nor the Administrator will adjudicate 

25348 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

any private legal dispute concerning the 

authorization or any representation, 

action, inaction, or submission of any 

CAIR designated representative, 

including private legal disputes 

concerning the proceeds of CAIR NOX

allowance transfers.

Subpart CC—Permits

§ 96.120 General CAIR Annual Trading 

Program permit requirements. 

(a) For each CAIR NOX source 

required to have a title V operating 

permit or required, under subpart II of 

this part, to have a title V operating 

permit or other federally enforceable 

permit, such permit shall include a 

CAIR permit administered by the 

permitting authority for the title V 

operating permit or the federally 

enforceable permit as applicable. The 

CAIR portion of the title V permit or 

other federally enforceable permit as 

applicable shall be administered in 

accordance with the permitting 

authority’s title V operating permits 

regulations promulgated under part 70 

or 71 of this chapter or the permitting 

authority’s regulations for other 

federally enforceable permits as 

applicable, except as provided 

otherwise by this subpart and subpart II 

of this part. 

(b) Each CAIR permit shall contain, 

with regard to the CAIR NOX source and 

the CAIR NOX units at the source 

covered by the CAIR permit, all 

applicable CAIR NOX Annual Trading 

Program, CAIR NOX Ozone Season 

Trading Program, and CAIR SO2 Trading 

Program requirements and shall be a 

complete and separable portion of the 

title V operating permit or other 

federally enforceable permit under 

paragraph (a) of this section.

§ 96.121 Submission of CAIR permit 

applications. 

(a) Duty to apply. The CAIR 

designated representative of any CAIR 

NOX source required to have a title V 

operating permit shall submit to the 

permitting authority a complete CAIR 

permit application under § 96.122 for 

the source covering each CAIR NOX unit 

at the source at least 18 months (or such 

lesser time provided by the permitting 

authority) before the later of January 1, 

2009 or the date on which the CAIR 

NOX unit commences operation.

(b) Duty to Reapply. For a CAIR NOX

source required to have a title V 

operating permit, the CAIR designated 

representative shall submit a complete 

CAIR permit application under § 96.122 

for the source covering each CAIR NOX

unit at the source to renew the CAIR 

permit in accordance with the 

permitting authority’s title V operating 

permits regulations addressing permit 

renewal.

§ 96.122 Information requirements for 

CAIR permit applications. 

A complete CAIR permit application 

shall include the following elements 

concerning the CAIR NOX source for 

which the application is submitted, in a 

format prescribed by the permitting 

authority: 

(a) Identification of the CAIR NOX

source; 

(b) Identification of each CAIR NOX

unit at the CAIR NOX source; and 

(c) The standard requirements under 

§ 96.106.

§ 96.123 CAIR permit contents and term. 

(a) Each CAIR permit will contain, in 

a format prescribed by the permitting 

authority, all elements required for a 

complete CAIR permit application 

under § 96.122. 

(b) Each CAIR permit is deemed to 

incorporate automatically the 

definitions of terms under § 96.102 and, 

upon recordation by the Administrator 

under subpart FF, GG, or II of this part, 

every allocation, transfer, or deduction 

of a CAIR NOX allowance to or from the 

compliance account of the CAIR NOX

source covered by the permit. 

(c) The term of the CAIR permit will 

be set by the permitting authority, as 

necessary to facilitate coordination of 

the renewal of the CAIR permit with 

issuance, revision, or renewal of the 

CAIR NOX source’s title V operating 

permit or other federally enforceable 

permit as applicable.

§ 96.124 CAIR permit revisions. 

Except as provided in § 96.123(b), the 

permitting authority will revise the 

CAIR permit, as necessary, in 

accordance with the permitting 

authority’s title V operating permits 

regulations or the permitting authority’s 

regulations for other federally 

enforceable permits as applicable 

addressing permit revisions.

Subpart DD—[Reserved]

Subpart EE—CAIR NOX Allowance 

Allocations

§ 96.140 State trading budgets. 

The State trading budgets for annual 

allocations of CAIR NOX allowances for 

the control periods in 2009 through 

2014 and in 2015 and thereafter are 

respectively as follows:

State State trading budget 

for 2009–2014 (tons) 

State trading budget 

for 2015 and thereafter (tons) 

Alabama ........................................................................................................................................... 69,020 57,517 

District of Columbia ......................................................................................................................... 144 120 

Florida .............................................................................................................................................. 99,445 82,871 

Georgia ............................................................................................................................................ 66,321 55,268 

Illinois ............................................................................................................................................... 76,230 63,525 

Indiana ............................................................................................................................................. 108,935 90,779 

Iowa ................................................................................................................................................. 32,692 27,243 

Kentucky .......................................................................................................................................... 83,205 69,337 

Louisiana .......................................................................................................................................... 35,512 29,593 

Maryland .......................................................................................................................................... 27,724 23,104 

Michigan ........................................................................................................................................... 65,304 54,420 

Minnesota ........................................................................................................................................ 31,443 26,203 

Mississippi ........................................................................................................................................ 17,807 14,839 

Missouri ............................................................................................................................................ 59,871 49,892 

New York ......................................................................................................................................... 45,617 38,014 

North Carolina .................................................................................................................................. 62,183 51,819 

Ohio ................................................................................................................................................. 108,667 90,556 

Pennsylvania .................................................................................................................................... 99,049 82,541 

South Carolina ................................................................................................................................. 32,662 27,219 

Tennessee ....................................................................................................................................... 50,973 42,478 

Texas ............................................................................................................................................... 181,014 150,845 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25349

State State trading budget 

for 2009–2014 (tons) 

State trading budget 

for 2015 and thereafter (tons) 

Virginia ............................................................................................................................................. 36,074 30,062 

West Virginia .................................................................................................................................... 74,220 61,850 

Wisconsin ......................................................................................................................................... 40,759 33,966 

§ 96.141 Timing requirements for CAIR 

NOX allowance allocations. 

(a) By October 31, 2006, the 

permitting authority will submit to the 

Administrator the CAIR NOX allowance 

allocations, in a format prescribed by 

the Administrator and in accordance 

with § 96.142(a) and (b), for the control 

periods in 2009, 2010, 2011, 2012, 2013, 

and 2014. 

(b)(1) By October 31, 2009 and 

October 31 of each year thereafter, the 

permitting authority will submit to the 

Administrator the CAIR NOX allowance 

allocations, in a format prescribed by 

the Administrator and in accordance 

with § 96.142(a) and (b), for the control 

period in the sixth year after the year of 

the applicable deadline for submission 

under this paragraph.

(2) If the permitting authority fails to 

submit to the Administrator the CAIR 

NOX allowance allocations in 

accordance with paragraph (b)(1) of this 

section, the Administrator will assume 

that the allocations of CAIR NOX

allowances for the applicable control 

period are the same as for the control 

period that immediately precedes the 

applicable control period, except that, if 

the applicable control period is in 2015, 

the Administrator will assume that the 

allocations equal 83 percent of the 

allocations for the control period that 

immediately precedes the applicable 

control period. 

(c)(1) By October 31, 2009 and 

October 31 of each year thereafter, the 

permitting authority will submit to the 

Administrator the CAIR NOX allowance 

allocations, in a format prescribed by 

the Administrator and in accordance 

with § 96.142(a), (c), and (d), for the 

control period in the year of the 

applicable deadline for submission 

under this paragraph. 

(2) If the permitting authority fails to 

submit to the Administrator the CAIR 

NOX allowance allocations in 

accordance with paragraph (c)(1) of this 

section, the Administrator will assume 

that the allocations of CAIR NOX

allowances for the applicable control 

period are the same as for the control 

period that immediately precedes the 

applicable control period, except that, if 

the applicable control period is in 2015, 

the Administrator will assume that the 

allocations equal 83 percent of the 

allocations for the control period that 

immediately precedes the applicable 

control period and except that any CAIR 

NOX unit that would otherwise be 

allocated CAIR NOX allowances under 

§ 96.142(a) and (b), as well as under 

§ 96.142(a), (c), and (d), for the 

applicable control period will be 

assumed to be allocated no CAIR NOX

allowances under § 96.142(a), (c), and 

(d) for the applicable control period.

§ 96.142 CAIR NOX allowance allocations. 

(a)(1) The baseline heat input (in 

mmBtu) used with respect to CAIR NOX

allowance allocations under paragraph 

(b) of this section for each CAIR NOX

unit will be: 

(i) For units commencing operation 

before January 1, 2001 the average of the 

3 highest amounts of the unit’s adjusted 

control period heat input for 2000 

through 2004, with the adjusted control 

period heat input for each year 

calculated as follows: 

(A) If the unit is coal-fired during the 

year, the unit’s control period heat input 

for such year is multiplied by 100 

percent; 

(B) If the unit is oil-fired during the 

year, the unit’s control period heat input 

for such year is multiplied by 60 

percent; and 

(C) If the unit is not subject to 

paragraph (a)(1)(i)(A) or (B) of this 

section, the unit’s control period heat 

input for such year is multiplied by 40 

percent.

(ii) For units commencing operation 

on or after January 1, 2001 and 

operating each calendar year during a 

period of 5 or more consecutive 

calendar years, the average of the 3 

highest amounts of the unit’s total 

converted control period heat input over 

the first such 5 years. 

(2)(i) A unit’s control period heat 

input, and a unit’s status as coal-fired or 

oil-fired, for a calendar year under 

paragraph (a)(1)(i) of this section, and a 

unit’s total tons of NOX emissions 

during a calendar year under paragraph 

(c)(3) of this section, will be determined 

in accordance with part 75 of this 

chapter, to the extent the 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, to the extent the unit was not 

otherwise subject to the requirements of 

part 75 of this chapter for the year. 

(ii) A unit’s converted control period 

heat input for a calendar year specified 

under paragraph (a)(1)(ii) of this section 

equals: 

(A) Except as provided in paragraph 

(a)(2)(ii)(B) or (C) of this section, the 

control period gross electrical output of 

the generator or generators served by the 

unit multiplied by 7,900 Btu/kWh, if the 

unit is coal-fired for the year, or 6,675 

Btu/kWh, if the unit is not coal-fired for 

the year, and divided by 1,000,000 Btu/

mmBtu, provided that if a generator is 

served by 2 or more units, then the gross 

electrical output of the generator will be 

attributed to each unit in proportion to 

the unit’s share of the total control 

period heat input of such units for the 

year; 

(B) For a unit that is a boiler and has 

equipment used to produce electricity 

and useful thermal energy for industrial, 

commercial, heating, or cooling 

purposes through the sequential use of 

energy, the total heat energy (in Btu) of 

the steam produced by the boiler during 

the control period, divided by 0.8 and 

by 1,000,000 Btu/mmBtu; or 

(C) For a unit that is a combustion 

turbine and has equipment used to 

produce electricity and useful thermal 

energy for industrial, commercial, 

heating, or cooling purposes through the 

sequential use of energy, the control 

period gross electrical output of the 

enclosed device comprising the 

compressor, combustor, and turbine 

multiplied by 3,414 Btu/kWh, plus the 

total heat energy (in Btu) of the steam 

produced by any associated heat 

recovery steam generator during the 

control period divided by 0.8, and with 

the sum divided by 1,000,000 Btu/

mmBtu. 

(b)(1) For each control period in 2009 

and thereafter, the permitting authority 

will allocate to all CAIR NOX units in 

the State that have a baseline heat input 

(as determined under paragraph (a) of 

this section) a total amount of CAIR 

NOX allowances equal to 95 percent for 

a control period during 2009 through 

2014, and 97 percent for a control 

period during 2015 and thereafter, of the 

tons of NOX emissions in the State 

trading budget under § 96.140 (except as 

provided in paragraph (d) of this 

section). 

25350 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

(2) The permitting authority will 

allocate CAIR NOX allowances to each 

CAIR NOX unit under paragraph (b)(1) 

of this section in an amount determined 

by multiplying the total amount of CAIR 

NOX allowances allocated under 

paragraph (b)(1) of this section by the 

ratio of the baseline heat input of such 

CAIR NOX unit to the total amount of 

baseline heat input of all such CAIR 

NOX units in the State and rounding to 

the nearest whole allowance as 

appropriate. 

(c) For each control period in 2009 

and thereafter, the permitting authority 

will allocate CAIR NOX allowances to 

CAIR NOX units in the State that 

commenced operation on or after 

January 1, 2001 and do not yet have a 

baseline heat input (as determined 

under paragraph (a) of this section), in 

accordance with the following 

procedures: 

(1) The permitting authority will 

establish a separate new unit set-aside 

for each control period. Each new unit 

set-aside will be allocated CAIR NOX

allowances equal to 5 percent for a 

control period in 2009 through 2013, 

and 3 percent for a control period in 

2014 and thereafter, of the amount of 

tons of NOX emissions in the State 

trading budget under § 96.140. 

(2) The CAIR designated 

representative of such a CAIR NOX unit 

may submit to the permitting authority 

a request, in a format specified by the 

permitting authority, to be allocated 

CAIR NOX allowances, starting with the 

later of the control period in 2009 or the 

first control period after the control 

period in which the CAIR NOX unit 

commences commercial operation and 

until the first control period for which 

the unit is allocated CAIR NOX

allowances under paragraph (b) of this 

section. The CAIR NOX allowance 

allocation request must be submitted on 

or before July 1 of the first control 

period for which the CAIR NOX

allowances are requested and after the 

date on which the CAIR NOX unit 

commences commercial operation. 

(3) In a CAIR NOX allowance 

allocation request under paragraph 

(c)(2) of this section, the CAIR 

designated representative may request 

for a control period CAIR NOX

allowances in an amount not exceeding 

the CAIR NOX unit’s total tons of NOX

emissions during the calendar year 

immediately before such control period. 

(4) The permitting authority will 

review each CAIR NOX allowance 

allocation request under paragraph 

(c)(2) of this section and will allocate 

CAIR NOX allowances for each control 

period pursuant to such request as 

follows:

(i) The permitting authority will 

accept an allowance allocation request 

only if the request meets, or is adjusted 

by the permitting authority as necessary 

to meet, the requirements of paragraphs 

(c)(2) and (3) of this section. 

(ii) On or after July 1 of the control 

period, the permitting authority will 

determine the sum of the CAIR NOX

allowances requested (as adjusted under 

paragraph (c)(4)(i) of this section) in all 

allowance allocation requests accepted 

under paragraph (c)(4)(i) of this section 

for the control period. 

(iii) If the amount of CAIR NOX

allowances in the new unit set-aside for 

the control period is greater than or 

equal to the sum under paragraph 

(c)(4)(ii) of this section, then the 

permitting authority will allocate the 

amount of CAIR NOX allowances 

requested (as adjusted under paragraph 

(c)(4)(i) of this section) to each CAIR 

NOX unit covered by an allowance 

allocation request accepted under 

paragraph (c)(4)(i) of this section. 

(iv) If the amount of CAIR NOX

allowances in the new unit set-aside for 

the control period is less than the sum 

under paragraph (c)(4)(ii) of this section, 

then the permitting authority will 

allocate to each CAIR NOX unit covered 

by an allowance allocation request 

accepted under paragraph (c)(4)(i) of 

this section the amount of the CAIR 

NOX allowances requested (as adjusted 

under paragraph (c)(4)(i) of this section), 

multiplied by the amount of CAIR NOX

allowances in the new unit set-aside for 

the control period, divided by the sum 

determined under paragraph (c)(4)(ii) of 

this section, and rounded to the nearest 

whole allowance as appropriate. 

(v) The permitting authority will 

notify each CAIR designated 

representative that submitted an 

allowance allocation request of the 

amount of CAIR NOX allowances (if 

any) allocated for the control period to 

the CAIR NOX unit covered by the 

request. 

(d) If, after completion of the 

procedures under paragraph (c)(4) of 

this section for a control period, any 

unallocated CAIR NOX allowances 

remain in the new unit set-aside for the 

control period, the permitting authority 

will allocate to each CAIR NOX unit that 

was allocated CAIR NOX allowances 

under paragraph (b) of this section an 

amount of CAIR NOX allowances equal 

to the total amount of such remaining 

unallocated CAIR NOX allowances, 

multiplied by the unit’s allocation 

under paragraph (b) of this section, 

divided by 95 percent for a control 

period during 2009 through 2014, and 

97 percent for a control period during 

2015 and thereafter, of the amount of 

tons of NOX emissions in the State 

trading budget under § 96.140, and 

rounded to the nearest whole allowance 

as appropriate.

§ 96.143 Compliance supplement pool. 

(a) In addition to the CAIR NOX

allowances allocated under § 96.142, the 

permitting authority may allocate for the 

control period in 2009 up to the 

following amount of CAIR NOX

allowances to CAIR NOX units in the 

respective State:

State 

Compliance

supplement 

pool 

Alabama .................................... 10,166 

District Of Columbia ................. 0 

Florida ....................................... 8,335 

Georgia ..................................... 12,397 

Illinois ........................................ 11,299 

Indiana ...................................... 20,155 

Iowa .......................................... 6,978 

Kentucky ................................... 14,935 

Louisiana .................................. 2,251 

Maryland ................................... 4,670 

Michigan ................................... 8,347 

Minnesota ................................. 6,528 

Mississippi ................................ 3,066 

Missouri .................................... 9,044 

New York .................................. 0 

North Carolina .......................... 0 

Ohio .......................................... 25,037 

Pennsylvania ............................ 16,009 

South Carolina .......................... 2,600 

Tennessee ................................ 8,944 

Texas ........................................ 772 

Virginia ...................................... 5,134 

West Virginia ............................ 16,929 

Wisconsin ................................. 4,898 

(b) For any CAIR NOX unit in the 

State that achieves NOX emission 

reductions in 2007 and 2008 that are not 

necessary to comply with any State or 

federal emissions limitation applicable 

during such years, the CAIR designated 

representative of the unit may request 

early reduction credits, and allocation of 

CAIR NOX allowances from the 

compliance supplement pool under 

paragraph (a) of this section for such 

early reduction credits, in accordance 

with the following: 

(1) The owners and operators of such 

CAIR NOX unit shall monitor and report 

the NOX emissions rate and the heat 

input of the unit in accordance with 

subpart HH of this part in each control 

period for which early reduction credit 

is requested. 

(2) The CAIR designated 

representative of such CAIR NOX unit 

shall submit to the permitting authority 

by July 1, 2009 a request, in a format 

specified by the permitting authority, 

for allocation of an amount of CAIR 

NOX allowances from the compliance 

supplement pool not exceeding the sum 

of the amounts (in tons) of the unit’s 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25351

NOX emission reductions in 2007 and 

2008 that are not necessary to comply 

with any State or federal emissions 

limitation applicable during such years, 

determined in accordance with subpart 

HH of this part. 

(c) For any CAIR NOX unit in the 

State whose compliance with CAIR NOX

emissions limitation for the control 

period in 2009 would create an undue 

risk to the reliability of electricity 

supply during such control period, the 

CAIR designated representative of the 

unit may request the allocation of CAIR 

NOX allowances from the compliance 

supplement pool under paragraph (a) of 

this section, in accordance with the 

following:

(1) The CAIR designated 

representative of such CAIR NOX unit 

shall submit to the permitting authority 

by July 1, 2009 a request, in a format 

specified by the permitting authority, 

for allocation of an amount of CAIR 

NOX allowances from the compliance 

supplement pool not exceeding the 

minimum amount of CAIR NOX

allowances necessary to remove such 

undue risk to the reliability of electricity 

supply. 

(2) In the request under paragraph 

(c)(1) of this section, the CAIR 

designated representative of such CAIR 

NOX unit shall demonstrate that, in the 

absence of allocation to the unit of the 

amount of CAIR NOX allowances 

requested, the unit’s compliance with 

CAIR NOX emissions limitation for the 

control period in 2009 would create an 

undue risk to the reliability of electricity 

supply during such control period. This 

demonstration must include a showing 

that it would not be feasible for the 

owners and operators of the unit to: 

(i) Obtain a sufficient amount of 

electricity from other electricity 

generation facilities, during the 

installation of control technology at the 

unit for compliance with the CAIR NOX

emissions limitation, to prevent such 

undue risk; or 

(ii) Obtain under paragraphs (b) and 

(d) of this section, or otherwise obtain, 

a sufficient amount of CAIR NOX

allowances to prevent such undue risk. 

(d) The permitting authority will 

review each request under paragraph (b) 

or (c) of this section submitted by July 

1, 2009 and will allocate CAIR NOX

allowances for the control period in 

2009 to CAIR NOX units in the State and 

covered by such request as follows: 

(1) Upon receipt of each such request, 

the permitting authority will make any 

necessary adjustments to the request to 

ensure that the amount of the CAIR NOX

allowances requested meets the 

requirements of paragraph (b) or (c) of 

this section. 

(2) If the State’s compliance 

supplement pool under paragraph (a) of 

this section has an amount of CAIR NOX

allowances not less than the total 

amount of CAIR NOX allowances in all 

such requests (as adjusted under 

paragraph (d)(1) of this section), the 

permitting authority will allocate to 

each CAIR NOX unit covered by such 

requests the amount of CAIR NOX

allowances requested (as adjusted under 

paragraph (d)(1) of this section). 

(3) If the State’s compliance 

supplement pool under paragraph (a) of 

this section has a smaller amount of 

CAIR NOX allowances than the total 

amount of CAIR NOX allowances in all 

such requests (as adjusted under 

paragraph (d)(1) of this section), the 

permitting authority will allocate CAIR 

NOX allowances to each CAIR NOX unit 

covered by such requests according to 

the following formula and rounding to 

the nearest whole allowance as 

appropriate:

Unit’s allocation = Unit’s adjusted 

allocation × (State’s compliance 

supplement pool ÷ Total adjusted 

allocations for all units)

Where:

‘‘Unit’s allocation’’ is the number of 

CAIR NOX allowances allocated to the 

unit from the State’s compliance 

supplement pool. Unit’s adjusted 

allocation’’ is the amount of CAIR NOX

allowances requested for the unit under 

paragraph (b) or (c) of this section, as 

adjusted under paragraph (d)(1) of this 

section. ‘‘State’s compliance 

supplement pool’’ is the amount of 

CAIR NOX allowances in the State’s 

compliance supplement pool. ‘‘Total 

adjusted allocations for all units’’ is the 

sum of the amounts of allocations 

requested for all units under paragraph 

(b) or (c) of this section, as adjusted 

under paragraph (d)(1) of this section. 

(4) By November 30, 2009, the 

permitting authority will determine, and 

submit to the Administrator, the 

allocations under paragraph (d)(3) or (4) 

of this section. 

(5) By January 1, 2010, the 

Administrator will record the 

allocations under paragraph (d)(5) of 

this section.

Subpart FF—CAIR NOX Allowance 

Tracking System

§ 96.150 [Reserved]

§ 96.151 Establishment of accounts. 

(a) Compliance accounts. Except as 

provided in § 96.184(e), upon receipt of 

a complete certificate of representation 

under § 96.113, the Administrator will 

establish a compliance account for the 

CAIR NOX source for which the 

certificate of representation was 

submitted unless the source already has 

a compliance account. 

(b) General accounts. (1) Application 

for general account.

(i) Any person may apply to open a 

general account for the purpose of 

holding and transferring CAIR NOX

allowances. An application for a general 

account may designate one and only one 

CAIR authorized account representative 

and one and only one alternate CAIR 

authorized account representative who 

may act on behalf of the CAIR 

authorized account representative. The 

agreement by which the alternate CAIR 

authorized account representative is 

selected shall include a procedure for 

authorizing the alternate CAIR 

authorized account representative to act 

in lieu of the CAIR authorized account 

representative. 

(ii) A complete application for a 

general account shall be submitted to 

the Administrator and shall include the 

following elements in a format 

prescribed by the Administrator: 

(A) Name, mailing address, e-mail 

address (if any), telephone number, and 

facsimile transmission number (if any) 

of the CAIR authorized account 

representative and any alternate CAIR 

authorized account representative; 

(B) Organization name and type of 

organization, if applicable;

(C) A list of all persons subject to a 

binding agreement for the CAIR 

authorized account representative and 

any alternate CAIR authorized account 

representative to represent their 

ownership interest with respect to the 

CAIR NOX allowances held in the 

general account; 

(D) The following certification 

statement by the CAIR authorized 

account representative and any alternate 

CAIR authorized account representative: 

‘‘I certify that I was selected as the CAIR 

authorized account representative or the 

alternate CAIR authorized account 

representative, as applicable, by an 

agreement that is binding on all persons 

who have an ownership interest with 

respect to CAIR NOX allowances held in 

the general account. I certify that I have 

all the necessary authority to carry out 

my duties and responsibilities under the 

CAIR NOX Annual Trading Program on 

behalf of such persons and that each 

such person shall be fully bound by my 

representations, actions, inactions, or 

submissions and by any order or 

decision issued to me by the 

Administrator or a court regarding the 

general account.’’

(E) The signature of the CAIR 

authorized account representative and 

any alternate CAIR authorized account 

representative and the dates signed. 

25352 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

(iii) Unless otherwise required by the 

permitting authority or the 

Administrator, documents of agreement 

referred to in the application for a 

general account shall not be submitted 

to the permitting authority or the 

Administrator. Neither the permitting 

authority nor the Administrator shall be 

under any obligation to review or 

evaluate the sufficiency of such 

documents, if submitted. 

(2) Authorization of CAIR authorized 

account representative.

(i) Upon receipt by the Administrator 

of a complete application for a general 

account under paragraph (b)(1) of this 

section: 

(A) The Administrator will establish a 

general account for the person or 

persons for whom the application is 

submitted. 

(B) The CAIR authorized account 

representative and any alternate CAIR 

authorized account representative for 

the general account shall represent and, 

by his or her representations, actions, 

inactions, or submissions, legally bind 

each person who has an ownership 

interest with respect to CAIR NOX

allowances held in the general account 

in all matters pertaining to the CAIR 

NOX Annual Trading Program, 

notwithstanding any agreement between 

the CAIR authorized account 

representative or any alternate CAIR 

authorized account representative and 

such person. Any such person shall be 

bound by any order or decision issued 

to the CAIR authorized account 

representative or any alternate CAIR 

authorized account representative by 

the Administrator or a court regarding 

the general account. 

(C) Any representation, action, 

inaction, or submission by any alternate 

CAIR authorized account representative 

shall be deemed to be a representation, 

action, inaction, or submission by the 

CAIR authorized account representative.

(ii) Each submission concerning the 

general account shall be submitted, 

signed, and certified by the CAIR 

authorized account representative or 

any alternate CAIR authorized account 

representative for the persons having an 

ownership interest with respect to CAIR 

NOX allowances held in the general 

account. Each such submission shall 

include the following certification 

statement by the CAIR authorized 

account representative or any alternate 

CAIR authorized account representative: 

‘‘I am authorized to make this 

submission on behalf of the persons 

having an ownership interest with 

respect to the CAIR NOX allowances 

held in the general account. I certify 

under penalty of law that I have 

personally examined, and am familiar 

with, the statements and information 

submitted in this document and all its 

attachments. Based on my inquiry of 

those individuals with primary 

responsibility for obtaining the 

information, I certify that the statements 

and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’

(iii) 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)(ii) of 

this section. 

(3) Changing CAIR authorized 

account representative and alternate 

CAIR authorized account 

representative; changes in persons with 

ownership interest.

(i) The CAIR authorized account 

representative for a general account may 

be changed at any time upon receipt by 

the Administrator of a superseding 

complete application for a general 

account under paragraph (b)(1) of this 

section. Notwithstanding any such 

change, all representations, actions, 

inactions, and submissions by the 

previous CAIR authorized account 

representative before the time and date 

when the Administrator receives the 

superseding application for a general 

account shall be binding on the new 

CAIR authorized account representative 

and the persons with an ownership 

interest with respect to the CAIR NOX

allowances in the general account. 

(ii) The alternate CAIR authorized 

account representative for a general 

account may be changed at any time 

upon receipt by the Administrator of a 

superseding complete application for a 

general account under paragraph (b)(1) 

of this section. Notwithstanding any 

such change, all representations, 

actions, inactions, and submissions by 

the previous alternate CAIR authorized 

account representative before the time 

and date when the Administrator 

receives the superseding application for 

a general account shall be binding on 

the new alternate CAIR authorized 

account representative and the persons 

with an ownership interest with respect 

to the CAIR NOX allowances in the 

general account. 

(iii)(A) In the event a new person 

having an ownership interest with 

respect to CAIR NOX allowances in the 

general account is not included in the 

list of such persons in the application 

for a general account, such new person 

shall be deemed to be subject to and 

bound by the application for a general 

account, the representation, actions, 

inactions, and submissions of the CAIR 

authorized account representative and 

any alternate CAIR authorized account 

representative of the account, and the 

decisions and orders of the 

Administrator or a court, as if the new 

person were included in such list. 

(B) Within 30 days following any 

change in the persons having an 

ownership interest with respect to CAIR 

NOX allowances in the general account, 

including the addition of persons, the 

CAIR authorized account representative 

or any alternate CAIR authorized 

account representative shall submit a 

revision to the application for a general 

account amending the list of persons 

having an ownership interest with 

respect to the CAIR NOX allowances in 

the general account to include the 

change. 

(4) Objections concerning CAIR 

authorized account representative.

(i) Once a complete application for a 

general account under paragraph (b)(1) 

of this section has been submitted and 

received, the Administrator will rely on 

the application unless and until a 

superseding complete application for a 

general account under paragraph (b)(1) 

of this section is received by the 

Administrator. 

(ii) Except as provided in paragraph 

(b)(3)(i) or (ii) of this section, no 

objection or other communication 

submitted to the Administrator 

concerning the authorization, or any 

representation, action, inaction, or 

submission of the CAIR authorized 

account representative or any 

alternative CAIR authorized account 

representative for a general account 

shall affect any representation, action, 

inaction, or submission of the CAIR 

authorized account representative or 

any alternative CAIR authorized account 

representative or the finality of any 

decision or order by the Administrator 

under the CAIR NOX Annual Trading 

Program. 

(iii) The Administrator will not 

adjudicate any private legal dispute 

concerning the authorization or any 

representation, action, inaction, or 

submission of the CAIR authorized 

account representative or any 

alternative CAIR authorized account 

representative for a general account, 

including private legal disputes 

concerning the proceeds of CAIR NOX

allowance transfers.

(c) Account identification. The 

Administrator will assign a unique 

identifying number to each account 

established under paragraph (a) or (b) of 

this section.

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25353

§ 96.152 Responsibilities of CAIR 

authorized account representative. 

Following the establishment of a 

CAIR NOX Allowance Tracking System 

account, all submissions to the 

Administrator pertaining to the account, 

including, but not limited to, 

submissions concerning the deduction 

or transfer of CAIR NOX allowances in 

the account, shall be made only by the 

CAIR authorized account representative 

for the account.

§ 96.153 Recordation of CAIR NOX

allowance allocations. 

(a) By December 1, 2006, the 

Administrator will record in the CAIR 

NOX source’s compliance account the 

CAIR NOX allowances allocated for the 

CAIR NOX units at a source, as 

submitted by the permitting authority in 

accordance with § 96.141(a), for the 

control periods in 2009, 2010, 2011, 

2012, 2013, and 2014. 

(b) By December 1, 2009, the 

Administrator will record in the CAIR 

NOX source’s compliance account the 

CAIR NOX allowances allocated for the 

CAIR NOX units at the source, as 

submitted by the permitting authority or 

as determined by the Administrator in 

accordance with § 96.141(b), for the 

control period in 2015. 

(c) In 2011 and each year thereafter, 

after the Administrator has made all 

deductions (if any) from a CAIR NOX

source’s compliance account under 

§ 96.154, the Administrator will record 

in the CAIR NOX source’s compliance 

account the CAIR NOX allowances 

allocated for the CAIR NOX units at the 

source, as submitted by the permitting 

authority or determined by the 

Administrator in accordance with 

§ 96.141(b), for the control period in the 

sixth year after the year of the control 

period for which such deductions were 

or could have been made. 

(d) By December 1, 2009 and 

December 1 of each year thereafter, the 

Administrator will record in the CAIR 

NOX source’s compliance account the 

CAIR NOX allowances allocated for the 

CAIR NOX units at the source, as 

submitted by the permitting authority or 

determined by the Administrator in 

accordance with § 96.141(c), for the 

control period in the year of the 

applicable deadline for recordation 

under this paragraph. 

(e) Serial numbers for allocated CAIR 

NOX allowances. When recording the 

allocation of CAIR NOX allowances for 

a CAIR NOX unit in a compliance 

account, the Administrator will assign 

each CAIR NOX allowance a unique 

identification number that will include 

digits identifying the year of the control 

period for which the CAIR NOX

allowance is allocated.

§ 96.154 Compliance with CAIR NOX

emissions limitation. 

(a) Allowance transfer deadline. The 

CAIR NOX allowances are available to 

be deducted for compliance with a 

source’s CAIR NOX emissions limitation 

for a control period in a given calendar 

year only if the CAIR NOX allowances: 

(1) Were allocated for the control 

period in the year or a prior year; 

(2) Are held in the compliance 

account as of the allowance transfer 

deadline for the control period or are 

transferred into the compliance account 

by a CAIR NOX allowance transfer 

correctly submitted for recordation 

under § 96.160 by the allowance transfer 

deadline for the control period; and 

(3) Are not necessary for deductions 

for excess emissions for a prior control 

period under paragraph (d) of this 

section. 

(b) Deductions for compliance.

Following the recordation, in 

accordance with § 96.161, of CAIR NOX

allowance transfers submitted for 

recordation in a source’s compliance 

account by the allowance transfer 

deadline for a control period, the 

Administrator will deduct from the 

compliance account CAIR NOX

allowances available under paragraph 

(a) of this section in order to determine 

whether the source meets the CAIR NOX

emissions limitation for the control 

period, as follows: 

(1) Until the amount of CAIR NOX

allowances deducted equals the number 

of tons of total nitrogen oxides 

emissions, determined in accordance 

with subpart HH of this part, from all 

CAIR NOX units at the source for the 

control period; or 

(2) If there are insufficient CAIR NOX

allowances to complete the deductions 

in paragraph (b)(1) of this section, until 

no more CAIR NOX allowances available 

under paragraph (a) of this section 

remain in the compliance account. 

(c)(1) Identification of CAIR NOX

allowances by serial number. The CAIR 

authorized account representative for a 

source’s compliance account may 

request that specific CAIR NOX

allowances, identified by serial number, 

in the compliance account be deducted 

for emissions or excess emissions for a 

control period in accordance with 

paragraph (b) or (d) of this section. Such 

request shall be submitted to the 

Administrator by the allowance transfer 

deadline for the control period and 

include, in a format prescribed by the 

Administrator, the identification of the 

CAIR NOX source and the appropriate 

serial numbers. 

(2) First-in, first-out. The 

Administrator will deduct CAIR NOX

allowances under paragraph (b) or (d) of 

this section from the source’s 

compliance account, in the absence of 

an identification or in the case of a 

partial identification of CAIR NOX

allowances by serial number under 

paragraph (c)(1) of this section, on a 

first-in, first-out (FIFO) accounting basis 

in the following order: 

(i) Any CAIR NOX allowances that 

were allocated to the units at the source, 

in the order of recordation; and then

(ii) Any CAIR NOX allowances that 

were allocated to any unit and 

transferred and recorded in the 

compliance account pursuant to subpart 

GG of this part, in the order of 

recordation. 

(d) Deductions for excess emissions.

(1) After making the deductions for 

compliance under paragraph (b) of this 

section for a control period in a calendar 

year in which the CAIR NOX source has 

excess emissions, the Administrator will 

deduct from the source’s compliance 

account an amount of CAIR NOX

allowances, allocated for the control 

period in the immediately following 

calendar year, equal to 3 times the 

number of tons of the source’s excess 

emissions. 

(2) Any allowance deduction required 

under paragraph (d)(1) of this section 

shall not affect the liability of the 

owners and operators of the CAIR NOX

source or the CAIR NOX units at the 

source for any fine, penalty, or 

assessment, or their obligation to 

comply with any other remedy, for the 

same violations, as ordered under the 

Clean Air Act or applicable State law. 

(e) Recordation of deductions. The 

Administrator will record in the 

appropriate compliance account all 

deductions from such an account under 

paragraph (b) or (d) of this section. 

(f) Administrator’s action on 

submissions.

(1) The Administrator may review and 

conduct independent audits concerning 

any submission under the CAIR NOX

Annual Trading Program and make 

appropriate adjustments of the 

information in the submissions. 

(2) The Administrator may deduct 

CAIR NOX allowances from or transfer 

CAIR NOX allowances to a source’s 

compliance account based on the 

information in the submissions, as 

adjusted under paragraph (f)(1) of this 

section.

§ 96.155 Banking. 

(a) CAIR NOX allowances may be 

banked for future use or transfer in a 

compliance account or a general 

25354 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

account in accordance with paragraph 

(b) of this section. 

(b) Any CAIR NOX allowance that is 

held in a compliance account or a 

general account will remain in such 

account unless and until the CAIR NOX

allowance is deducted or transferred 

under § 96.154, § 96.156, or subpart GG 

of this part.

§ 96.156 Account error. 

The Administrator may, at his or her 

sole discretion and on his or her own 

motion, correct any error in any CAIR 

NOX Allowance Tracking System 

account. Within 10 business days of 

making such correction, the 

Administrator will notify the CAIR 

authorized account representative for 

the account.

§ 96.157 Closing of general accounts. 

(a) The CAIR authorized account 

representative of a general account may 

submit to the Administrator a request to 

close the account, which shall include 

a correctly submitted allowance transfer 

under § 96.160 for any CAIR NOX

allowances in the account to one or 

more other CAIR NOX Allowance 

Tracking System accounts. 

(b) If a general account has no 

allowance transfers in or out of the 

account for a 12-month period or longer 

and does not contain any CAIR NOX

allowances, the Administrator may 

notify the CAIR authorized account 

representative for the account that the 

account will be closed following 20 

business days after the notice is sent. 

The account will be closed after the 20-

day period unless, before the end of the 

20-day period, the Administrator 

receives a correctly submitted transfer of 

CAIR NOX allowances into the account 

under § 96.160 or a statement submitted 

by the CAIR authorized account 

representative demonstrating to the 

satisfaction of the Administrator good 

cause as to why the account should not 

be closed.

Subpart GG—CAIR NOX Allowance 

Transfers

§ 96.160 Submission of CAIR NOX

allowance transfers. 

A CAIR authorized account 

representative seeking recordation of a 

CAIR NOX allowance transfer shall 

submit the transfer to the Administrator. 

To be considered correctly submitted, 

the CAIR NOX allowance transfer shall 

include the following elements, in a 

format specified by the Administrator: 

(a) The account numbers for both the 

transferor and transferee accounts; 

(b) The serial number of each CAIR 

NOX allowance that is in the transferor 

account and is to be transferred; and

(c) The name and signature of the 

CAIR authorized account representative 

of the transferor account and the date 

signed.

§ 96.161 EPA recordation. 

(a) Within 5 business days (except as 

provided in paragraph (b) of this 

section) of receiving a CAIR NOX

allowance transfer, the Administrator 

will record a CAIR NOX allowance 

transfer by moving each CAIR NOX

allowance from the transferor account to 

the transferee account as specified by 

the request, provided that: 

(1) The transfer is correctly submitted 

under § 96.160; and 

(2) The transferor account includes 

each CAIR NOX allowance identified by 

serial number in the transfer. 

(b) A CAIR NOX allowance transfer 

that is submitted for recordation after 

the allowance transfer deadline for a 

control period and that includes any 

CAIR NOX allowances allocated for any 

control period before such allowance 

transfer deadline will not be recorded 

until after the Administrator completes 

the deductions under § 96.154 for the 

control period immediately before such 

allowance transfer deadline. 

(c) Where a CAIR NOX allowance 

transfer submitted for recordation fails 

to meet the requirements of paragraph 

(a) of this section, the Administrator 

will not record such transfer.

§ 96.162 Notification. 

(a) Notification of recordation. Within 

5 business days of recordation of a CAIR 

NOX allowance transfer under § 96.161, 

the Administrator will notify the CAIR 

authorized account representatives of 

both the transferor and transferee 

accounts. 

(b) Notification of non-recordation.

Within 10 business days of receipt of a 

CAIR NOX allowance transfer that fails 

to meet the requirements of § 96.161(a), 

the Administrator will notify the CAIR 

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 CAIR NOX

allowance transfer for recordation 

following notification of nonrecordation.

Subpart HH—Monitoring and 

Reporting

§ 96.170 General requirements. 

The owners and operators, and to the 

extent applicable, the CAIR designated 

representative, of a CAIR NOX unit, 

shall comply with the monitoring, 

recordkeeping, and reporting 

requirements as provided in this subpart 

and in subpart H of part 75 of this 

chapter. For purposes of complying 

with such requirements, the definitions 

in § 96.102 and in § 72.2 of this chapter 

shall apply, and the terms ‘‘affected 

unit,’’ ‘‘designated representative,’’ and 

‘‘continuous emission monitoring 

system’’ (or ‘‘CEMS’’) in part 75 of this 

chapter shall be deemed to refer to the 

terms ‘‘CAIR NOX unit,’’ ‘‘CAIR 

designated representative,’’ and 

‘‘continuous emission monitoring 

system’’ (or ‘‘CEMS’’) respectively, as 

defined in § 96.102. The owner or 

operator of a unit that is not a CAIR 

NOX unit but that is monitored under 

§ 75.72(b)(2)(ii) of this chapter shall 

comply with the same monitoring, 

recordkeeping, and reporting 

requirements as a CAIR NOX unit. 

(a) Requirements for installation, 

certification, and data accounting. The 

owner or operator of each CAIR NOX

unit shall: 

(1) Install all monitoring systems 

required under this subpart for 

monitoring NOX mass emissions and 

individual unit heat input (including all 

systems required to monitor NOX

emission rate, NOX concentration, stack 

gas moisture content, stack gas flow 

rate, CO2 or O2 concentration, and fuel 

flow rate, as applicable, in accordance 

with §§ 75.71 and 75.72 of this chapter); 

(2) Successfully complete all 

certification tests required under 

§ 96.171 and meet all other 

requirements of this subpart and part 75 

of this chapter applicable to the 

monitoring systems under paragraph 

(a)(1) of this section; and 

(3) Record, report, and quality-assure 

the data from the monitoring systems 

under paragraph (a)(1) of this section. 

(b) Compliance deadlines. The owner 

or operator shall meet the monitoring 

system certification and other 

requirements of paragraphs (a)(1) and 

(2) of this section on or before the 

following dates. The owner or operator 

shall record, report, and quality-assure 

the data from the monitoring systems 

under paragraph (a)(1) of this section on 

and after the following dates. 

(1) For the owner or operator of a 

CAIR NOX unit that commences 

commercial operation before July 1, 

2007, by January 1, 2008. 

(2) For the owner or operator of a 

CAIR NOX unit that commences 

commercial operation on or after July 1, 

2007, by the later of the following dates: 

(i) January 1, 2008; or 

(ii) 90 unit operating days or 180 

calendar days, whichever occurs first, 

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after the date on which the unit 

commences commercial operation. 

(3) For the owner or operator of a 

CAIR NOX unit for which construction 

of a new stack or flue or installation of 

add-on NOX emission controls is 

completed after the applicable deadline 

under paragraph (b)(1), (2), (4), or (5) of 

this section, by 90 unit operating days 

or 180 calendar days, whichever occurs 

first, after the date on which emissions 

first exit to the atmosphere through the 

new stack or flue or add-on NOX

emissions controls. 

(4) Notwithstanding the dates in 

paragraphs (b)(1) and (2) of this section, 

for the owner or operator of a unit for 

which a CAIR opt-in permit application 

is submitted and not withdrawn and a 

CAIR opt-in permit is not yet issued or 

denied under subpart II of this part, by 

the date specified in § 96.184(b).

(5) Notwithstanding the dates in 

paragraphs (b)(1), (2), and (4) of this 

section and solely for purposes of 

§ 96.106(c)(2), for the owner or operator 

of a CAIR NOX opt-in unit under 

subpart II of this part, by the date on 

which the CAIR NOX opt-in unit enters 

the CAIR NOX Annual Trading Program 

as provided in § 96.184(g). 

(c) Reporting data. (1) Except as 

provided in paragraph (c)(2) of this 

section, the owner or operator of a CAIR 

NOX unit that does not meet the 

applicable compliance date set forth in 

paragraph (b) of this section for any 

monitoring system under paragraph 

(a)(1) of this section shall, for each such 

monitoring system, determine, record, 

and report maximum potential (or, as 

appropriate, minimum potential) values 

for NOX concentration, NOX emission 

rate, stack gas flow rate, stack gas 

moisture content, fuel flow rate, and any 

other parameters required to determine 

NOX mass emissions and heat input in 

accordance with § 75.31(b)(2) or (c)(3) of 

this chapter, section 2.4 of appendix D 

to part 75 of this chapter, or section 2.5 

of appendix E to part 75 of this chapter, 

as applicable. 

(2) The owner or operator of a CAIR 

NOX unit that does not meet the 

applicable compliance date set forth in 

paragraph (b)(3) of this section for any 

monitoring system under paragraph 

(a)(1) of this section shall, for each such 

monitoring system, determine, record, 

and report substitute data using the 

applicable missing data procedures in 

subpart D or subpart H of, or appendix 

D or appendix E to, part 75 of this 

chapter, in lieu of the maximum 

potential (or, as appropriate, minimum 

potential) values, for a parameter if the 

owner or operator demonstrates that 

there is continuity between the data 

streams for that parameter before and 

after the construction or installation 

under paragraph (b)(3) of this section. 

(d) Prohibitions. (1) No owner or 

operator of a CAIR NOX unit shall use 

any alternative monitoring system, 

alternative reference method, or any 

other alternative to any requirement of 

this subpart without having obtained 

prior written approval in accordance 

with § 96.175. 

(2) No owner or operator of a CAIR 

NOX unit shall operate the unit so as to 

discharge, or allow to be discharged, 

NOX emissions to the atmosphere 

without accounting for all such 

emissions in accordance with the 

applicable provisions of this subpart 

and part 75 of this chapter. 

(3) No owner or operator of a CAIR 

NOX unit shall disrupt the continuous 

emission monitoring system, any 

portion thereof, or any other approved 

emission monitoring method, and 

thereby avoid monitoring and recording 

NOX mass emissions discharged into the 

atmosphere, except for periods of 

recertification or periods when 

calibration, quality assurance testing, or 

maintenance is performed in accordance 

with the applicable provisions of this 

subpart and part 75 of this chapter. 

(4) No owner or operator of a CAIR 

NOX unit shall retire or permanently 

discontinue use of the continuous 

emission monitoring system, any 

component thereof, or any other 

approved monitoring system under this 

subpart, except under any one of the 

following circumstances: 

(i) During the period that the unit is 

covered by an exemption under § 96.105 

that is in effect; 

(ii) The owner or operator is 

monitoring emissions from the unit with 

another certified monitoring system 

approved, in accordance with the 

applicable provisions of this subpart 

and part 75 of this chapter, by the 

permitting authority for use at that unit 

that provides emission data for the same 

pollutant or parameter as the retired or 

discontinued monitoring system; or 

(iii) The CAIR designated 

representative submits notification of 

the date of certification testing of a 

replacement monitoring system for the 

retired or discontinued monitoring 

system in accordance with 

§ 96.171(d)(3)(i).

§ 96.171 Initial certification and 

recertification procedures. 

(a) The owner or operator of a CAIR 

NOX unit shall be exempt from the 

initial certification requirements of this 

section for a monitoring system under 

§ 96.170(a)(1) if the following conditions 

are met:

(1) The monitoring system has been 

previously certified in accordance with 

part 75 of this chapter; and 

(2) The applicable quality-assurance 

and quality-control requirements of 

§ 75.21 of this chapter and appendix B, 

appendix D, and appendix E to part 75 

of this chapter are fully met for the 

certified monitoring system described in 

paragraph (a)(1) of this section. 

(b) The recertification provisions of 

this section shall apply to a monitoring 

system under § 96.170(a)(1) exempt 

from initial certification requirements 

under paragraph (a) of this section. 

(c) If the Administrator has previously 

approved a petition under § 75.17(a) or 

(b) of this chapter for apportioning the 

NOX emission rate measured in a 

common stack or a petition under 

§ 75.66 of this chapter for an alternative 

to a requirement in § 75.12, § 75.17, or 

subpart H of part 75 of this chapter, the 

CAIR designated representative shall 

resubmit the petition to the 

Administrator under § 96.175(a) to 

determine whether the approval applies 

under the CAIR NOX Annual Trading 

Program. 

(d) Except as provided in paragraph 

(a) of this section, the owner or operator 

of a CAIR NOX unit shall comply with 

the following initial certification and 

recertification procedures for a 

continuous monitoring system (i.e., a 

continuous emission monitoring system 

and an excepted monitoring system 

under appendices D and E to part 75 of 

this chapter) under § 96.170(a)(1). The 

owner or operator of a unit that qualifies 

to use the low mass emissions excepted 

monitoring methodology under § 75.19 

of this chapter or that qualifies to use an 

alternative monitoring system under 

subpart E of part 75 of this chapter shall 

comply with the procedures in 

paragraph (e) or (f) of this section 

respectively. 

(1) Requirements for initial 

certification. The owner or operator 

shall ensure that each continuous 

monitoring system under 

§ 96.170(a)(1)(including the automated 

data acquisition and handling system) 

successfully completes all of the initial 

certification testing required under 

§ 75.20 of this chapter by the applicable 

deadline in § 96.170(b). In addition, 

whenever the owner or operator installs 

a monitoring system to meet the 

requirements of this subpart in a 

location where no such monitoring 

system was previously installed, initial 

certification in accordance with § 75.20 

of this chapter is required. 

(2) Requirements for recertification.

Whenever the owner or operator makes 

a replacement, modification, or change 

in any certified continuous emission 

25356 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

monitoring system under § 96.170(a)(1) 

that may significantly affect the ability 

of the system to accurately measure or 

record NOX mass emissions or heat 

input rate or to meet the qualityassurance and quality-control 

requirements of § 75.21 of this chapter 

or appendix B to part 75 of this chapter, 

the owner or operator shall recertify the 

monitoring system in accordance with 

§ 75.20(b) of this chapter. Furthermore, 

whenever the owner or operator makes 

a replacement, modification, or change 

to the flue gas handling system or the 

unit’s operation that may significantly 

change the stack flow or concentration 

profile, the owner or operator shall 

recertify each continuous emission 

monitoring system whose accuracy is 

potentially affected by the change, in 

accordance with § 75.20(b) of this 

chapter. Examples of changes to a 

continuous emission monitoring system 

that require recertification include 

replacement of the analyzer, complete 

replacement of an existing continuous 

emission monitoring system, or change 

in location or orientation of the 

sampling probe or site. Any fuel 

flowmeter system, and any excepted 

NOX monitoring system under appendix 

E to part 75 of this chapter, under 

§ 96.170(a)(1) are subject to the 

recertification requirements in 

§ 75.20(g)(6) of this chapter. 

(3) Approval process for initial 

certification and recertification.

Paragraphs (d)(3)(i) through (iv) of this 

section apply to both initial certification 

and recertification of a continuous 

monitoring system under § 96.170(a)(1). 

For recertifications, replace the words 

‘‘certification’’ and ‘‘initial certification’’

with the word ‘‘recertification’’, replace 

the word ‘‘certified’’ with the word 

‘‘recertified,’’ and follow the procedures 

in §§ 75.20(b)(5) and (g)(7) of this 

chapter in lieu of the procedures in 

paragraph (d)(3)(v) of this section. 

(i) Notification of certification. The 

CAIR designated representative shall 

submit to the permitting authority, the 

appropriate EPA Regional Office, and 

the Administrator written notice of the 

dates of certification testing, in 

accordance with § 96.173. 

(ii) Certification application. The 

CAIR designated representative shall 

submit to the permitting authority a 

certification application for each 

monitoring system. A complete 

certification application shall include 

the information specified in § 75.63 of 

this chapter. 

(iii) Provisional certification date. The 

provisional certification date for a 

monitoring system shall be determined 

in accordance with § 75.20(a)(3) of this 

chapter. A provisionally certified 

monitoring system may be used under 

the CAIR NOX Annual Trading Program 

for a period not to exceed 120 days after 

receipt by the permitting authority of 

the complete certification application 

for the monitoring system under 

paragraph (d)(3)(ii) of this section. Data 

measured and recorded by the 

provisionally certified monitoring 

system, in accordance with the 

requirements of part 75 of this chapter, 

will be considered valid quality-assured 

data (retroactive to the date and time of 

provisional certification), provided that 

the permitting authority does not 

invalidate the provisional certification 

by issuing a notice of disapproval 

within 120 days of the date of receipt of 

the complete certification application by 

the permitting authority.

(iv) Certification application approval 

process. The permitting authority will 

issue a written notice of approval or 

disapproval of the certification 

application to the owner or operator 

within 120 days of receipt of the 

complete certification application under 

paragraph (d)(3)(ii) of this section. In the 

event the permitting authority does not 

issue such a notice within such 120-day 

period, each monitoring system that 

meets the applicable performance 

requirements of part 75 of this chapter 

and is included in the certification 

application will be deemed certified for 

use under the CAIR NOX Annual 

Trading Program. 

(A) Approval notice. If the 

certification application is complete and 

shows that each monitoring system 

meets the applicable performance 

requirements of part 75 of this chapter, 

then the permitting authority will issue 

a written notice of approval of the 

certification application within 120 

days of receipt. 

(B) Incomplete application notice. If 

the certification application is not 

complete, then the permitting authority 

will issue a written notice of 

incompleteness that sets a reasonable 

date by which the CAIR designated 

representative must submit the 

additional information required to 

complete the certification application. If 

the CAIR designated representative does 

not comply with the notice of 

incompleteness by the specified date, 

then the permitting authority may issue 

a notice of disapproval under paragraph 

(d)(3)(iv)(C) of this section. The 120-day 

review period shall not begin before 

receipt of a complete certification 

application. 

(C) Disapproval notice. If the 

certification application shows that any 

monitoring system does not meet the 

performance requirements of part 75 of 

this chapter or if the certification 

application is incomplete and the 

requirement for disapproval under 

paragraph (d)(3)(iv)(B) of this section is 

met, then the permitting authority will 

issue a written notice of disapproval of 

the certification application. Upon 

issuance of such notice of disapproval, 

the provisional certification is 

invalidated by the permitting authority 

and the data measured and recorded by 

each uncertified monitoring system 

shall not be considered valid qualityassured data beginning with the date 

and hour of provisional certification (as 

defined under § 75.20(a)(3) of this 

chapter). The owner or operator shall 

follow the procedures for loss of 

certification in paragraph (d)(3)(v) of 

this section for each monitoring system 

that is disapproved for initial 

certification. 

(D) Audit decertification. The 

permitting authority or, for a CAIR NOX

opt-in unit or a unit for which a CAIR 

opt-in permit application is submitted 

and not withdrawn and a CAIR opt-in 

permit is not yet issued or denied under 

subpart II of this part, the Administrator 

may issue a notice of disapproval of the 

certification status of a monitor in 

accordance with § 96.172(b). 

(v) Procedures for loss of certification.

If the permitting authority or the 

Administrator issues a notice of 

disapproval of a certification 

application under paragraph 

(d)(3)(iv)(C) of this section or a notice of 

disapproval of certification status under 

paragraph (d)(3)(iv)(D) of this section, 

then: 

(A) The owner or operator shall 

substitute the following values, for each 

disapproved monitoring system, for 

each hour of unit operation during the 

period of invalid data specified under 

§ 75.20(a)(4)(iii), § 75.20(g)(7), or 

§ 75.21(e) of this chapter and continuing 

until the applicable date and hour 

specified under § 75.20(a)(5)(i) or (g)(7) 

of this chapter: 

(1) For a disapproved NOX emission 

rate (i.e., NOX-diluent) system, the 

maximum potential NOX emission rate, 

as defined in § 72.2 of this chapter. 

(2) For a disapproved NOX pollutant 

concentration monitor and disapproved 

flow monitor, respectively, the 

maximum potential concentration of 

NOX and the maximum potential flow 

rate, as defined in sections 2.1.2.1 and 

2.1.4.1 of appendix A to part 75 of this 

chapter.

(3) For a disapproved moisture 

monitoring system and disapproved 

diluent gas monitoring system, 

respectively, the minimum potential 

moisture percentage and either the 

maximum potential CO2 concentration 

or the minimum potential O2

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25357

concentration (as applicable), as defined 

in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of 

appendix A to part 75 of this chapter. 

(4) For a disapproved fuel flowmeter 

system, the maximum potential fuel 

flow rate, as defined in section 2.4.2.1 

of appendix D to part 75 of this chapter. 

(5) For a disapproved excepted NOX

monitoring system under appendix E to 

part 75 of this chapter, the fuel-specific 

maximum potential NOX emission rate, 

as defined in § 72.2 of this chapter. 

(B) The CAIR designated 

representative shall submit a 

notification of certification retest dates 

and a new certification application in 

accordance with paragraphs (d)(3)(i) and 

(ii) of this section. 

(C) The owner or operator shall repeat 

all certification tests or other 

requirements that were failed by the 

monitoring system, as indicated in the 

permitting authority’s or the 

Administrator’s notice of disapproval, 

no later than 30 unit operating days 

after the date of issuance of the notice 

of disapproval. 

(e) Initial certification and 

recertification procedures for units 

using the low mass emission excepted 

methodology under § 75.19 of this 

chapter. The owner or operator of a unit 

qualified to use the low mass emissions 

(LME) excepted methodology under 

§ 75.19 of this chapter shall meet the 

applicable certification and 

recertification requirements in 

§§ 75.19(a)(2) and 75.20(h) of this 

chapter. If the owner or operator of such 

a unit elects to certify a fuel flowmeter 

system for heat input determination, the 

owner or operator shall also meet the 

certification and recertification 

requirements in § 75.20(g) of this 

chapter. 

(f) Certification/recertification 

procedures for alternative monitoring 

systems. The CAIR designated 

representative of each unit for which the 

owner or operator intends to use an 

alternative monitoring system approved 

by the Administrator and, if applicable, 

the permitting authority under subpart E 

of part 75 of this chapter shall comply 

with the applicable notification and 

application procedures of § 75.20(f) of 

this chapter.

§ 96.172 Out of control periods. 

(a) Whenever any monitoring system 

fails to meet the quality-assurance and 

quality-control requirements or data 

validation requirements of part 75 of 

this chapter, data shall be substituted 

using the applicable missing data 

procedures in subpart D or subpart H of, 

or appendix D or appendix E to, 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 monitoring system should not have 

been certified or recertified because it 

did not meet a particular performance 

specification or other requirement under 

§ 96.171 or the applicable provisions of 

part 75 of this chapter, both at the time 

of the initial certification or 

recertification application submission 

and at the time of the audit, the 

permitting authority or, for a CAIR NOX

opt-in unit or a unit for which a CAIR 

opt-in permit application is submitted 

and not withdrawn and a CAIR opt-in 

permit is not yet issued or denied under 

subpart II of this part, the Administrator 

will issue a notice of disapproval of the 

certification status of such monitoring 

system. For the purposes of this 

paragraph, an audit shall be either a 

field audit or an audit of any 

information submitted to the permitting 

authority or the Administrator. By 

issuing the notice of disapproval, the 

permitting authority or the 

Administrator revokes prospectively the 

certification status of the monitoring 

system. The data measured and 

recorded by the monitoring system shall 

not be considered valid quality-assured 

data from the date of issuance of the 

notification of the revoked certification 

status until the date and time that the 

owner or operator completes 

subsequently approved initial 

certification or recertification tests for 

the monitoring system. The owner or 

operator shall follow the applicable 

initial certification or recertification 

procedures in § 96.171 for each 

disapproved monitoring system.

§ 96.173 Notifications. 

The CAIR designated representative 

for a CAIR NOX 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.

§ 96.174 Recordkeeping and reporting. 

(a) General provisions. The CAIR 

designated representative shall comply 

with all recordkeeping and reporting 

requirements in this section, the 

applicable recordkeeping and reporting 

requirements under § 75.73 of this 

chapter, and the requirements of 

§ 96.110(e)(1). 

(b) Monitoring Plans. The owner or 

operator of a CAIR NOX unit shall 

comply with requirements of § 75.73(c) 

and (e) of this chapter and, for a unit for 

which a CAIR opt-in permit application 

is submitted and not withdrawn and a 

CAIR opt-in permit is not yet issued or 

denied under subpart II of this part, 

§§ 96.183 and 96.184(a). 

(c) Certification Applications. The 

CAIR designated representative shall 

submit an application to the permitting 

authority within 45 days after 

completing all initial certification or 

recertification tests required under 

§ 96.171, including the information 

required under § 75.63 of this chapter. 

(d) Quarterly reports. The CAIR 

designated representative shall submit 

quarterly reports, as follows: 

(1) The CAIR designated 

representative shall report the NOX

mass emissions data and heat input data 

for the CAIR NOX unit, in an electronic 

quarterly report in a format prescribed 

by the Administrator, for each calendar 

quarter beginning with: 

(i) For a unit that commences 

commercial operation before July 1, 

2007, the calendar quarter covering 

January 1, 2008 through March 31, 2008; 

or 

(ii) For a unit that commences 

commercial operation on or after July 1, 

2007, the calendar quarter 

corresponding to the earlier of the date 

of provisional certification or the 

applicable deadline for initial 

certification under § 96.170(b), unless 

that quarter is the third or fourth quarter 

of 2007, in which case reporting shall 

commence in the quarter covering 

January 1, 2008 through March 31, 2008. 

(2) The CAIR designated 

representative shall submit each 

quarterly report to the Administrator 

within 30 days following the end of the 

calendar quarter covered by the report. 

Quarterly reports shall be submitted in 

the manner specified in § 75.73(f) of this 

chapter. 

(3) For CAIR NOX units that are also 

subject to an Acid Rain emissions 

limitation or the CAIR NOX Ozone 

Season Trading Program or CAIR SO2

Trading Program, quarterly reports shall 

include the applicable data and 

information required by subparts F 

through H of part 75 of this chapter as 

applicable, in addition to the NOX mass 

emission data, heat input data, and 

other information required by this 

subpart. 

(e) Compliance certification. The 

CAIR designated representative shall 

submit to the Administrator a 

compliance certification (in a format 

prescribed by the Administrator) in 

support of each quarterly report based 

on reasonable inquiry of those persons 

with primary responsibility for ensuring 

that all of the unit’s emissions are 

25358 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

correctly and fully monitored. The 

certification shall state that: 

(1) The monitoring data submitted 

were recorded in accordance with the 

applicable requirements of this subpart 

and part 75 of this chapter, including 

the quality assurance procedures and 

specifications; and 

(2) For a unit with add-on NOX

emission controls and for all hours 

where NOX data are substituted in 

accordance with § 75.34(a)(1) of this 

chapter, the add-on emission controls 

were operating within the range of 

parameters listed in the quality 

assurance/quality control program 

under appendix B to part 75 of this 

chapter and the substitute data values 

do not systematically underestimate 

NOX emissions.

§ 96.175 Petitions.

(a) Except as provided in paragraph 

(b)(2) of this section, the CAIR 

designated representative of a CAIR 

NOX 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 in writing by the 

Administrator, in consultation with the 

permitting authority. 

(b)(1) The CAIR designated 

representative of a CAIR NOX unit that 

is not subject to an Acid Rain emissions 

limitation may submit a petition under 

§ 75.66 of this chapter to the permitting 

authority and the Administrator 

requesting approval to apply an 

alternative to any requirement of this 

subpart. Application of an alternative to 

any requirement of this subpart is in 

accordance with this subpart only to the 

extent that the petition is approved in 

writing by both the permitting authority 

and the Administrator. 

(2) The CAIR designated 

representative of a CAIR NOX 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 continuous emission 

monitoring system required under 

§ 75.72 of this chapter. Application of 

an alternative to any such requirement 

is in accordance with this subpart only 

to the extent that the petition is 

approved in writing by both the 

permitting authority and the 

Administrator.

§ 96.176 Additional requirements to 

provide heat input data. 

The owner or operator of a CAIR NOX

unit that monitors and reports NOX

mass emissions using a NOX

concentration system and a flow system 

shall also monitor and report heat input 

rate at the unit level using the 

procedures set forth in part 75 of this 

chapter.

Subpart II—CAIR NOX Opt-in Units

§ 96.180 Applicability. 

A CAIR NOX opt-in unit must be a 

unit that: 

(a) Is located in the State; 

(b) Is not a CAIR NOX unit under 

§ 96.104 and is not covered by a retired 

unit exemption under § 96.105 that is in 

effect; 

(c) Is not covered by a retired unit 

exemption under § 72.8 of this chapter 

that is in effect; 

(d) Has or is required or qualified to 

have a title V operating permit or other 

federally enforceable permit; and 

(e) Vents all of its emissions to a stack 

and can meet the monitoring, 

recordkeeping, and reporting 

requirements of subpart HH of this part.

§ 96.181 General. 

(a) Except as otherwise provided in 

§§ 96.101 through 96.104, §§ 96.106 

through 96.108, and subparts BB and CC 

and subparts FF through HH of this part, 

a CAIR NOX opt-in unit shall be treated 

as a CAIR NOX unit for purposes of 

applying such sections and subparts of 

this part. 

(b) Solely for purposes of applying, as 

provided in this subpart, the 

requirements of subpart HH of this part 

to a unit for which a CAIR opt-in permit 

application is submitted and not 

withdrawn and a CAIR opt-in permit is 

not yet issued or denied under this 

subpart, such unit shall be treated as a 

CAIR NOX unit before issuance of a 

CAIR opt-in permit for such unit.

§ 96.182 CAIR designated representative. 

Any CAIR NOX opt-in unit, and any 

unit for which a CAIR opt-in permit 

application is submitted and not 

withdrawn and a CAIR opt-in permit is 

not yet issued or denied under this 

subpart, located at the same source as 

one or more CAIR NOX units shall have 

the same CAIR designated 

representative and alternate CAIR 

designated representative as such CAIR 

NOX units.

§ 96.183 Applying for CAIR opt-in permit. 

(a) Applying for initial CAIR opt-in 

permit. The CAIR designated 

representative of a unit meeting the 

requirements for a CAIR NOX opt-in 

unit in § 96.180 may apply for an initial 

CAIR opt-in permit at any time, except 

as provided under § 96.186(f) and (g), 

and, in order to apply, must submit the 

following:

(1) A complete CAIR permit 

application under § 96.122; 

(2) A certification, in a format 

specified by the permitting authority, 

that the unit: 

(i) Is not a CAIR NOX unit under 

§ 96.104 and is not covered by a retired 

unit exemption under § 96.105 that is in 

effect; 

(ii) Is not covered by a retired unit 

exemption under § 72.8 of this chapter 

that is in effect; 

(iii) Vents all of its emissions to a 

stack, and 

(iv) Has documented heat input for 

more than 876 hours during the 6 

months immediately preceding 

submission of the CAIR permit 

application under § 96.122; 

(3) A monitoring plan in accordance 

with subpart HH of this part; 

(4) A complete certificate of 

representation under § 96.113 consistent 

with § 96.182, if no CAIR designated 

representative has been previously 

designated for the source that includes 

the unit; and 

(5) A statement, in a format specified 

by the permitting authority, whether the 

CAIR designated representative requests 

that the unit be allocated CAIR NOX

allowances under § 96.188(c) (subject to 

the conditions in §§ 96.184(h) and 

96.186(g)). 

(b) Duty to reapply. (1) The CAIR 

designated representative of a CAIR 

NOX opt-in unit shall submit a complete 

CAIR permit application under § 96.122 

to renew the CAIR opt-in unit permit in 

accordance with the permitting 

authority’s regulations for title V 

operating permits, or the permitting 

authority’s regulations for other 

federally enforceable permits if 

applicable, addressing permit renewal. 

(2) Unless the permitting authority 

issues a notification of acceptance of 

withdrawal of the CAIR opt-in unit from 

the CAIR NOX Annual Trading Program 

in accordance with § 96.186 or the unit 

becomes a CAIR NOX unit under 

§ 96.104, the CAIR NOX opt-in unit shall 

remain subject to the requirements for a 

CAIR NOX opt-in unit, even if the CAIR 

designated representative for the CAIR 

NOX opt-in unit fails to submit a CAIR 

permit application that is required for 

renewal of the CAIR opt-in permit under 

paragraph (b)(1) of this section.

§ 96.184 Opt-in process. 

The permitting authority will issue or 

deny a CAIR opt-in permit for a unit for 

which an initial application for a CAIR 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25359

opt-in permit under § 96.183 is 

submitted in accordance with the 

following: 

(a) Interim review of monitoring plan.

The permitting authority and the 

Administrator will determine, on an 

interim basis, the sufficiency of the 

monitoring plan accompanying the 

initial application for a CAIR opt-in 

permit under § 96.183. 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 and all other applicable 

parameters are monitored and reported 

in accordance with subpart HH of this 

part. A determination of sufficiency 

shall not be construed as acceptance or 

approval of the monitoring plan. 

(b) Monitoring and reporting. (1)(i) If 

the permitting authority and the 

Administrator determine that the 

monitoring plan is sufficient under 

paragraph (a) of this section, the owner 

or operator shall monitor and report the 

NOX emissions rate and the heat input 

of the unit and all other applicable 

parameters, in accordance with subpart 

HH of this part, starting on the date of 

certification of the appropriate 

monitoring systems under subpart HH 

of this part and continuing until a CAIR 

opt-in permit is denied under § 96.184(f) 

or, if a CAIR opt-in permit is issued, the 

date and time when the unit is 

withdrawn from the CAIR NOX Annual 

Trading Program in accordance with 

§ 96.186. 

(ii) The monitoring and reporting 

under paragraph (b)(1)(i) of this section 

shall include the entire control period 

immediately before the date on which 

the unit enters the CAIR NOX Annual 

Trading Program under § 96.184(g), 

during which period monitoring system 

availability must not be less than 90 

percent under subpart HH of this part 

and the unit must be in full compliance 

with any applicable State or Federal 

emissions or emissions-related 

requirements.

(2) To the extent the NOX emissions 

rate and the heat input of the unit are 

monitored and reported in accordance 

with subpart HH of this part for one or 

more control periods, in addition to the 

control period under paragraph (b)(1)(ii) 

of this section, during which control 

periods monitoring system availability 

is not less than 90 percent under 

subpart HH of this part and the unit is 

in full compliance with any applicable 

State or Federal emissions or emissionsrelated requirements and which control 

periods begin not more than 3 years 

before the unit enters the CAIR NOX

Annual Trading Program under 

§ 96.184(g), such information shall be 

used as provided in paragraphs (c) and 

(d) of this section. 

(c) Baseline heat input. The unit’s 

baseline heat rate shall equal: 

(1) If the unit’s NOX emissions rate 

and heat input are monitored and 

reported for only one control period, in 

accordance with paragraph (b)(1) of this 

section, the unit’s total heat input (in 

mmBtu) for the control period; or 

(2) If the unit’s NOX emissions rate 

and heat input are monitored and 

reported for more than one control 

period, in accordance with paragraphs 

(b)(1) and (2) of this section, the average 

of the amounts of the unit’s total heat 

input (in mmBtu) for the control period 

under paragraph (b)(1)(ii) of this section 

and for the control periods under 

paragraph (b)(2) of this section. 

(d) Baseline NOX emission rate. The 

unit’s baseline NOX emission rate shall 

equal: 

(1) If the unit’s NOX emissions rate 

and heat input are monitored and 

reported for only one control period, in 

accordance with paragraph (b)(1) of this 

section, the unit’s NOX emissions rate 

(in lb/mmBtu) for the control period; 

(2) If the unit’s NOX emissions rate 

and heat input are monitored and 

reported for more than one control 

period, in accordance with paragraphs 

(b)(1) and (2) of this section, and the 

unit does not have add-on NOX

emission controls during any such 

control periods, the average of the 

amounts of the unit’s NOX emissions 

rate (in lb/mmBtu) for the control period 

under paragraph (b)(1)(ii) of this section 

and the control periods under paragraph 

(b)(2) of this section; or 

(3) If the unit’s NOX emissions rate 

and heat input are monitored and 

reported for more than one control 

period, in accordance with paragraphs 

(b)(1) and (2) of this section, and the 

unit has add-on NOX emission controls 

during any such control periods, the 

average of the amounts of the unit’s 

NOX emissions rate (in lb/mmBtu) for 

such control period during which the 

unit has add-on NOX emission controls. 

(e) Issuance of CAIR opt-in permit.

After calculating the baseline heat input 

and the baseline NOX emissions rate for 

the unit under paragraphs (c) and (d) of 

this section and if the permitting 

authority determines that the CAIR 

designated representative shows that the 

unit meets the requirements for a CAIR 

NOX opt-in unit in § 96.180 and meets 

the elements certified in § 96.183(a)(2), 

the permitting authority will issue a 

CAIR opt-in permit. The permitting 

authority will provide a copy of the 

CAIR opt-in permit to the 

Administrator, who will then establish 

a compliance account for the source that 

includes the CAIR NOX opt-in unit 

unless the source already has a 

compliance account. 

(f) Issuance of denial of CAIR opt-in 

permit. Notwithstanding paragraphs (a) 

through (e) of this section, if at any time 

before issuance of a CAIR opt-in permit 

for the unit, the permitting authority 

determines that the CAIR designated 

representative fails to show that the unit 

meets the requirements for a CAIR NOX

opt-in unit in § 96.180 or meets the 

elements certified in § 96.183(a)(2), the 

permitting authority will issue a denial 

of a CAIR NOX opt-in permit for the 

unit. 

(g) Date of entry into CAIR NOX

Annual Trading Program. A unit for 

which an initial CAIR opt-in permit is 

issued by the permitting authority shall 

become a CAIR NOX opt-in unit, and a 

CAIR NOX unit, as of the later of January 

1, 2009 or January 1 of the first control 

period during which such CAIR opt-in 

permit is issued. 

(h) Repowered CAIR NOX opt-in unit. 

(1) If CAIR designated representative 

requests, and the permitting authority 

issues a CAIR opt-in permit providing 

for, allocation to a CAIR NOX opt-in unit 

of CAIR NOX allowances under 

§ 96.188(c) and such unit is repowered 

after its date of entry into the CAIR NOX

Annual Trading Program under 

paragraph (g) of this section, the 

repowered unit shall be treated as a 

CAIR NOX opt-in unit replacing the 

original CAIR NOX opt-in unit, as of the 

date of start-up of the repowered unit’s 

combustion chamber. 

(2) Notwithstanding paragraphs (c) 

and (d) of this section, as of the date of 

start-up under paragraph (h)(1) of this 

section, the repowered unit shall be 

deemed to have the same date of 

commencement of operation, date of 

commencement of commercial 

operation, baseline heat input, and 

baseline NOX emission rate as the 

original CAIR NOX opt-in unit, and the 

original CAIR NOX opt-in unit shall no 

longer be treated as a CAIR opt-in unit 

or a CAIR NOX unit.

§ 96.185 CAIR opt-in permit contents. 

(a) Each CAIR opt-in permit will 

contain: 

(1) All elements required for a 

complete CAIR permit application 

under § 96.122; 

(2) The certification in § 96.183(a)(2); 

(3) The unit’s baseline heat input 

under § 96.184(c); 

(4) The unit’s baseline NOX emission 

rate under § 96.184(d);

(5) A statement whether the unit is to 

be allocated CAIR NOX allowances 

under § 96.188(c) (subject to the 

25360 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

conditions in §§ 96.184(h) and 

96.186(g)); 

(6) A statement that the unit may 

withdraw from the CAIR NOX Annual 

Trading Program only in accordance 

with § 96.186; and 

(7) A statement that the unit is subject 

to, and the owners and operators of the 

unit must comply with, the 

requirements of § 96.187. 

(b) Each CAIR opt-in permit is 

deemed to incorporate automatically the 

definitions of terms under § 96.102 and, 

upon recordation by the Administrator 

under subpart FF or GG of this part or 

this subpart, every allocation, transfer, 

or deduction of CAIR NOX allowances 

to or from the compliance account of the 

source that includes a CAIR NOX opt-in 

unit covered by the CAIR opt-in permit.

§ 96.186 Withdrawal from CAIR NOX

Annual Trading Program. 

Except as provided under paragraph 

(g) of this section, a CAIR NOX opt-in 

unit may withdraw from the CAIR NOX

Annual Trading Program, but only if the 

permitting authority issues a 

notification to the CAIR designated 

representative of the CAIR NOX opt-in 

unit of the acceptance of the withdrawal 

of the CAIR NOX opt-in unit in 

accordance with paragraph (d) of this 

section. 

(a) Requesting withdrawal. In order to 

withdraw a CAIR opt-in unit from the 

CAIR NOX Annual Trading Program, the 

CAIR designated representative of the 

CAIR NOX opt-in unit shall submit to 

the permitting authority a request to 

withdraw effective as of midnight of 

December 31 of a specified calendar 

year, which date must be at least 4 years 

after December 31 of the year of entry 

into the CAIR NOX Annual Trading 

Program under § 96.184(g). The request 

must be submitted no later than 90 days 

before the requested effective date of 

withdrawal. 

(b) Conditions for withdrawal. Before 

a CAIR NOX opt-in unit covered by a 

request under paragraph (a) of this 

section may withdraw from the CAIR 

NOX Annual Trading Program and the 

CAIR opt-in permit may be terminated 

under paragraph (e) of this section, the 

following conditions must be met: 

(1) For the control period ending on 

the date on which the withdrawal is to 

be effective, the source that includes the 

CAIR NOX opt-in unit must meet the 

requirement to hold CAIR NOX

allowances under § 96.106(c) and 

cannot have any excess emissions. 

(2) After the requirement for 

withdrawal under paragraph (b)(1) of 

this section is met, the Administrator 

will deduct from the compliance 

account of the source that includes the 

CAIR NOX opt-in unit CAIR NOX

allowances equal in number to and 

allocated for the same or a prior control 

period as any CAIR NOX allowances 

allocated to the CAIR NOX opt-in unit 

under § 96.188 for any control period for 

which the withdrawal is to be effective. 

If there are no remaining CAIR NOX

units at the source, the Administrator 

will close the compliance account, and 

the owners and operators of the CAIR 

NOX opt-in unit may submit a CAIR 

NOX allowance transfer for any 

remaining CAIR NOX allowances to 

another CAIR NOX Allowance Tracking 

System in accordance with subpart GG 

of this part. 

(c) Notification. (1) After the 

requirements for withdrawal under 

paragraphs (a) and (b) of this section are 

met (including deduction of the full 

amount of CAIR NOX allowances 

required), the permitting authority will 

issue a notification to the CAIR 

designated representative of the CAIR 

NOX opt-in unit of the acceptance of the 

withdrawal of the CAIR NOX opt-in unit 

as of midnight on December 31 of the 

calendar year for which the withdrawal 

was requested. 

(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 

CAIR designated representative of the 

CAIR NOX opt-in unit that the CAIR 

NOX opt-in unit’s request to withdraw is 

denied. Such CAIR NOX opt-in unit 

shall continue to be a CAIR NOX opt-in 

unit. 

(d) Permit amendment. After the 

permitting authority issues a 

notification under paragraph (c)(1) of 

this section that the requirements for 

withdrawal have been met, the 

permitting authority will revise the 

CAIR permit covering the CAIR NOX

opt-in unit to terminate the CAIR opt-in 

permit for such unit as of the effective 

date specified under paragraph (c)(1) of 

this section. The unit shall continue to 

be a CAIR NOX opt-in unit until the 

effective date of the termination and 

shall comply with all requirements 

under the CAIR NOX Annual Trading 

Program concerning any control periods 

for which the unit is a CAIR NOX optin unit, even if such requirements arise 

or must be complied with after the 

withdrawal takes effect. 

(e) Reapplication upon failure to meet 

conditions of withdrawal. If the 

permitting authority denies the CAIR 

NOX opt-in unit’s request to withdraw, 

the CAIR designated representative may 

submit another request to withdraw in 

accordance with paragraphs (a) and (b) 

of this section. 

(f) Ability to reapply to the CAIR NOX

Annual Trading Program. Once a CAIR 

NOX opt-in unit withdraws from the 

CAIR NOX Annual Trading Program and 

its CAIR opt-in permit is terminated 

under this section, the CAIR designated 

representative may not submit another 

application for a CAIR opt-in permit 

under § 96.183 for such CAIR NOX optin unit before the date that is 4 years 

after the date on which the withdrawal 

became effective. Such new application 

for a CAIR opt-in permit will be treated 

as an initial application for a CAIR optin permit under § 96.184.

(g) Inability to withdraw.

Notwithstanding paragraphs (a) through 

(f) of this section, a CAIR NOX opt-in 

unit shall not be eligible to withdraw 

from the CAIR NOX Annual Trading 

Program if the CAIR designated 

representative of the CAIR NOX opt-in 

unit requests, and the permitting 

authority issues a CAIR NOX opt-in 

permit providing for, allocation to the 

CAIR NOX opt-in unit of CAIR NOX

allowances under § 96.188(c).

§ 96.187 Change in regulatory status. 

(a) Notification. If a CAIR NOX opt-in 

unit becomes a CAIR NOX unit under 

§ 96.104, then the CAIR designated 

representative shall notify in writing the 

permitting authority and the 

Administrator of such change in the 

CAIR NOX opt-in unit’s regulatory 

status, within 30 days of such change. 

(b) Permitting authority’s and 

Administrator’s actions.

(1) If a CAIR NOX opt-in unit becomes 

a CAIR NOX unit under § 96.104, the 

permitting authority will revise the 

CAIR NOX opt-in unit’s CAIR opt-in 

permit to meet the requirements of a 

CAIR permit under § 96.123 as of the 

date on which the CAIR NOX opt-in unit 

becomes a CAIR NOX unit under 

§ 96.104. 

(2)(i) The Administrator will deduct 

from the compliance account of the 

source that includes the CAIR NOX optin unit that becomes a CAIR NOX unit 

under § 96.104, CAIR NOX allowances 

equal in number to and allocated for the 

same or a prior control period as: 

(A) Any CAIR NOX allowances 

allocated to the CAIR NOX opt-in unit 

under § 96.188 for any control period 

after the date on which the CAIR NOX

opt-in unit becomes a CAIR NOX unit 

under § 96.104; and 

(B) If the date on which the CAIR NOX

opt-in unit becomes a CAIR NOX unit 

under § 96.104 is not December 31, the 

CAIR NOX allowances allocated to the 

CAIR NOX opt-in unit under § 96.188 for 

the control period that includes the date 

on which the CAIR NOX opt-in unit 

becomes a CAIR NOX unit under 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25361

§ 96.104, multiplied by the ratio of the 

number of days, in the control period, 

starting with the date on which the 

CAIR NOX opt-in unit becomes a CAIR 

NOX unit under § 96.104 divided by the 

total number of days in the control 

period and rounded to the nearest 

whole allowance as appropriate. 

(ii) The CAIR designated 

representative shall ensure that the 

compliance account of the source that 

includes the CAIR NOX unit that 

becomes a CAIR NOX unit under 

§ 96.104 contains the CAIR NOX

allowances necessary for completion of 

the deduction under paragraph (b)(2)(i) 

of this section. 

(3)(i) For every control period after 

the date on which the CAIR NOX optin unit becomes a CAIR NOX unit under 

§ 96.104, the CAIR NOX opt-in unit will 

be treated, solely for purposes of CAIR 

NOX allowance allocations under 

§ 96.142, as a unit that commences 

operation on the date on which the 

CAIR NOX opt-in unit becomes a CAIR 

NOX unit under § 96.104 and will be 

allocated CAIR NOX allowances under 

§ 96.142. 

(ii) Notwithstanding paragraph 

(b)(3)(i) of this section, if the date on 

which the CAIR NOX opt-in unit 

becomes a CAIR NOX unit under 

§ 96.104 is not January 1, the following 

number of CAIR NOX allowances will be 

allocated to the CAIR NOX opt-in unit 

(as a CAIR NOX unit) under § 96.142 for 

the control period that includes the date 

on which the CAIR NOX opt-in unit 

becomes a CAIR NOX unit under 

§ 96.104: 

(A) The number of CAIR NOX

allowances otherwise allocated to the 

CAIR NOX opt-in unit (as a CAIR NOX

unit) under § 96.142 for the control 

period multiplied by; 

(B) The ratio of the number of days, 

in the control period, starting with the 

date on which the CAIR NOX opt-in unit 

becomes a CAIR NOX unit under 

§ 96.104, divided by the total number of 

days in the control period; and 

(C) Rounded to the nearest whole 

allowance as appropriate.

§ 96.188 NOX allowance allocations to 

CAIR NOX opt-in units. 

(a) Timing requirements. (1) When the 

CAIR opt-in permit is issued under 

§ 96.184(e), the permitting authority will 

allocate CAIR NOX allowances to the 

CAIR NOX opt-in unit, and submit to the 

Administrator the allocation for the 

control period in which a CAIR NOX

opt-in unit enters the CAIR NOX Annual 

Trading Program under § 96.184(g), in 

accordance with paragraph (b) or (c) of 

this section. 

(2) By no later than October 31 of the 

control period in which a CAIR opt-in 

unit enters the CAIR NOX Annual 

Trading Program under § 96.184(g) and 

October 31 of each year thereafter, the 

permitting authority will allocate CAIR 

NOX allowances to the CAIR NOX optin unit, and submit to the Administrator 

the allocation for the control period that 

includes such submission deadline and 

in which the unit is a CAIR NOX optin unit, in accordance with paragraph 

(b) or (c) of this section. 

(b) Calculation of allocation. For each 

control period for which a CAIR NOX

opt-in unit is to be allocated CAIR NOX

allowances, the permitting authority 

will allocate in accordance with the 

following procedures: 

(1) The heat input (in mmBtu) used 

for calculating the CAIR NOX allowance 

allocation will be the lesser of: 

(i) The CAIR NOX opt-in unit’s 

baseline heat input determined under 

§ 96.184(c); or 

(ii) The CAIR NOX opt-in unit’s heat 

input, as determined in accordance with 

subpart HH of this part, for the 

immediately prior control period, 

except when the allocation is being 

calculated for the control period in 

which the CAIR NOX opt-in unit enters 

the CAIR NOX Annual Trading Program 

under § 96.184(g). 

(2) The NOX emission rate (in lb/

mmBtu) used for calculating CAIR NOX

allowance allocations will be the lesser 

of: 

(i) The CAIR NOX opt-in unit’s 

baseline NOX emissions rate (in lb/

mmBtu) determined under § 96.184(d) 

and multiplied by 70 percent; or

(ii) The most stringent State or 

Federal NOX emissions limitation 

applicable to the CAIR NOX opt-in unit 

at any time during the control period for 

which CAIR NOX allowances are to be 

allocated. 

(3) The permitting authority will 

allocate CAIR NOX allowances to the 

CAIR NOX opt-in unit in an amount 

equaling the heat input under paragraph 

(b)(1) of this section, multiplied by the 

NOX emission rate under paragraph 

(b)(2) of this section, divided by 2,000 

lb/ton, and rounded to the nearest 

whole allowance as appropriate. 

(c) Notwithstanding paragraph (b) of 

this section and if the CAIR designated 

representative requests, and the 

permitting authority issues a CAIR optin permit providing for, allocation to a 

CAIR NOX opt-in unit of CAIR NOX

allowances under this paragraph 

(subject to the conditions in 

§§ 96.184(h) and 96.186(g)), the 

permitting authority will allocate to the 

CAIR NOX opt-in unit as follows: 

(1) For each control period in 2009 

through 2014 for which the CAIR NOX

opt-in unit is to be allocated CAIR NOX

allowances, 

(i) The heat input (in mmBtu) used for 

calculating CAIR NOX allowance 

allocations will be determined as 

described in paragraph (b)(1) of this 

section. 

(ii) The NOX emission rate (in lb/

mmBtu) used for calculating CAIR NOX

allowance allocations will be the lesser 

of: 

(A) The CAIR NOX opt-in unit’s 

baseline NOX emissions rate (in lb/

mmBtu) determined under § 96.184(d); 

or 

(B) The most stringent State or 

Federal NOX emissions limitation 

applicable to the CAIR NOX opt-in unit 

at any time during the control period in 

which the CAIR NOX opt-in unit enters 

the CAIR NOX Annual Trading Program 

under § 96.184(g). 

(iii) The permitting authority will 

allocate CAIR NOX allowances to the 

CAIR NOX opt-in unit in an amount 

equaling the heat input under paragraph 

(c)(1)(i) of this section, multiplied by the 

NOX emission rate under paragraph 

(c)(1)(ii) of this section, divided by 

2,000 lb/ton, and rounded to the nearest 

whole allowance as appropriate. 

(2) For each control period in 2015 

and thereafter for which the CAIR NOX

opt-in unit is to be allocated CAIR NOX

allowances, 

(i) The heat input (in mmBtu) used for 

calculating the CAIR NOX allowance 

allocations will be determined as 

described in paragraph (b)(1) of this 

section. 

(ii) The NOX emission rate (in lb/

mmBtu) used for calculating the CAIR 

NOX allowance allocation will be the 

lesser of: 

(A) 0.15 lb/mmBtu; 

(B) The CAIR NOX opt-in unit’s 

baseline NOX emissions rate (in lb/

mmBtu) determined under § 96.184(d); 

or 

(C) The most stringent State or 

Federal NOX emissions limitation 

applicable to the CAIR NOX opt-in unit 

at any time during the control period for 

which CAIR NOX allowances are to be 

allocated. 

(iii) The permitting authority will 

allocate CAIR NOX allowances to the 

CAIR NOX opt-in unit in an amount 

equaling the heat input under paragraph 

(c)(2)(i) of this section, multiplied by the 

NOX emission rate under paragraph 

(c)(2)(ii) of this section, divided by 

2,000 lb/ton, and rounded to the nearest 

whole allowance as appropriate. 

(d) Recordation. (1) The 

Administrator will record, in the 

compliance account of the source that 

25362 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

includes the CAIR NOX opt-in unit, the 

CAIR NOX allowances allocated by the 

permitting authority to the CAIR NOX

opt-in unit under paragraph (a)(1) of this 

section. 

(2) By December 1 of the control 

period in which a CAIR opt-in unit 

enters the CAIR NOX Annual Trading 

Program under § 96.184(g) and 

December 1 of each year thereafter, the 

Administrator will record, in the 

compliance account of the source that 

includes the CAIR NOX opt-in unit, the 

CAIR NOX allowances allocated by the 

permitting authority to the CAIR NOX

opt-in unit under paragraph (a)(2) of this 

section.

■ 3. Part 96 is amended by adding 

subparts AAA through CCC, adding and 

reserving subparts DDD and EEE and 

adding subparts FFF through III to read 

as follows:

Subpart AAA—CAIR SO2 Trading Program 

General Provisions 

Sec. 

96.201 Purpose. 

96.202 Definitions. 

96.203 Measurements, abbreviations, and 

acronyms. 

96.204 Applicability. 

96.205 Retired unit exemption. 

96.206 Standard requirements. 

96.207 Computation of time. 

96.208 Appeal procedures.

Subpart BBB—CAIR Designated 

Representative for CAIR SO2 Sources 

96.210 Authorization and responsibilities of 

CAIR designated representative. 

96.211 Alternate CAIR designated 

representative. 

96.212 Changing CAIR designated 

representative and alternate CAIR 

designated representative; changes in 

owners and operators. 

96.213 Certificate of representation. 

96.214 Objections concerning CAIR 

designated representative.

Subpart CCC—Permits 

96.220 General CAIR SO2 Trading Program 

permit requirements. 

96.221 Submission of CAIR permit 

applications. 

96.222 Information requirements for CAIR 

permit applications. 

96.223 CAIR permit contents and term. 

96.224 CAIR permit revisions.

Subpart DDD—[Reserved]

Subpart EEE—[Reserved]

Subpart FFF—CAIR SO2 Allowance 

Tracking System 

96.250 [Reserved] 

96.251 Establishment of accounts. 

96.252 Responsibilities of CAIR authorized 

account representative. 

96.253 Recordation of CAIR SO2

allowances. 

96.254 Compliance with CAIR SO2

emissions limitation. 

96.255 Banking. 

96.256 Account error. 

96.257 Closing of general accounts.

Subpart GGG—CAIR SO2 Allowance 

Transfers 

96.260 Submission of CAIR SO2 allowance 

transfers. 

96.261 EPA recordation. 

96.262 Notification.

Subpart HHH—Monitoring and Reporting 

96.270 General requirements. 

96.271 Initial certification and 

recertification procedures. 

96.272 Out of control periods. 

96.273 Notifications. 

96.274 Recordkeeping and reporting. 

96.275 Petitions. 

96.276 Additional requirements to provide 

heat input data.

Subpart III—CAIR SO2 Opt-in Units 

96.280 Applicability. 

96.281 General. 

96.282 CAIR designated representative. 

96.283 Applying for CAIR opt-in permit. 

96.284 Opt-in process. 

96.285 CAIR opt-in permit contents. 

96.286 Withdrawal from CAIR SO2 Trading 

Program. 

96.287 Change in regulatory status. 

96.288 SO2 allowance allocations to CAIR 

SO2 opt-in units.

Subpart AAA—CAIR SO2 Trading 

Program General Provisions

§ 96.201 Purpose. 

This subpart and subparts BBB 

through III establish the model rule 

comprising general provisions and the 

designated representative, permitting, 

allowance, monitoring, and opt-in 

provisions for the State Clean Air 

Interstate Rule (CAIR) SO2 Trading 

Program, under section 110 of the Clean 

Air Act and § 51.124 of this chapter, as 

a means of mitigating interstate 

transport of fine particulates and sulfur 

dioxide. The owner or operator of a unit 

or a source shall comply with the 

requirements of this subpart and 

subparts BBB through III as a matter of 

federal law only if the State with 

jurisdiction over the unit and the source 

incorporates by reference such subparts 

or otherwise adopts the requirements of 

such subparts in accordance with 

§ 51.124(o)(1) or (2) of this chapter, the 

State submits to the Administrator one 

or more revisions of the State 

implementation plan that include such 

adoption, and the Administrator 

approves such revisions. If the State 

adopts the requirements of such 

subparts in accordance with 

§ 51.124(o)(1) or (2) of this chapter, then 

the State authorizes the Administrator 

to assist the State in implementing the 

CAIR SO2 Trading Program by carrying 

out the functions set forth for the 

Administrator in such subparts.

§ 96.202 Definitions. 

The terms used in this subpart and 

subparts BBB through III shall have the 

meanings set forth in this section as 

follows: 

Account number means the 

identification number given by the 

Administrator to each CAIR SO2

Allowance Tracking System account. 

Acid Rain emissions limitation means 

a limitation on emissions of sulfur 

dioxide or nitrogen oxides under the 

Acid Rain Program. 

Acid Rain Program means a multistate sulfur dioxide and nitrogen oxides 

air pollution control and emission 

reduction program established by the 

Administrator under title IV of the CAA 

and parts 72 through 78 of this chapter. 

Administrator means the 

Administrator of the United States 

Environmental Protection Agency or the 

Administrator’s duly authorized 

representative.

Allocate or allocation means, with 

regard to CAIR SO2 allowances issued 

under the Acid Rain Program, the 

determination by the Administrator of 

the amount of such CAIR SO2

allowances to be initially credited to a 

CAIR SO2 unit and, with regard to CAIR 

SO2 allowances issued under § 96.288, 

the determination by the permitting 

authority of the amount of such CAIR 

SO2 allowances to be initially credited 

to a CAIR SO2 unit. 

Allowance transfer deadline means, 

for a control period, midnight of March 

1, if it is a business day, or, if March 1 

is not a business day, midnight of the 

first business day thereafter 

immediately following the control 

period and is the deadline by which a 

CAIR SO2 allowance transfer must be 

submitted for recordation in a CAIR SO2

source’s compliance account in order to 

be used to meet the source’s CAIR SO2

emissions limitation for such control 

period in accordance with § 96.254. 

Alternate CAIR designated 

representative means, for a CAIR SO2

source and each CAIR SO2 unit at the 

source, the natural person who is 

authorized by the owners and operators 

of the source and all such units at the 

source in accordance with subparts BBB 

and III of this part, to act on behalf of 

the CAIR designated representative in 

matters pertaining to the CAIR SO2

Trading Program. If the CAIR SO2

source is also a CAIR NOX source, then 

this natural person shall be the same 

person as the alternate CAIR designated 

representative under the CAIR NOX

Annual Trading Program. If the CAIR 

SO2 source is also a CAIR NOX Ozone 

Season source, then this natural person 

shall be the same person as the alternate 

CAIR designated representative under 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25363

the CAIR NOX Ozone Season Trading 

Program. If the CAIR SO2 source is also 

subject to the Acid Rain Program, then 

this natural person shall be the same 

person as the alternate designated 

representative under the Acid Rain 

Program. 

Automated data acquisition and 

handling system or DAHS means that 

component of the continuous emission 

monitoring system, or other emissions 

monitoring system approved for use 

under subpart HHH of this part, 

designed to interpret and convert 

individual output signals from pollutant 

concentration monitors, flow monitors, 

diluent gas monitors, and other 

component parts of the monitoring 

system to produce a continuous record 

of the measured parameters in the 

measurement units required by subpart 

HHH of this part. 

Boiler means an enclosed fossil- or 

other-fuel-fired combustion device used 

to produce heat and to transfer heat to 

recirculating water, steam, or other 

medium. 

Bottoming-cycle cogeneration unit

means a cogeneration unit in which the 

energy input to the unit is first used to 

produce useful thermal energy and at 

least some of the reject heat from the 

useful thermal energy application or 

process is then used for electricity 

production. 

CAIR authorized account 

representative means, with regard to a 

general account, a responsible natural 

person who is authorized, in accordance 

with subparts BBB and III of this part, 

to transfer and otherwise dispose of 

CAIR SO2 allowances held in the 

general account and, with regard to a 

compliance account, the CAIR 

designated representative of the source. 

CAIR designated representative

means, for a CAIR SO2 source and each 

CAIR SO2 unit at the source, the natural 

person who is authorized by the owners 

and operators of the source and all such 

units at the source, in accordance with 

subparts BBB and III of this part, to 

represent and legally bind each owner 

and operator in matters pertaining to the 

CAIR SO2 Trading Program. If the CAIR 

SO2 source is also a CAIR NOX source, 

then this natural person shall be the 

same person as the CAIR designated 

representative under the CAIR NOX

Annual Trading Program. If the CAIR 

SO2 source is also a CAIR NOX Ozone 

Season source, then this natural person 

shall be the same person as the CAIR 

designated representative under the 

CAIR NOX Ozone Season Trading 

Program. If the CAIR SO2 source is also 

subject to the Acid Rain Program, then 

this natural person shall be the same 

person as the designated representative 

under the Acid Rain Program. 

CAIR NO X Annual Trading Program

means a multi-state nitrogen oxides air 

pollution control and emission 

reduction program approved and 

administered by the Administrator in 

accordance with subparts AA through II 

of this part and § 51.123 of this chapter, 

as a means of mitigating interstate 

transport of fine particulates and 

nitrogen oxides.

CAIR NOX Ozone Season source

means a source that includes one or 

more CAIR NOX Ozone Season units. 

CAIR NOX Ozone Season Trading 

Program means a multi-state nitrogen 

oxides air pollution control and 

emission reduction program approved 

and administered by the Administrator 

in accordance with subparts AAAA 

through IIII of this part and § 51.123 of 

this chapter, as a means of mitigating 

interstate transport of ozone and 

nitrogen oxides. 

CAIR NOX Ozone Season unit means 

a unit that is subject to the CAIR NOX

Ozone Season Trading Program under 

§ 96.304 and a CAIR NOX Ozone Season 

opt-in unit under subpart IIII of this 

part. 

CAIR NOX source means a source that 

includes one or more CAIR NOX units. 

CAIR NOX unit means a unit that is 

subject to the CAIR NOX Annual 

Trading Program under § 96.104 and a 

CAIR NOX opt-in unit under subpart II 

of this part. 

CAIR permit means the legally 

binding and federally enforceable 

written document, or portion of such 

document, issued by the permitting 

authority under subpart CCC of this 

part, including any permit revisions, 

specifying the CAIR SO2 Trading 

Program requirements applicable to a 

CAIR SO2 source, to each CAIR SO2 unit 

at the source, and to the owners and 

operators and the CAIR designated 

representative of the source and each 

such unit. 

CAIR SO2 allowance means a limited 

authorization issued by the 

Administrator under the Acid Rain 

Program, or by a permitting authority 

under § 96.288, to emit sulfur dioxide 

during the control period of the 

specified calendar year for which the 

authorization is allocated or of any 

calendar year thereafter under the CAIR 

SO2 Trading Program as follows: 

(1) For one CAIR SO2 allowance 

allocated for a control period in a year 

before 2010, one ton of sulfur dioxide, 

except as provided in § 96.254(b); 

(2) For one CAIR SO2 allowance 

allocated for a control period in 2010 

through 2014, 0.50 ton of sulfur dioxide, 

except as provided in § 96.254(b); and 

(3) For one CAIR SO2 allowance 

allocated for a control period in 2015 or 

later, 0.35 ton of sulfur dioxide, except 

as provided in § 96.254(b). 

An authorization to emit sulfur 

dioxide that is not issued under the 

Acid Rain Program or under the 

provisions of a State implementation 

plan that is approved under 

§ 51.124(o)(1) or (2) of this chapter shall 

not be a CAIR SO2 allowance. 

CAIR SO2 allowance deduction or 

deduct CAIR SO2 allowances means the 

permanent withdrawal of CAIR SO2

allowances by the Administrator from a 

compliance account in order to account 

for a specified number of tons of total 

sulfur dioxide emissions from all CAIR 

SO2 units at a CAIR SO2 source for a 

control period, determined in 

accordance with subpart HHH of this 

part, or to account for excess emissions. 

CAIR SO2 Allowance Tracking System

means the system by which the 

Administrator records allocations, 

deductions, and transfers of CAIR SO2

allowances under the CAIR SO2 Trading 

Program. This is the same system as the 

Allowance Tracking System under 

§ 72.2 of this chapter by which the 

Administrator records allocations, 

deduction, and transfers of Acid Rain 

SO2 allowances under the Acid Rain 

Program. 

CAIR SO2 Allowance Tracking System 

account means an account in the CAIR 

SO2 Allowance Tracking System 

established by the Administrator for 

purposes of recording the allocation, 

holding, transferring, or deducting of 

CAIR SO2 allowances. Such allowances 

will be allocated, held, deducted, or 

transferred only as whole allowances. 

CAIR SO2 allowances held or hold 

CAIR SO2 allowances means the CAIR 

SO2 allowances recorded by the 

Administrator, or submitted to the 

Administrator for recordation, in 

accordance with subparts FFF, GGG, 

and III of this part or part 73 of this 

chapter, in a CAIR SO2 Allowance 

Tracking System account. 

CAIR SO2 emissions limitation means, 

for a CAIR SO2 source, the tonnage 

equivalent of the CAIR SO2 allowances 

available for deduction for the source 

under § 96.254(a) and (b) for a control 

period. 

CAIR SO2 source means a source that 

includes one or more CAIR SO2 units. 

CAIR SO2 Trading Program means a 

multi-state sulfur dioxide air pollution 

control and emission reduction program 

approved and administered by the 

Administrator in accordance with 

subparts AAA through III of this part 

and § 51.124 of this chapter, as a means 

of mitigating interstate transport of fine 

particulates and sulfur dioxide. 

25364 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

CAIR SO2 unit means a unit that is 

subject to the CAIR SO2 Trading 

Program under § 96.204 and, except for 

purposes of § 96.205, a CAIR SO2 opt-in 

unit under subpart III of this part. 

Clean Air Act or CAA means the 

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

Coal means any solid fuel classified as 

anthracite, bituminous, subbituminous, 

or lignite. 

Coal-derived fuel means any fuel 

(whether in a solid, liquid, or gaseous 

state) produced by the mechanical, 

thermal, or chemical processing of coal. 

Coal-fired means combusting any 

amount of coal or coal-derived fuel, 

alone, or in combination with any 

amount of any other fuel. 

Cogeneration unit means a stationary, 

fossil-fuel-fired boiler or stationary, 

fossil-fuel-fired combustion turbine: 

(1) Having equipment used to produce 

electricity and useful thermal energy for 

industrial, commercial, heating, or 

cooling purposes through the sequential 

use of energy; and

(2) Producing during the 12-month 

period starting on the date the unit first 

produces electricity and during any 

calendar year after which the unit first 

produces electricity—

(i) For a topping-cycle cogeneration 

unit, 

(A) Useful thermal energy not less 

than 5 percent of total energy output; 

and 

(B) Useful power that, when added to 

one-half of useful thermal energy 

produced, is not less then 42.5 percent 

of total energy input, if useful thermal 

energy produced is 15 percent or more 

of total energy output, or not less than 

45 percent of total energy input, if 

useful thermal energy produced is less 

than 15 percent of total energy output. 

(ii) For a bottoming-cycle 

cogeneration unit, useful power not less 

than 45 percent of total energy input. 

Combustion turbine means:

(1) An enclosed device comprising a 

compressor, a combustor, and a turbine 

and in which the flue gas resulting from 

the combustion of fuel in the combustor 

passes through the turbine, rotating the 

turbine; and 

(2) If the enclosed device under 

paragraph (1) of this definition is 

combined cycle, any associated heat 

recovery steam generator and steam 

turbine. 

Commence commercial operation

means, with regard to a unit serving a 

generator: 

(1) To have begun to produce steam, 

gas, or other heated medium used to 

generate electricity for sale or use, 

including test generation, except as 

provided in § 96.205. 

(i) For a unit that is a CAIR SO2 unit 

under § 96.204 on the date the unit 

commences commercial operation as 

defined in paragraph (1) of this 

definition and that subsequently 

undergoes a physical change (other than 

replacement of the unit by a unit at the 

same source), such date shall remain the 

unit’s date of commencement of 

commercial operation. 

(ii) For a unit that is a CAIR SO2 unit 

under § 96.204 on the date the unit 

commences commercial operation as 

defined in paragraph (1) of this 

definition and that is subsequently 

replaced by a unit at the same source 

(e.g., repowered), the replacement unit 

shall be treated as a separate unit with 

a separate date for commencement of 

commercial operation as defined in 

paragraph (1), (2), or (3) of this 

definition as appropriate. 

(2) Notwithstanding paragraph (1) of 

this definition and except as provided 

in § 96.205, for a unit that is not a CAIR 

SO2 unit under § 96.204 on the date the 

unit commences commercial operation 

as defined in paragraph (1) of this 

definition and is not a unit under 

paragraph (3) of this definition, the 

unit’s date for commencement of 

commercial operation shall be the date 

on which the unit becomes a CAIR SO2

unit under § 96.204. 

(i) For a unit with a date for 

commencement of commercial 

operation as defined in paragraph (2) of 

this definition and that subsequently 

undergoes a physical change (other than 

replacement of the unit by a unit at the 

same source), such date shall remain the 

unit’s date of commencement of 

commercial operation. 

(ii) For a unit with a date for 

commencement of commercial 

operation as defined in paragraph (2) of 

this definition and that is subsequently 

replaced by a unit at the same source 

(e.g., repowered), the replacement unit 

shall be treated as a separate unit with 

a separate date for commencement of 

commercial operation as defined in 

paragraph (1), (2), or (3) of this 

definition as appropriate. 

(3) Notwithstanding paragraph (1) of 

this definition and except as provided 

in § 96.284(h) or § 96.287(b)(3), for a 

CAIR SO2 opt-in unit or a unit for which 

a CAIR opt-in permit application is 

submitted and not withdrawn and a 

CAIR opt-in permit is not yet issued or 

denied under subpart III of this part, the 

unit’s date for commencement of 

commercial operation shall be the date 

on which the owner or operator is 

required to start monitoring and 

reporting the SO2 emissions rate and the 

heat input of the unit under 

§ 96.284(b)(1)(i). 

(i) For a unit with a date for 

commencement of commercial 

operation as defined in paragraph (3) of 

this definition and that subsequently 

undergoes a physical change (other than 

replacement of the unit by a unit at the 

same source), such date shall remain the 

unit’s date of commencement of 

commercial operation.

(ii) For a unit with a date for 

commencement of commercial 

operation as defined in paragraph (3) of 

this definition and that is subsequently 

replaced by a unit at the same source 

(e.g., repowered), the replacement unit 

shall be treated as a separate unit with 

a separate date for commencement of 

commercial operation as defined in 

paragraph (1), (2), or (3) of this 

definition as appropriate. 

(4) Notwithstanding paragraphs (1) 

through (3) of this definition, for a unit 

not serving a generator producing 

electricity for sale, the unit’s date of 

commencement of operation shall also 

be the unit’s date of commencement of 

commercial operation. 

Commence operation means: 

(1) To have begun any mechanical, 

chemical, or electronic process, 

including, with regard to a unit, start-up 

of a unit’s combustion chamber, except 

as provided in § 96.205. 

(i) For a unit that is a CAIR SO2 unit 

under § 96.204 on the date the unit 

commences operation as defined in 

paragraph (1) of this definition and that 

subsequently undergoes a physical 

change (other than replacement of the 

unit by a unit at the same source), such 

date shall remain the unit’s date of 

commencement of operation. 

(ii) For a unit that is a CAIR SO2 unit 

under § 96.204 on the date the unit 

commences operation as defined in 

paragraph (1) of this definition and that 

is subsequently replaced by a unit at the 

same source (e.g., repowered), the 

replacement unit shall be treated as a 

separate unit with a separate date for 

commencement of operation as defined 

in paragraph (1), (2), or (3) of this 

definition as appropriate. 

(2) Notwithstanding paragraph (1) of 

this definition and except as provided 

in § 96.205, for a unit that is not a CAIR 

SO2 unit under § 96.204 on the date the 

unit commences operation as defined in 

paragraph (1) of this definition and is 

not a unit under paragraph (3) of this 

definition, the unit’s date for 

commencement of operation shall be the 

date on which the unit becomes a CAIR 

SO2 unit under § 96.204. 

(i) For a unit with a date for 

commencement of operation as defined 

in paragraph (2) of this definition and 

that subsequently undergoes a physical 

change (other than replacement of the 

unit by a unit at the same source), such 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25365

date shall remain the unit’s date of 

commencement of operation. 

(ii) For a unit with a date for 

commencement of operation as defined 

in paragraph (2) of this definition and 

that is subsequently replaced by a unit 

at the same source (e.g., repowered), the 

replacement unit shall be treated as a 

separate unit with a separate date for 

commencement of operation as defined 

in paragraph (1),(2), or (3) of this 

definition as appropriate. 

(3) Notwithstanding paragraph (1) of 

this definition and except as provided 

in § 96.284(h) or § 96.287(b)(3), for a 

CAIR SO2 opt-in unit or a unit for which 

a CAIR opt-in permit application is 

submitted and not withdrawn and a 

CAIR opt-in permit is not yet issued or 

denied under subpart III of this part, the 

unit’s date for commencement of 

operation shall be the date on which the 

owner or operator is required to start 

monitoring and reporting the SO2

emissions rate and the heat input of the 

unit under § 96.284(b)(1)(i). 

(i) For a unit with a date for 

commencement of operation as defined 

in paragraph (3) of this definition and 

that subsequently undergoes a physical 

change (other than replacement of the 

unit by a unit at the same source), such 

date shall remain the unit’s date of 

commencement of operation. 

(ii) For a unit with a date for 

commencement of operation as defined 

in paragraph (3) of this definition and 

that is subsequently replaced by a unit 

at the same source (e.g., repowered), the 

replacement unit shall be treated as a 

separate unit with a separate date for 

commencement of operation as defined 

in paragraph (1), (2), or (3) of this 

definition as appropriate. 

Common stack means a single flue 

through which emissions from 2 or 

more units are exhausted. 

Compliance account means a CAIR 

SO2 Allowance Tracking System 

account, established by the 

Administrator for a CAIR SO2 source 

subject to an Acid Rain emissions 

limitations under § 73.31(a) or (b) of this 

chapter or for any other CAIR SO2

source under subpart FFF or III of this 

part, in which any CAIR SO2 allowance 

allocations for the CAIR SO2 units at the 

source are initially recorded and in 

which are held any CAIR SO2

allowances available for use for a 

control period in order to meet the 

source’s CAIR SO2 emissions limitation 

in accordance with § 96.254. 

Continuous emission monitoring 

system or CEMS means the equipment 

required under subpart HHH of this part 

to sample, analyze, measure, and 

provide, by means of readings recorded 

at least once every 15 minutes (using an 

automated data acquisition and 

handling system (DAHS)), a permanent 

record of sulfur dioxide emissions, stack 

gas volumetric flow rate, stack gas 

moisture content, and oxygen or carbon 

dioxide concentration (as applicable), in 

a manner consistent with part 75 of this 

chapter. The following systems are the 

principal types of continuous emission 

monitoring systems required under 

subpart HHH of this part: 

(1) A flow monitoring system, 

consisting of a stack flow rate monitor 

and an automated data acquisition and 

handling system and providing a 

permanent, continuous record of stack 

gas volumetric flow rate, in standard 

cubic feet per hour (scfh);

(2) A sulfur dioxide monitoring 

system, consisting of a SO2 pollutant 

concentration monitor and an 

automated data acquisition handling 

system and providing a permanent, 

continuous record of SO2 emissions, in 

parts per million (ppm); 

(3) A moisture monitoring system, as 

defined in § 75.11(b)(2) of this chapter 

and providing a permanent, continuous 

record of the stack gas moisture content, 

in percent H2O; 

(4) A carbon dioxide monitoring 

system, consisting of a CO2 pollutant 

concentration monitor (or an oxygen 

monitor plus suitable mathematical 

equations from which the CO2

concentration is derived) and an 

automated data acquisition and 

handling system and providing a 

permanent, continuous record of CO2

emissions, in percent CO2; and 

(5) An oxygen monitoring system, 

consisting of an O2 concentration 

monitor and an automated data 

acquisition and handling system and 

providing a permanent, continuous 

record of O2 in percent O2. 

Control period means the period 

beginning January 1 of a calendar year 

and ending on December 31 of the same 

year, inclusive. 

Emissions means air pollutants 

exhausted from a unit or source into the 

atmosphere, as measured, recorded, and 

reported to the Administrator by the 

CAIR designated representative and as 

determined by the Administrator in 

accordance with subpart HHH of this 

part. 

Excess emissions means any ton, or 

portion of a ton, of sulfur dioxide 

emitted by the CAIR SO2 units at a CAIR 

SO2 source during a control period that 

exceeds the CAIR SO2 emissions 

limitation for the source, provided that 

any portion of a ton of excess emissions 

shall be treated as one ton of excess 

emissions. 

Fossil fuel means natural gas, 

petroleum, coal, or any form of solid, 

liquid, or gaseous fuel derived from 

such material. 

Fossil-fuel-fired means, with regard to 

a unit, combusting any amount of fossil 

fuel in any calendar year. 

General account means a CAIR SO2

Allowance Tracking System account, 

established under subpart FFF of this 

part, that is not a compliance account. 

Generator means a device that 

produces electricity. 

Heat input means, with regard to a 

specified period of time, the product (in 

mmBtu/time) of the gross calorific value 

of the fuel (in Btu/lb) divided by 

1,000,000 Btu/mmBtu and multiplied by 

the fuel feed rate into a combustion 

device (in lb of fuel/time), as measured, 

recorded, and reported to the 

Administrator by the CAIR designated 

representative and determined by the 

Administrator in accordance with 

subpart HHH of this part and excluding 

the heat derived from preheated 

combustion air, recirculated flue gases, 

or exhaust from other sources. 

Heat input rate means the amount of 

heat input (in mmBtu) divided by unit 

operating time (in hr) or, with regard to 

a specific fuel, the amount of heat input 

attributed to the fuel (in mmBtu) 

divided by the unit operating time (in 

hr) during which the unit combusts the 

fuel. 

Life-of-the-unit, firm power 

contractual arrangement means a unit 

participation power sales agreement 

under which a utility or industrial 

customer reserves, or is entitled to 

receive, a specified amount or 

percentage of nameplate capacity and 

associated energy generated by any 

specified unit and pays its proportional 

amount of such unit’s total costs, 

pursuant to a contract: 

(1) For the life of the unit; 

(2) For a cumulative term of no less 

than 30 years, including contracts that 

permit an election for early termination; 

or 

(3) For a period no less than 25 years 

or 70 percent of the economic useful life 

of the unit determined as of the time the 

unit is built, with option rights to 

purchase or release some portion of the 

nameplate capacity and associated 

energy generated by the unit at the end 

of the period. 

Maximum design heat input means, 

starting from the initial installation of a 

unit, the maximum amount of fuel per 

hour (in Btu/hr) that a unit is capable of 

combusting on a steady state basis as 

specified by the manufacturer of the 

unit, or, starting from the completion of 

any subsequent physical change in the 

unit resulting in a decrease in the 

maximum amount of fuel per hour (in 

Btu/hr) that a unit is capable of 

25366 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

combusting on a steady state basis, such 

decreased maximum amount as 

specified by the person conducting the 

physical change.

Monitoring system means any 

monitoring system that meets the 

requirements of subpart HHH of this 

part, including a continuous emissions 

monitoring system, an alternative 

monitoring system, or an excepted 

monitoring system under part 75 of this 

chapter. 

Most stringent State or Federal SO2

emissions limitation means, with regard 

to a unit, the lowest SO2 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, starting 

from the initial installation of a 

generator, the maximum electrical 

generating output (in MWe) that the 

generator is capable of producing on a 

steady state basis and during continuous 

operation (when not restricted by 

seasonal or other deratings) as specified 

by the manufacturer of the generator or, 

starting from the completion of any 

subsequent physical change in the 

generator resulting in an increase in the 

maximum electrical generating output 

(in MWe) that the generator is capable 

of producing on a steady state basis and 

during continuous operation (when not 

restricted by seasonal or other 

deratings), such increased maximum 

amount as specified by the person 

conducting the physical change. 

Operator means any person who 

operates, controls, or supervises a CAIR 

SO2 unit or a CAIR SO2 source and shall 

include, but not be limited to, any 

holding company, utility system, or 

plant manager of such a unit or source. 

Owner means any of the following 

persons: 

(1) With regard to a CAIR SO2 source 

or a CAIR SO2 unit at a source, 

respectively: 

(i) Any holder of any portion of the 

legal or equitable title in a CAIR SO2

unit at the source or the CAIR SO2 unit; 

(ii) Any holder of a leasehold interest 

in a CAIR SO2 unit at the source or the 

CAIR SO2 unit; or 

(iii) Any purchaser of power from a 

CAIR SO2 unit at the source or the CAIR 

SO2 unit under a life-of-the-unit, firm 

power contractual arrangement; 

provided that, unless expressly 

provided for in a leasehold agreement, 

owner shall not include a passive lessor, 

or a person who has an equitable 

interest through such lessor, whose 

rental payments are not based (either 

directly or indirectly) on the revenues or 

income from such CAIR SO2 unit; or 

(2) With regard to any general 

account, any person who has an 

ownership interest with respect to the 

CAIR SO2 allowances held in the 

general account and who is subject to 

the binding agreement for the CAIR 

authorized account representative to 

represent the person’s ownership 

interest with respect to CAIR SO2

allowances. 

Permitting authority means the State 

air pollution control agency, local 

agency, other State agency, or other 

agency authorized by the Administrator 

to issue or revise permits to meet the 

requirements of the CAIR SO2 Trading 

Program in accordance with subpart 

CCC of this part or, if no such agency 

has been so authorized, the 

Administrator. 

Potential electrical output capacity

means 33 percent of a unit’s maximum 

design heat input, divided by 3,413

Btu/kWh, divided by 1,000 kWh/MWh, 

and multiplied by 8,760 hr/yr. 

Receive or receipt of means, when 

referring to the permitting authority or 

the Administrator, to come into 

possession of a document, information, 

or correspondence (whether sent in hard 

copy or by authorized electronic 

transmission), as indicated in an official 

correspondence log, or by a notation 

made on the document, information, or 

correspondence, by the permitting 

authority or the Administrator in the 

regular course of business. 

Recordation, record, or recorded

means, with regard to CAIR SO2

allowances, the movement of CAIR SO2

allowances by the Administrator into or 

between CAIR SO2 Allowance Tracking 

System accounts, for purposes of 

allocation, transfer, or deduction. 

Reference method means any direct 

test method of sampling and analyzing 

for an air pollutant as specified in 

§ 75.22 of this chapter. 

Repowered means, with regard to a 

unit, replacement of a coal-fired boiler 

with one of the following coal-fired 

technologies at the same source as the 

coal-fired boiler:

(1) Atmospheric or pressurized 

fluidized bed combustion; 

(2) Integrated gasification combined 

cycle; 

(3) Magnetohydrodynamics; 

(4) Direct and indirect coal-fired 

turbines; 

(5) Integrated gasification fuel cells; or 

(6) As determined by the 

Administrator in consultation with the 

Secretary of Energy, a derivative of one 

or more of the technologies under 

paragraphs (1) through (5) of this 

definition and any other coal-fired 

technology capable of controlling 

multiple combustion emissions 

simultaneously with improved boiler or 

generation efficiency and with 

significantly greater waste reduction 

relative to the performance of 

technology in widespread commercial 

use as of January 1, 2005. 

Serial number means, for a CAIR SO2

allowance, the unique identification 

number assigned to each CAIR SO2

allowance by the Administrator. 

Sequential use of energy means: 

(1) For a topping-cycle cogeneration 

unit, the use of reject heat from 

electricity production in a useful 

thermal energy application or process; 

or 

(2) For a bottoming-cycle cogeneration 

unit, the use of reject heat from useful 

thermal energy application or process in 

electricity production. 

Source means all buildings, 

structures, or installations located in 

one or more contiguous or adjacent 

properties under common control of the 

same person or persons. For purposes of 

section 502(c) of the Clean Air Act, a 

‘‘source,’’ including a ‘‘source’’ with 

multiple units, shall be considered a 

single ‘‘facility.’’

State means one of the States or the 

District of Columbia that adopts the 

CAIR SO2 Trading Program pursuant to 

§ 51.124 (o)(1) or (2) of this chapter. 

Submit or serve means to send or 

transmit a document, information, or 

correspondence to the person specified 

in accordance with the applicable 

regulation: 

(1) In person; 

(2) By United States Postal Service; or 

(3) By other means of dispatch or 

transmission and delivery. Compliance 

with any ‘‘submission’’ or ‘‘service’’

deadline shall be determined by the 

date of dispatch, transmission, or 

mailing and not the date of receipt. 

Title V operating permit means a 

permit issued under title V of the Clean 

Air Act and part 70 or part 71 of this 

chapter. 

Title V operating permit regulations

means the regulations that the 

Administrator has approved or issued as 

meeting the requirements of title V of 

the Clean Air Act and part 70 or 71 of 

this chapter. 

Ton means 2,000 pounds. For the 

purpose of determining compliance 

with the CAIR SO2 emissions limitation, 

total tons of sulfur dioxide emissions for 

a control period shall be calculated as 

the sum of all recorded hourly 

emissions (or the mass equivalent of the 

recorded hourly emission rates) in 

accordance with subpart HHH of this 

part, but with any remaining fraction of 

a ton equal to or greater than 0.50 tons 

deemed to equal one ton and any 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25367

remaining fraction of a ton less than 

0.50 tons deemed to equal zero tons. 

Topping-cycle cogeneration unit

means a cogeneration unit in which the 

energy input to the unit is first used to 

produce useful power, including 

electricity, and at least some of the 

reject heat from the electricity 

production is then used to provide 

useful thermal energy. 

Total energy input means, with regard 

to a cogeneration unit, total energy of all 

forms supplied to the cogeneration unit, 

excluding energy produced by the 

cogeneration unit itself. 

Total energy output means, with 

regard to a cogeneration unit, the sum 

of useful power and useful thermal 

energy produced by the cogeneration 

unit. 

Unit means a stationary, fossil-fuelfired boiler or combustion turbine or 

other stationary, fossil-fuel-fired 

combustion device. 

Unit operating day means a calendar 

day in which a unit combusts any fuel. 

Unit operating hour or hour of unit 

operation means an hour in which a 

unit combusts any fuel. 

Useful power means, with regard to a 

cogeneration unit, electricity or 

mechanical energy made available for 

use, excluding any such energy used in 

the power production process (which 

process includes, but is not limited to, 

any on-site processing or treatment of 

fuel combusted at the unit and any onsite emission controls). 

Useful thermal energy means, with 

regard to a cogeneration unit, thermal 

energy that is: 

(1) Made available to an industrial or 

commercial process (not a power 

production process), excluding any heat 

contained in condensate return or 

makeup water; 

(2) Used in a heat application (e.g., 

space heating or domestic hot water 

heating); or 

(3) Used in a space cooling 

application (i.e., thermal energy used by 

an absorption chiller). 

Utility power distribution system

means the portion of an electricity grid 

owned or operated by a utility and 

dedicated to delivering electricity to 

customers.

§ 96.203 Measurements, abbreviations, 

and acronyms. 

Measurements, abbreviations, and 

acronyms used in this part are defined 

as follows:

Btu-British thermal unit. 

CO2—carbon dioxide. 

NOX—nitrogen oxides.

hr—hour. 

kW—kilowatt electrical. 

kWh—kilowatt hour. 

mmBtu—million Btu. 

MWe—megawatt electrical. 

MWh—megawatt hour. 

O2—oxygen. 

ppm—parts per million. 

lb—pound. 

scfh—standard cubic feet per hour. 

SO2—sulfur dioxide. 

H2O—water. 

yr—year.

§ 96.204 Applicability. 

The following units in a State shall be 

CAIR SO2 units, and any source that 

includes one or more such units shall be 

a CAIR SO2 source, subject to the 

requirements of this subpart and 

subparts BBB through HHH of this part: 

(a) Except as provided in paragraph 

(b) of this section, a stationary, fossilfuel-fired boiler or stationary, fossilfuel-fired combustion turbine serving at 

any time, since the start-up of the unit’s 

combustion chamber, a generator with 

nameplate capacity of more than 25 

MWe producing electricity for sale. 

(b) For a unit that qualifies as a 

cogeneration unit during the 12-month 

period starting on the date the unit first 

produces electricity and continues to 

qualify as a cogeneration unit, a 

cogeneration unit serving at any time a 

generator with nameplate capacity of 

more than 25 MWe and supplying in 

any calendar year more than one-third 

of the unit’s potential electric output 

capacity or 219,000 MWh, whichever is 

greater, to any utility power distribution 

system for sale. If a unit qualifies as a 

cogeneration unit during the 12-month 

period starting on the date the unit first 

produces electricity but subsequently no 

longer qualifies as a cogeneration unit, 

the unit shall be subject to paragraph (a) 

of this section starting on the day on 

which the unit first no longer qualifies 

as a cogeneration unit.

§ 96.205 Retired unit exemption. 

(a)(1) Any CAIR SO2 unit that is 

permanently retired and is not a CAIR 

SO2 opt-in unit under subpart III of this 

part shall be exempt from the CAIR SO2

Trading Program, except for the 

provisions of this section, § 96.202, 

§ 96.203, § 96.204, § 96.206(c)(4) 

through (8), § 96.207, and subparts FFF 

and GGG of this part. 

(2) The exemption under paragraph 

(a)(1) of this section shall become 

effective the day on which the CAIR SO2

unit is permanently retired. Within 30 

days of the unit’s permanent retirement, 

the CAIR designated representative shall 

submit a statement to the permitting 

authority otherwise responsible for 

administering any CAIR permit for the 

unit and shall submit a copy of the 

statement to the Administrator. The 

statement shall state, in a format 

prescribed by the permitting authority, 

that the unit was permanently retired on 

a specific date and will comply with the 

requirements of paragraph (b) of this 

section. 

(3) After receipt of the statement 

under paragraph (a)(2) of this section, 

the permitting authority will amend any 

permit under subpart CCC of this part 

covering the source at which the unit is 

located to add the provisions and 

requirements of the exemption under 

paragraphs (a)(1) and (b) of this section. 

(b) Special provisions. (1) A unit 

exempt under paragraph (a) of this 

section shall not emit any sulfur 

dioxide, starting on the date that the 

exemption takes effect. 

(2) For a period of 5 years from the 

date the records are created, the owners 

and operators of a unit exempt under 

paragraph (a) of 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 before the end of the 

period, in writing by the permitting 

authority or the Administrator. The 

owners and operators bear the burden of 

proof that the unit is permanently 

retired. 

(3) The owners and operators and, to 

the extent applicable, the CAIR 

designated representative of a unit 

exempt under paragraph (a) of this 

section shall comply with the 

requirements of the CAIR SO2 Trading 

Program concerning all periods for 

which the exemption is not in effect, 

even if such requirements arise, or must 

be complied with, after the exemption 

takes effect. 

(4) A unit exempt under paragraph (a) 

of this section and located at a source 

that is required, or but for this 

exemption would be required, to have a 

title V operating permit shall not resume 

operation unless the CAIR designated 

representative of the source submits a 

complete CAIR permit application 

under § 96.222 for the unit not less than 

18 months (or such lesser time provided 

by the permitting authority) before the 

later of January 1, 2010 or the date on 

which the unit resumes operation. 

(5) On the earlier of the following 

dates, a unit exempt under paragraph (a) 

of this section shall lose its exemption: 

(i) The date on which the CAIR 

designated representative submits a 

CAIR permit application for the unit 

under paragraph (b)(4) of this section; 

(ii) The date on which the CAIR 

designated representative is required 

under paragraph (b)(4) of this section to 

submit a CAIR permit application for 

the unit; or 

25368 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

(iii) The date on which the unit 

resumes operation, if the CAIR 

designated representative is not 

required to submit a CAIR permit 

application for the unit.

(6) For the purpose of applying 

monitoring, reporting, and 

recordkeeping requirements under 

subpart HHH of this part, a unit that 

loses its exemption under paragraph (a) 

of this section shall be treated as a unit 

that commences operation and 

commercial operation on the first date 

on which the unit resumes operation.

§ 96.206 Standard requirements. 

(a) Permit requirements. (1) The CAIR 

designated representative of each CAIR 

SO2 source required to have a title V 

operating permit and each CAIR SO2

unit required to have a title V operating 

permit at the source shall: 

(i) Submit to the permitting authority 

a complete CAIR permit application 

under § 96.222 in accordance with the 

deadlines specified in § 96.221(a) and 

(b); and 

(ii) Submit in a timely manner any 

supplemental information that the 

permitting authority determines is 

necessary in order to review a CAIR 

permit application and issue or deny a 

CAIR permit. 

(2) The owners and operators of each 

CAIR SO2 source required to have a title 

V operating permit and each CAIR SO2

unit required to have a title V operating 

permit at the source shall have a CAIR 

permit issued by the permitting 

authority under subpart CCC of this part 

for the source and operate the source 

and the unit in compliance with such 

CAIR permit. 

(3) Except as provided in subpart III 

of this part, the owners and operators of 

a CAIR SO2 source that is not otherwise 

required to have a title V operating 

permit and each CAIR SO2 unit that is 

not otherwise required to have a title V 

operating permit are not required to 

submit a CAIR permit application, and 

to have a CAIR permit, under subpart 

CCC of this part for such CAIR SO2

source and such CAIR SO2 unit. 

(b) Monitoring, reporting, and 

recordkeeping requirements. (1) The 

owners and operators, and the CAIR 

designated representative, of each CAIR 

SO2 source and each CAIR SO2 unit at 

the source shall comply with the 

monitoring, reporting, and 

recordkeeping requirements of subpart 

HHH of this part. 

(2) The emissions measurements 

recorded and reported in accordance 

with subpart HHH of this part shall be 

used to determine compliance by each 

CAIR SO2 source with the CAIR SO2

emissions limitation under paragraph 

(c) of this section. 

(c) Sulfur dioxide emission 

requirements. (1) As of the allowance 

transfer deadline for a control period, 

the owners and operators of each CAIR 

SO2 source and each CAIR SO2 unit at 

the source shall hold, in the source’s 

compliance account, a tonnage 

equivalent in CAIR SO2 allowances 

available for compliance deductions for 

the control period, as determined in 

accordance with § 96.254(a) and (b), not 

less than the tons of total sulfur dioxide 

emissions for the control period from all 

CAIR SO2 units at the source, as 

determined in accordance with subpart 

HHH of this part. 

(2) A CAIR SO2 unit shall be subject 

to the requirements under paragraph 

(c)(1) of this section starting on the later 

of January 1, 2010 or the deadline for 

meeting the unit’s monitor certification 

requirements under § 96.270(b)(1),(2), or 

(5). 

(3) A CAIR SO2 allowance shall not be 

deducted, for compliance with the 

requirements under paragraph (c)(1) of 

this section, for a control period in a 

calendar year before the year for which 

the CAIR SO2 allowance was allocated. 

(4) CAIR SO2 allowances shall be held 

in, deducted from, or transferred into or 

among CAIR SO2 Allowance Tracking 

System accounts in accordance with 

subparts FFF and GGG of this part. 

(5) A CAIR SO2 allowance is a limited 

authorization to emit sulfur dioxide in 

accordance with the CAIR SO2 Trading 

Program. No provision of the CAIR SO2

Trading Program, the CAIR permit 

application, the CAIR permit, or an 

exemption under § 96.205 and no 

provision of law shall be construed to 

limit the authority of the State or the 

United States to terminate or limit such 

authorization. 

(6) A CAIR SO2 allowance does not 

constitute a property right. 

(7) Upon recordation by the 

Administrator under subpart FFF, GGG, 

or III of this part, every allocation, 

transfer, or deduction of a CAIR SO2

allowance to or from a CAIR SO2 unit’s 

compliance account is incorporated 

automatically in any CAIR permit of the 

source that includes the CAIR SO2 unit. 

(d) Excess emissions requirements—

(1) If a CAIR SO2 source emits sulfur 

dioxide during any control period in 

excess of the CAIR SO2 emissions 

limitation, then: 

(i) The owners and operators of the 

source and each CAIR SO2 unit at the 

source shall surrender the CAIR SO2

allowances required for deduction 

under § 96.254(d)(1) and pay any fine, 

penalty, or assessment or comply with 

any other remedy imposed, for the same 

violations, under the Clean Air Act or 

applicable State law; and 

(ii) Each ton of such excess emissions 

and each day of such control period 

shall constitute a separate violation of 

this subpart, the Clean Air Act, and 

applicable State law. 

(2) [Reserved] 

(e) Recordkeeping and reporting 

requirements. (1) Unless otherwise 

provided, the owners and operators of 

the CAIR SO2 source and each CAIR SO2

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 before the end of 5 years, in 

writing by the permitting authority or 

the Administrator.

(i) The certificate of representation 

under § 96.213 for the CAIR designated 

representative for the source and each 

CAIR SO2 unit at the source and all 

documents that demonstrate the truth of 

the statements in the certificate of 

representation; provided that the 

certificate and documents shall be 

retained on site at the source beyond 

such 5-year period until such 

documents are superseded because of 

the submission of a new certificate of 

representation under § 96.213 changing 

the CAIR designated representative. 

(ii) All emissions monitoring 

information, in accordance with subpart 

HHH of this part, provided that to the 

extent that subpart HHH of this part 

provides for a 3-year period for 

recordkeeping, the 3-year period shall 

apply. 

(iii) Copies of all reports, compliance 

certifications, and other submissions 

and all records made or required under 

the CAIR SO2 Trading Program. 

(iv) Copies of all documents used to 

complete a CAIR permit application and 

any other submission under the CAIR 

SO2 Trading Program or to demonstrate 

compliance with the requirements of the 

CAIR SO2 Trading Program. 

(2) The CAIR designated 

representative of a CAIR SO2 source and 

each CAIR SO2 unit at the source shall 

submit the reports required under the 

CAIR SO2 Trading Program, including 

those under subpart HHH of this part. 

(f) Liability. (1) Each CAIR SO2 source 

and each CAIR SO2 unit shall meet the 

requirements of the CAIR SO2 Trading 

Program. 

(2) Any provision of the CAIR SO2

Trading Program that applies to a CAIR 

SO2 source or the CAIR designated 

representative of a CAIR SO2 source 

shall also apply to the owners and 

operators of such source and of the 

CAIR SO2 units at the source. 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25369

(3) Any provision of the CAIR SO2

Trading Program that applies to a CAIR 

SO2 unit or the CAIR designated 

representative of a CAIR SO2 unit shall 

also apply to the owners and operators 

of such unit. 

(g) Effect on other authorities. No 

provision of the CAIR SO2 Trading 

Program, a CAIR permit application, a 

CAIR permit, or an exemption under 

§ 96.205 shall be construed as 

exempting or excluding the owners and 

operators, and the CAIR designated 

representative, of a CAIR SO2 source or 

CAIR SO2 unit from compliance with 

any other provision of the applicable, 

approved State implementation plan, a 

federally enforceable permit, or the 

Clean Air Act.

§ 96.207 Computation of time. 

(a) Unless otherwise stated, any time 

period scheduled, under the CAIR SO2

Trading Program, to begin on the 

occurrence of an act or event shall begin 

on the day the act or event occurs. 

(b) Unless otherwise stated, any time 

period scheduled, under the CAIR SO2

Trading Program, to begin before the 

occurrence of an act or event shall be 

computed so that the period ends the 

day before the act or event occurs. 

(c) Unless otherwise stated, if the final 

day of any time period, under the CAIR 

SO2 Trading Program, falls on a 

weekend or a State or Federal holiday, 

the time period shall be extended to the 

next business day.

§ 96.208 Appeal procedures. 

The appeal procedures for decisions 

of the Administrator under the CAIR 

SO2 Trading Program are set forth in 

part 78 of this chapter.

Subpart BBB—CAIR Designated 

Representative for CAIR SO2 Sources

§ 96.210 Authorization and responsibilities 

of CAIR designated representative. 

(a) Except as provided under § 96.211, 

each CAIR SO2 source, including all 

CAIR SO2 units at the source, shall have 

one and only one CAIR designated 

representative, with regard to all matters 

under the CAIR SO2 Trading Program 

concerning the source or any CAIR SO2

unit at the source. 

(b) The CAIR designated 

representative of the CAIR SO2 source 

shall be selected by an agreement 

binding on the owners and operators of 

the source and all CAIR SO2 units at the 

source and shall act in accordance with 

the certification statement in 

§ 96.213(a)(4)(iv).

(c) Upon receipt by the Administrator 

of a complete certificate of 

representation under § 96.213, the CAIR 

designated representative of the source 

shall represent and, by his or her 

representations, actions, inactions, or 

submissions, legally bind each owner 

and operator of the CAIR SO2 source 

represented and each CAIR SO2 unit at 

the source in all matters pertaining to 

the CAIR SO2 Trading Program, 

notwithstanding any agreement between 

the CAIR designated representative and 

such owners and operators. The owners 

and operators shall be bound by any 

decision or order issued to the CAIR 

designated representative by the 

permitting authority, the Administrator, 

or a court regarding the source or unit. 

(d) No CAIR permit will be issued, no 

emissions data reports will be accepted, 

and no CAIR SO2 Allowance Tracking 

System account will be established for 

a CAIR SO2 unit at a source, until the 

Administrator has received a complete 

certificate of representation under 

§ 96.213 for a CAIR designated 

representative of the source and the 

CAIR SO2 units at the source. 

(e)(1) Each submission under the 

CAIR SO2 Trading Program shall be 

submitted, signed, and certified by the 

CAIR designated representative for each 

CAIR SO2 source on behalf of which the 

submission is made. Each such 

submission shall include the following 

certification statement by the CAIR 

designated representative: ‘‘I am 

authorized to make this submission on 

behalf of the owners and operators of 

the source or units for which the 

submission is made. I certify under 

penalty of law that I have personally 

examined, and am familiar with, the 

statements and information submitted 

in this document and all its 

attachments. Based on my inquiry of 

those individuals with primary 

responsibility for obtaining the 

information, I certify that the statements 

and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’

(2) The permitting authority and the 

Administrator will accept or act on a 

submission made on behalf of owner or 

operators of a CAIR SO2 source or a 

CAIR SO2 unit only if the submission 

has been made, signed, and certified in 

accordance with paragraph (e)(1) of this 

section.

§ 96.211 Alternate CAIR designated 

representative. 

(a) A certificate of representation 

under § 96.213 may designate one and 

only one alternate CAIR designated 

representative, who may act on behalf of 

the CAIR designated representative. The 

agreement by which the alternate CAIR 

designated representative is selected 

shall include a procedure for 

authorizing the alternate CAIR 

designated representative to act in lieu 

of the CAIR designated representative.

(b) Upon receipt by the Administrator 

of a complete certificate of 

representation under § 96.213, any 

representation, action, inaction, or 

submission by the alternate CAIR 

designated representative shall be 

deemed to be a representation, action, 

inaction, or submission by the CAIR 

designated representative. 

(c) Except in this section and 

§§ 96.202, 96.210(a) and (d), 96.212, 

96.213, 96.251, and 96.282, whenever 

the term ‘‘CAIR designated 

representative’’ is used in subparts AAA 

through III of this part, the term shall be 

construed to include the CAIR 

designated representative or any 

alternate CAIR designated 

representative.

§ 96.212 Changing CAIR designated 

representative and alternate CAIR 

designated representative; changes in 

owners and operators. 

(a) Changing CAIR designated 

representative. The CAIR designated 

representative may be changed at any 

time upon receipt by the Administrator 

of a superseding complete certificate of 

representation under § 96.213. 

Notwithstanding any such change, all 

representations, actions, inactions, and 

submissions by the previous CAIR 

designated representative before the 

time and date when the Administrator 

receives the superseding certificate of 

representation shall be binding on the 

new CAIR designated representative and 

the owners and operators of the CAIR 

SO2 source and the CAIR SO2 units at 

the source. 

(b) Changing alternate CAIR 

designated representative. The alternate 

CAIR designated representative may be 

changed at any time upon receipt by the 

Administrator of a superseding 

complete certificate of representation 

under § 96.213. Notwithstanding any 

such change, all representations, 

actions, inactions, and submissions by 

the previous alternate CAIR designated 

representative before the time and date 

when the Administrator receives the 

superseding certificate of representation 

shall be binding on the new alternate 

CAIR designated representative and the 

owners and operators of the CAIR SO2

source and the CAIR SO2 units at the 

source. 

(c) Changes in owners and operators.

(1) In the event a new owner or operator 

of a CAIR SO2 source or a CAIR SO2 unit 

25370 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

is not included in the list of owners and 

operators in the certificate of 

representation under § 96.213, such new 

owner or operator shall be deemed to be 

subject to and bound by the certificate 

of representation, the representations, 

actions, inactions, and submissions of 

the CAIR designated representative and 

any alternate CAIR designated 

representative of the source or unit, and 

the decisions and orders of the 

permitting authority, the Administrator, 

or a court, as if the new owner or 

operator were included in such list. 

(2) Within 30 days following any 

change in the owners and operators of 

a CAIR SO2 source or a CAIR SO2 unit, 

including the addition of a new owner 

or operator, the CAIR designated 

representative or any alternate CAIR 

designated representative shall submit a 

revision to the certificate of 

representation under § 96.213 amending 

the list of owners and operators to 

include the change.

§ 96.213 Certificate of representation. 

(a) A complete certificate of 

representation for a CAIR designated 

representative or an alternate CAIR 

designated representative shall include 

the following elements in a format 

prescribed by the Administrator: 

(1) Identification of the CAIR SO2

source, and each CAIR SO2 unit at the 

source, for which the certificate of 

representation is submitted. 

(2) The name, address, e-mail address 

(if any), telephone number, and 

facsimile transmission number (if any) 

of the CAIR designated representative 

and any alternate CAIR designated 

representative. 

(3) A list of the owners and operators 

of the CAIR SO2 source and of each 

CAIR SO2 unit at the source. 

(4) The following certification 

statements by the CAIR designated 

representative and any alternate CAIR 

designated representative—

(i) ‘‘I certify that I was selected as the 

CAIR designated representative or 

alternate CAIR designated 

representative, as applicable, by an 

agreement binding on the owners and 

operators of the source and each CAIR 

SO2 unit at the source.’’

(ii) ‘‘I certify that I have all the 

necessary authority to carry out my 

duties and responsibilities under the 

CAIR SO2 Trading Program on behalf of 

the owners and operators of the source 

and of each CAIR SO2 unit at the source 

and that each such owner and operator 

shall be fully bound by my 

representations, actions, inactions, or 

submissions.’’

(iii) ‘‘I certify that the owners and 

operators of the source and of each 

CAIR SO2 unit at the source shall be 

bound by any order issued to me by the 

Administrator, the permitting authority, 

or a court regarding the source or unit.’’

(iv) ‘‘Where there are multiple holders 

of a legal or equitable title to, or a 

leasehold interest in, a CAIR SO2 unit, 

or where a customer purchases power 

from a CAIR SO2 unit under a life-ofthe-unit, firm power contractual 

arrangement, I certify that: I have given 

a written notice of my selection as the 

‘CAIR designated representative’ or 

‘alternate CAIR designated 

representative’, as applicable, and of the 

agreement by which I was selected to 

each owner and operator of the source 

and of each CAIR SO2 unit at the source; 

and CAIR SO2 allowances and proceeds 

of transactions involving CAIR SO2

allowances will be deemed to be held or 

distributed in proportion to each 

holder’s legal, equitable, leasehold, or 

contractual reservation or entitlement, 

except that, if such multiple holders 

have expressly provided for a different 

distribution of CAIR SO2 allowances by 

contract, CAIR SO2 allowances and 

proceeds of transactions involving CAIR 

SO2 allowances will be deemed to be 

held or distributed in accordance with 

the contract.’’

(5) The signature of the CAIR 

designated representative and any 

alternate CAIR designated 

representative and the dates signed. 

(b) Unless otherwise required by the 

permitting authority or the 

Administrator, documents of agreement 

referred to in the certificate of 

representation shall not be submitted to 

the permitting authority or the 

Administrator. Neither the permitting 

authority nor the Administrator shall be 

under any obligation to review or 

evaluate the sufficiency of such 

documents, if submitted.

§ 96.214 Objections concerning CAIR 

designated representative. 

(a) Once a complete certificate of 

representation under § 96.213 has been 

submitted and received, the permitting 

authority and the Administrator will 

rely on the certificate of representation 

unless and until a superseding complete 

certificate of representation under 

§ 96.213 is received by the 

Administrator. 

(b) Except as provided in § 96.212(a) 

or (b), no objection or other 

communication submitted to the 

permitting authority or the 

Administrator concerning the 

authorization, or any representation, 

action, inaction, or submission, of the 

CAIR designated representative shall 

affect any representation, action, 

inaction, or submission of the CAIR 

designated representative or the finality 

of any decision or order by the 

permitting authority or the 

Administrator under the CAIR SO2

Trading Program. 

(c) Neither the permitting authority 

nor the Administrator will adjudicate 

any private legal dispute concerning the 

authorization or any representation, 

action, inaction, or submission of any 

CAIR designated representative, 

including private legal disputes 

concerning the proceeds of CAIR SO2

allowance transfers.

Subpart CCC—Permits

§ 96.220 General CAIR SO2 Trading 

Program permit requirements. 

(a) For each CAIR SO2 source required 

to have a title V operating permit or 

required, under subpart III of this part, 

to have a title V operating permit or 

other federally enforceable permit, such 

permit shall include a CAIR permit 

administered by the permitting 

authority for the title V operating permit 

or the federally enforceable permit as 

applicable. The CAIR portion of the title 

V permit or other federally enforceable 

permit as applicable shall be 

administered in accordance with the 

permitting authority’s title V operating 

permits regulations promulgated under 

part 70 or 71 of this chapter or the 

permitting authority’s regulations for 

other federally enforceable permits as 

applicable, except as provided 

otherwise by this subpart and subpart III 

of this part. 

(b) Each CAIR permit shall contain, 

with regard to the CAIR SO2 source and 

the CAIR SO2 units at the source, all 

applicable CAIR SO2 Trading Program, 

CAIR NOX Annual Trading Program, 

and CAIR NOX Ozone Season Trading 

Program requirements and shall be a 

complete and separable portion of the 

title V operating permit or other 

federally enforceable permit under 

paragraph (a) of this section.

§ 96.221 Submission of CAIR permit 

applications. 

(a) Duty to apply. The CAIR 

designated representative of any CAIR 

SO2 source required to have a title V 

operating permit shall submit to the 

permitting authority a complete CAIR 

permit application under § 96.222 for 

the source covering each CAIR SO2 unit 

at the source at least 18 months (or such 

lesser time provided by the permitting 

authority) before the later of January 1, 

2010 or the date on which the CAIR SO2

unit commences operation. 

(b) Duty to Reapply. For a CAIR SO2

source required to have a title V 

operating permit, the CAIR designated 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25371

representative shall submit a complete 

CAIR permit application under § 96.222 

for the source covering each CAIR SO2

unit at the source to renew the CAIR 

permit in accordance with the 

permitting authority’s title V operating 

permits regulations addressing permit 

renewal.

§ 96.222 Information requirements for 

CAIR permit applications. 

A complete CAIR permit application 

shall include the following elements 

concerning the CAIR SO2 source for 

which the application is submitted, in a 

format prescribed by the permitting 

authority: 

(a) Identification of the CAIR SO2

source; 

(b) Identification of each CAIR SO2

unit at the CAIR SO2 source; and 

(c) The standard requirements under 

§ 96.206.

§ 96.223 CAIR permit contents and term. 

(a) Each CAIR permit will contain, in 

a format prescribed by the permitting 

authority, all elements required for a 

complete CAIR permit application 

under § 96.222. 

(b) Each CAIR permit is deemed to 

incorporate automatically the 

definitions of terms under § 96.202 and, 

upon recordation by the Administrator 

under subpart FFF, GGG, or III of this 

part, every allocation, transfer, or 

deduction of a CAIR SO2 allowance to 

or from the compliance account of the 

CAIR SO2 source covered by the permit. 

(c) The term of the CAIR permit will 

be set by the permitting authority, as 

necessary to facilitate coordination of 

the renewal of the CAIR permit with 

issuance, revision, or renewal of the 

CAIR SO2 source’s title V operating 

permit or other federally enforceable 

permit as applicable.

§ 96.224 CAIR permit revisions. 

Except as provided in § 96.223(b), the 

permitting authority will revise the 

CAIR permit, as necessary, in 

accordance with the permitting 

authority’s title V operating permits 

regulations or the permitting authority’s 

regulations for other federally 

enforceable permits as applicable 

addressing permit revisions.

Subpart DDD—[Reserved]

Subpart EEE—[Reserved]

Subpart FFF—CAIR SO2 Allowance 

Tracking System

§ 96.250 [Reserved]

§ 96.251 Establishment of accounts. 

(a) Compliance accounts. Except as 

provided in § 96.284(e), upon receipt of 

a complete certificate of representation 

under § 96.213, the Administrator will 

establish a compliance account for the 

CAIR SO2 source for which the 

certificate of representation was 

submitted, unless the source already has 

a compliance account. 

(b) General accounts—(1) Application 

for general account.

(i) Any person may apply to open a 

general account for the purpose of 

holding and transferring CAIR SO2

allowances. An application for a general 

account may designate one and only one 

CAIR authorized account representative 

and one and only one alternate CAIR 

authorized account representative who 

may act on behalf of the CAIR 

authorized account representative. The 

agreement by which the alternate CAIR 

authorized account representative is 

selected shall include a procedure for 

authorizing the alternate CAIR 

authorized account representative to act 

in lieu of the CAIR authorized account 

representative. 

(ii) A complete application for a 

general account shall be submitted to 

the Administrator and shall include the 

following elements in a format 

prescribed by the Administrator: 

(A) Name, mailing address, e-mail 

address (if any), telephone number, and 

facsimile transmission number (if any) 

of the CAIR authorized account 

representative and any alternate CAIR 

authorized account representative; 

(B) Organization name and type of 

organization, if applicable; 

(C) A list of all persons subject to a 

binding agreement for the CAIR 

authorized account representative and 

any alternate CAIR authorized account 

representative to represent their 

ownership interest with respect to the 

CAIR SO2 allowances held in the 

general account; 

(D) The following certification 

statement by the CAIR authorized 

account representative and any alternate 

CAIR authorized account representative: 

‘‘I certify that I was selected as the CAIR 

authorized account representative or the 

alternate CAIR authorized account 

representative, as applicable, by an 

agreement that is binding on all persons 

who have an ownership interest with 

respect to CAIR SO2 allowances held in 

the general account. I certify that I have 

all the necessary authority to carry out 

my duties and responsibilities under the 

CAIR SO2 Trading Program on behalf of 

such persons and that each such person 

shall be fully bound by my 

representations, actions, inactions, or 

submissions and by any order or 

decision issued to me by the 

Administrator or a court regarding the 

general account.’’

(E) The signature of the CAIR 

authorized account representative and 

any alternate CAIR authorized account 

representative and the dates signed. 

(iii) Unless otherwise required by the 

permitting authority or the 

Administrator, documents of agreement 

referred to in the application for a 

general account shall not be submitted 

to the permitting authority or the 

Administrator. Neither the permitting 

authority nor the Administrator shall be 

under any obligation to review or 

evaluate the sufficiency of such 

documents, if submitted. 

(2) Authorization of CAIR authorized 

account representative.

(i) Upon receipt by the Administrator 

of a complete application for a general 

account under paragraph (b)(1) of this 

section: 

(A) The Administrator will establish a 

general account for the person or 

persons for whom the application is 

submitted.

(B) The CAIR authorized account 

representative and any alternate CAIR 

authorized account representative for 

the general account shall represent and, 

by his or her representations, actions, 

inactions, or submissions, legally bind 

each person who has an ownership 

interest with respect to CAIR SO2

allowances held in the general account 

in all matters pertaining to the CAIR 

SO2 Trading Program, notwithstanding 

any agreement between the CAIR 

authorized account representative or 

any alternate CAIR authorized account 

representative and such person. Any 

such person shall be bound by any order 

or decision issued to the CAIR 

authorized account representative or 

any alternate CAIR authorized account 

representative by the Administrator or a 

court regarding the general account. 

(C) Any representation, action, 

inaction, or submission by any alternate 

CAIR authorized account representative 

shall be deemed to be a representation, 

action, inaction, or submission by the 

CAIR authorized account representative. 

(ii) Each submission concerning the 

general account shall be submitted, 

signed, and certified by the CAIR 

authorized account representative or 

any alternate CAIR authorized account 

representative for the persons having an 

ownership interest with respect to CAIR 

SO2 allowances held in the general 

account. Each such submission shall 

include the following certification 

statement by the CAIR authorized 

account representative or any alternate 

CAIR authorized account representative: 

‘‘I am authorized to make this 

submission on behalf of the persons 

having an ownership interest with 

respect to the CAIR SO2 allowances held 

25372 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

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.’’

(iii) 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)(ii) of 

this section. 

(3) Changing CAIR authorized 

account representative and alternate 

CAIR authorized account 

representative; changes in persons with 

ownership interest.

(i) The CAIR authorized account 

representative for a general account may 

be changed at any time upon receipt by 

the Administrator of a superseding 

complete application for a general 

account under paragraph (b)(1) of this 

section. Notwithstanding any such 

change, all representations, actions, 

inactions, and submissions by the 

previous CAIR authorized account 

representative before the time and date 

when the Administrator receives the 

superseding application for a general 

account shall be binding on the new 

CAIR authorized account representative 

and the persons with an ownership 

interest with respect to the CAIR SO2

allowances in the general account. 

(ii) The alternate CAIR authorized 

account representative for a general 

account may be changed at any time 

upon receipt by the Administrator of a 

superseding complete application for a 

general account under paragraph (b)(1) 

of this section. Notwithstanding any 

such change, all representations, 

actions, inactions, and submissions by 

the previous alternate CAIR authorized 

account representative before the time 

and date when the Administrator 

receives the superseding application for 

a general account shall be binding on 

the new alternate CAIR authorized 

account representative and the persons 

with an ownership interest with respect 

to the CAIR SO2 allowances in the 

general account. 

(iii)(A) In the event a new person 

having an ownership interest with 

respect to CAIR SO2 allowances in the 

general account is not included in the 

list of such persons in the application 

for a general account, such new person 

shall be deemed to be subject to and 

bound by the application for a general 

account, the representation, actions, 

inactions, and submissions of the CAIR 

authorized account representative and 

any alternate CAIR authorized account 

representative of the account, and the 

decisions and orders of the 

Administrator or a court, as if the new 

person were included in such list. 

(B) Within 30 days following any 

change in the persons having an 

ownership interest with respect to CAIR 

SO2 allowances in the general account, 

including the addition of persons, the 

CAIR authorized account representative 

or any alternate CAIR authorized 

account representative shall submit a 

revision to the application for a general 

account amending the list of persons 

having an ownership interest with 

respect to the CAIR SO2 allowances in 

the general account to include the 

change. 

(4) Objections concerning CAIR 

authorized account representative.

(i) Once a complete application for a 

general account under paragraph (b)(1) 

of this section has been submitted and 

received, the Administrator will rely on 

the application unless and until a 

superseding complete application for a 

general account under paragraph (b)(1) 

of this section is received by the 

Administrator.

(ii) Except as provided in paragraph 

(b)(3)(i) or (ii) of this section, no 

objection or other communication 

submitted to the Administrator 

concerning the authorization, or any 

representation, action, inaction, or 

submission of the CAIR authorized 

account representative or any 

alternative CAIR authorized account 

representative for a general account 

shall affect any representation, action, 

inaction, or submission of the CAIR 

authorized account representative or 

any alternative CAIR authorized account 

representative or the finality of any 

decision or order by the Administrator 

under the CAIR SO2 Trading Program. 

(iii) The Administrator will not 

adjudicate any private legal dispute 

concerning the authorization or any 

representation, action, inaction, or 

submission of the CAIR authorized 

account representative or any 

alternative CAIR authorized account 

representative for a general account, 

including private legal disputes 

concerning the proceeds of CAIR SO2

allowance transfers. 

(c) Account identification. The 

Administrator will assign a unique 

identifying number to each account 

established under paragraph (a) or (b) of 

this section.

§ 96.252 Responsibilities of CAIR 

authorized account representative. 

Following the establishment of a 

CAIR SO2 Allowance Tracking System 

account, all submissions to the 

Administrator pertaining to the account, 

including, but not limited to, 

submissions concerning the deduction 

or transfer of CAIR SO2 allowances in 

the account, shall be made only by the 

CAIR authorized account representative 

for the account.

§ 96.253 Recordation of CAIR SO2

allowances. 

(a)(1) After a compliance account is 

established under § 96.251(a) or 

§ 73.31(a) or (b) of this chapter, the 

Administrator will record in the 

compliance account any CAIR SO2

allowance allocated to any CAIR SO2

unit at the source for each of the 30 

years starting the later of 2010 or the 

year in which the compliance account is 

established and any CAIR SO2

allowance allocated for each of the 30 

years starting the later of 2010 or the 

year in which the compliance account is 

established and transferred to the source 

in accordance with subpart GGG of this 

part or subpart D of part 73 of this 

chapter. 

(2) In 2011 and each year thereafter, 

after Administrator has completed all 

deductions under § 96.254(b), the 

Administrator will record in the 

compliance account any CAIR SO2

allowance allocated to any CAIR SO2

unit at the source for the new 30th year 

(i.e., the year that is 30 years after the 

calendar year for which such 

deductions are or could be made) and 

any CAIR SO2 allowance allocated for 

the new 30th year and transferred to the 

source in accordance with subpart GGG 

of this part or subpart D of part 73 of 

this chapter. 

(b)(1) After a general account is 

established under § 96.251(b) or 

§ 73.31(c) of this chapter, the 

Administrator will record in the general 

account any CAIR SO2 allowance 

allocated for each of the 30 years 

starting the later of 2010 or the year in 

which the general account is established 

and transferred to the general account in 

accordance with subpart GGG of this 

part or subpart D of part 73 of this 

chapter. 

(2) In 2011 and each year thereafter, 

after Administrator has completed all 

deductions under § 96.254(b), the 

Administrator will record in the general 

account any CAIR SO2 allowance 

allocated for the new 30th year (i.e., the 

year that is 30 years after the calendar 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25373

year for which such deductions are or 

could be made) and transferred to the 

general account in accordance with 

subpart GGG of this part or subpart D of 

part 73 of this chapter. 

(c) Serial numbers for allocated CAIR 

SO2 allowances. When recording the 

allocation of CAIR SO2 allowances 

issued by a permitting authority under 

§ 96.288, the Administrator will assign 

each such CAIR SO2 allowance a unique 

identification number that will include 

digits identifying the year of the control 

period for which the CAIR SO2

allowance is allocated.

§ 96.254 Compliance with CAIR SO2

emissions limitation. 

(a) Allowance transfer deadline. The 

CAIR SO2 allowances are available to be 

deducted for compliance with a source’s 

CAIR SO2 emissions limitation for a 

control period in a given calendar year 

only if the CAIR SO2 allowances: 

(1) Were allocated for the control 

period in the year or a prior year;

(2) Are held in the compliance 

account as of the allowance transfer 

deadline for the control period or are 

transferred into the compliance account 

by a CAIR SO2 allowance transfer 

correctly submitted for recordation 

under § 96.260 by the allowance transfer 

deadline for the control period; and 

(3) Are not necessary for deduction 

for excess emissions for a prior control 

period under paragraph (d) of this 

section or for deduction under part 77 

of this chapter. 

(b) Deductions for compliance.

Following the recordation, in 

accordance with § 96.261, of CAIR SO2

allowance transfers submitted for 

recordation in a source’s compliance 

account by the allowance transfer 

deadline for a control period, the 

Administrator will deduct from the 

compliance account CAIR SO2

allowances available under paragraph 

(a) of this section in order to determine 

whether the source meets the CAIR SO2

emissions limitation for the control 

period as follows: 

(1) For a CAIR SO2 source subject to 

an Acid Rain emissions limitation, the 

Administrator will, in the following 

order: 

(i) Deduct the amount of CAIR SO2

allowances, available under paragraph 

(a) of this section and not issued by a 

permitting authority under § 96.288, 

that is required under §§ 73.35(b) and 

(c) of this part. If there are sufficient 

CAIR SO2 allowances to complete this 

deduction, the deduction will be treated 

as satisfying the requirements of 

§§ 73.35(b) and (c) of this chapter. 

(ii) Deduct the amount of CAIR SO2

allowances, available under paragraph 

(a) of this section and not issued by a 

permitting authority under § 96.288, 

that is required under §§ 73.35(d) and 

77.5 of this part. If there are sufficient 

CAIR SO2 allowances to complete this 

deduction, the deduction will be treated 

as satisfying the requirements of 

§§ 73.35(d) and 77.5 of this chapter. 

(iii) Treating the CAIR SO2 allowances 

deducted under paragraph (b)(1)(i) of 

this section as also being deducted 

under this paragraph (b)(1)(iii), deduct 

CAIR SO2 allowances available under 

paragraph (a) of this section (including 

any issued by a permitting authority 

under § 96.288) in order to determine 

whether the source meets the CAIR SO2

emissions limitation for the control 

period, as follows: 

(A) Until the tonnage equivalent of 

the CAIR SO2 allowances deducted 

equals, or exceeds in accordance with 

paragraphs (c)(1) and (2) of this section, 

the number of tons of total sulfur 

dioxide emissions, determined in 

accordance with subpart HHH of this 

part, from all CAIR SO2 units at the 

source for the control period; or 

(B) If there are insufficient CAIR SO2

allowances to complete the deductions 

in paragraph (b)(1)(iii)(A) of this section, 

until no more CAIR SO2 allowances 

available under paragraph (a) of this 

section (including any issued by a 

permitting authority under § 96.288) 

remain in the compliance account. 

(2) For a CAIR SO2 source not subject 

to an Acid Rain emissions limitation, 

the Administrator will deduct CAIR SO2

allowances available under paragraph 

(a) of this section (including any issued 

by a permitting authority under 

§ 96.288) in order to determine whether 

the source meets the CAIR SO2

emissions limitation for the control 

period, as follows: 

(i) Until the tonnage equivalent of the 

CAIR SO2 allowances deducted equals, 

or exceeds in accordance with 

paragraphs (c)(1) and (2) of this section, 

the number of tons of total sulfur 

dioxide emissions, determined in 

accordance with subpart HHH of this 

part, from all CAIR SO2 units at the 

source for the control period; or 

(ii) If there are insufficient CAIR SO2

allowances to complete the deductions 

in paragraph (b)(2)(i) of this section, 

until no more CAIR SO2 allowances 

available under paragraph (a) of this 

section (including any issued by a 

permitting authority under § 96.288) 

remain in the compliance account. 

(c)(1) Identification of CAIR SO2

allowances by serial number. The CAIR 

authorized account representative for a 

source’s compliance account may 

request that specific CAIR SO2

allowances, identified by serial number, 

in the compliance account be deducted 

for emissions or excess emissions for a 

control period in accordance with 

paragraph (b) or (d) of this section. Such 

request shall be submitted to the 

Administrator by the allowance transfer 

deadline for the control period and 

include, in a format prescribed by the 

Administrator, the identification of the 

CAIR SO2 source and the appropriate 

serial numbers. 

(2) First-in, first-out. The 

Administrator will deduct CAIR SO2

allowances under paragraph (b) or (d) of 

this section from the source’s 

compliance account, in the absence of 

an identification or in the case of a 

partial identification of CAIR SO2

allowances by serial number under 

paragraph (c)(1) of this section, on a 

first-in, first-out (FIFO) accounting basis 

in the following order: 

(i) Any CAIR SO2 allowances that 

were allocated to the units at the source 

for a control period before 2010, in the 

order of recordation; 

(ii) Any CAIR SO2 allowances that 

were allocated to any unit for a control 

period before 2010 and transferred and 

recorded in the compliance account 

pursuant to subpart GGG of this part or 

subpart D of part 73 of this chapter, in 

the order of recordation; 

(iii) Any CAIR SO2 allowances that 

were allocated to the units at the source 

for a control period during 2010 through 

2014, in the order of recordation;

(iv) Any CAIR SO2 allowances that 

were allocated to any unit for a control 

period during 2010 through 2014 and 

transferred and recorded in the 

compliance account pursuant to subpart 

GGG of this part or subpart D of part 73 

of this chapter, in the order of 

recordation; 

(v) Any CAIR SO2 allowances that 

were allocated to the units at the source 

for a control period in 2015 or later, in 

the order of recordation; and 

(vi) Any CAIR SO2 allowances that 

were allocated to any unit for a control 

period in 2015 or later and transferred 

and recorded in the compliance account 

pursuant to subpart GGG of this part or 

subpart D of part 73 of this chapter, in 

the order of recordation. 

(d) Deductions for excess emissions.

(1) After making the deductions for 

compliance under paragraph (b) of this 

section for a control period in a calendar 

year in which the CAIR SO2 source has 

excess emissions, the Administrator will 

deduct from the source’s compliance 

account the tonnage equivalent in CAIR 

SO2 allowances, allocated for the 

control period in the immediately 

following calendar year (including any 

issued by a permitting authority under 

§ 96.288), equal to, or exceeding in 

25374 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

accordance with paragraphs (c)(1) and 

(2) of this section, 3 times the number 

of tons of the source’s excess emissions. 

(2) Any allowance deduction required 

under paragraph (d)(1) of this section 

shall not affect the liability of the 

owners and operators of the CAIR SO2

source or the CAIR SO2 units at the 

source for any fine, penalty, or 

assessment, or their obligation to 

comply with any other remedy, for the 

same violations, as ordered under the 

Clean Air Act or applicable State law. 

(e) Recordation of deductions. The 

Administrator will record in the 

appropriate compliance account all 

deductions from such an account under 

paragraph (b) or (d) of this section. 

(f) Administrator’s action on 

submissions. (1) The Administrator may 

review and conduct independent audits 

concerning any submission under the 

CAIR SO2 Trading Program and make 

appropriate adjustments of the 

information in the submissions. 

(2) The Administrator may deduct 

CAIR SO2 allowances from or transfer 

CAIR SO2 allowances to a source’s 

compliance account based on the 

information in the submissions, as 

adjusted under paragraph (f)(1) of this 

section.

§ 96.255 Banking. 

(a) CAIR SO2 allowances may be 

banked for future use or transfer in a 

compliance account or a general 

account in accordance with paragraph 

(b) of this section. 

(b) Any CAIR SO2 allowance that is 

held in a compliance account or a 

general account will remain in such 

account unless and until the CAIR SO2

allowance is deducted or transferred 

under § 96.254, § 96.256, or subpart 

GGG of this part.

§ 96.256 Account error. 

The Administrator may, at his or her 

sole discretion and on his or her own 

motion, correct any error in any CAIR 

SO2 Allowance Tracking System 

account. Within 10 business days of 

making such correction, the 

Administrator will notify the CAIR 

authorized account representative for 

the account.

§ 96.257 Closing of general accounts. 

(a) The CAIR authorized account 

representative of a general account may 

submit to the Administrator a request to 

close the account, which shall include 

a correctly submitted allowance transfer 

under § 96.260 for any CAIR SO2

allowances in the account to one or 

more other CAIR SO2 Allowance 

Tracking System accounts. 

(b) If a general account has no 

allowance transfers in or out of the 

account for a 12-month period or longer 

and does not contain any CAIR SO2

allowances, the Administrator may 

notify the CAIR authorized account 

representative for the account that the 

account will be closed following 20 

business days after the notice is sent. 

The account will be closed after the 20-

day period unless, before the end of the 

20-day period, the Administrator 

receives a correctly submitted transfer of 

CAIR SO2 allowances into the account 

under § 96.260 or a statement submitted 

by the CAIR authorized account 

representative demonstrating to the 

satisfaction of the Administrator good 

cause as to why the account should not 

be closed.

Subpart GGG—CAIR SO2 Allowance 

Transfers

§ 96.260 Submission of CAIR SO2

allowance transfers. 

(a) A CAIR authorized account 

representative seeking recordation of a 

CAIR SO2 allowance transfer shall 

submit the transfer to the Administrator. 

To be considered correctly submitted, 

the CAIR SO2 allowance transfer shall 

include the following elements, in a 

format specified by the Administrator: 

(1) The account numbers of both the 

transferor and transferee accounts; 

(2) The serial number of each CAIR 

SO2 allowance that is in the transferor 

account and is to be transferred; and 

(3) The name and signature of the 

CAIR authorized account 

representatives of the transferor and 

transferee accounts and the dates 

signed. 

(b)(1) The CAIR authorized account 

representative for the transferee account 

can meet the requirements in paragraph 

(a)(3) of this section by submitting, in a 

format prescribed by the Administrator, 

a statement signed by the CAIR 

authorized account representative and 

identifying each account into which any 

transfer of allowances, submitted on or 

after the date on which the 

Administrator receives such statement, 

is authorized. Such authorization shall 

be binding on any CAIR authorized 

account representative for such account 

and shall apply to all transfers into the 

account that are submitted on or after 

such date of receipt, unless and until 

the Administrator receives a statement 

signed by the CAIR authorized account 

representative retracting the 

authorization for the account. 

(2) The statement under paragraph 

(b)(1) of this section shall include the 

following: ‘‘By this signature I authorize 

any transfer of allowances into each 

account listed herein, except that I do 

not waive any remedies under State or 

Federal law to obtain correction of any 

erroneous transfers into such accounts. 

This authorization shall be binding on 

any CAIR authorized account 

representative for such account unless 

and until a statement signed by the 

CAIR authorized account representative 

retracting this authorization for the 

account is received by the 

Administrator.’’

§ 96.261 EPA recordation. 

(a) Within 5 business days (except as 

necessary to perform a transfer in 

perpetuity of CAIR SO2 allowances 

allocated to a CAIR SO2 unit or as 

provided in paragraph (b) of this 

section) of receiving a CAIR SO2

allowance transfer, the Administrator 

will record a CAIR SO2 allowance 

transfer by moving each CAIR SO2

allowance from the transferor account to 

the transferee account as specified by 

the request, provided that: 

(1) The transfer is correctly submitted 

under § 96.260; and 

(2) The transferor account includes 

each CAIR SO2 allowance identified by 

serial number in the transfer. 

(b) A CAIR SO2 allowance transfer 

that is submitted for recordation after 

the allowance transfer deadline for a 

control period and that includes any 

CAIR SO2 allowances allocated for any 

control period before such allowance 

transfer deadline will not be recorded 

until after the Administrator completes 

the deductions under § 96.254 for the 

control period immediately before such 

allowance transfer deadline. 

(c) Where a CAIR SO2 allowance 

transfer submitted for recordation fails 

to meet the requirements of paragraph 

(a) of this section, the Administrator 

will not record such transfer.

§ 96.262 Notification. 

(a) Notification of recordation. Within 

5 business days of recordation of a CAIR 

SO2 allowance transfer under § 96.261, 

the Administrator will notify the CAIR 

authorized account representatives of 

both the transferor and transferee 

accounts. 

(b) Notification of non-recordation.

Within 10 business days of receipt of a 

CAIR SO2 allowance transfer that fails to 

meet the requirements of § 96.261(a), the 

Administrator will notify the CAIR 

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 CAIR SO2

allowance transfer for recordation 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25375

following notification of nonrecordation.

Subpart HHH—Monitoring and 

Reporting

§ 96.270 General requirements. 

The owners and operators, and to the 

extent applicable, the CAIR designated 

representative, of a CAIR SO2 unit, shall 

comply with the monitoring, 

recordkeeping, and reporting 

requirements as provided in this subpart 

and in subparts F and G of part 75 of 

this chapter. For purposes of complying 

with such requirements, the definitions 

in § 96.202 and in § 72.2 of this chapter 

shall apply, and the terms ‘‘affected 

unit,’’ ‘‘designated representative,’’ and 

‘‘continuous emission monitoring 

system’’ (or ‘‘CEMS’’) in part 75 of this 

chapter shall be deemed to refer to the 

terms ‘‘CAIR SO2 unit,’’ ‘‘CAIR 

designated representative,’’ and 

‘‘continuous emission monitoring 

system’’ (or ‘‘CEMS’’) respectively, as 

defined in § 96.202. The owner or 

operator of a unit that is not a CAIR SO2

unit but that is monitored under 

§ 75.16(b)(2) of this chapter shall 

comply with the same monitoring, 

recordkeeping, and reporting 

requirements as a CAIR SO2 unit. 

(a) Requirements for installation, 

certification, and data accounting. The 

owner or operator of each CAIR SO2

unit shall: 

(1) Install all monitoring systems 

required under this subpart for 

monitoring SO2 mass emissions and 

individual unit heat input (including all 

systems required to monitor SO2

concentration, stack gas moisture 

content, stack gas flow rate, CO2 or O2

concentration, and fuel flow rate, as 

applicable, in accordance with §§ 75.11 

and 75.16 of this chapter);

(2) Successfully complete all 

certification tests required under 

§ 96.271 and meet all other 

requirements of this subpart and part 75 

of this chapter applicable to the 

monitoring systems under paragraph 

(a)(1) of this section; and 

(3) Record, report, and quality-assure 

the data from the monitoring systems 

under paragraph (a)(1) of this section. 

(b) Compliance deadlines. The owner 

or operator shall meet the monitoring 

system certification and other 

requirements of paragraphs (a)(1) and 

(2) of this section on or before the 

following dates. The owner or operator 

shall record, report, and quality-assure 

the data from the monitoring systems 

under paragraph (a)(1) of this section on 

and after the following dates. 

(1) For the owner or operator of a 

CAIR SO2 unit that commences 

commercial operation before July 1, 

2008, by January 1, 2009. 

(2) For the owner or operator of a 

CAIR SO2 unit that commences 

commercial operation on or after July 1, 

2008, by the later of the following dates: 

(i) January 1, 2009; or 

(ii) 90 unit operating days or 180 

calendar days, whichever occurs first, 

after the date on which the unit 

commences commercial operation. 

(3) For the owner or operator of a 

CAIR SO2 unit for which construction of 

a new stack or flue or installation of 

add-on SO2 emission controls is 

completed after the applicable deadline 

under paragraph (b)(1), (2), (4), or (5) of 

this section, by 90 unit operating days 

or 180 calendar days, whichever occurs 

first, after the date on which emissions 

first exit to the atmosphere through the 

new stack or flue or add-on SO2

emissions controls. 

(4) Notwithstanding the dates in 

paragraphs (b)(1) and (2) of this section, 

for the owner or operator of a unit for 

which a CAIR opt-in permit application 

is submitted and not withdrawn and a 

CAIR opt-in permit is not yet issued or 

denied under subpart III of this part, by 

the date specified in § 96.284(b). 

(5) Notwithstanding the dates in 

paragraphs (b)(1) and (2) of this section 

and solely for purposes of § 96.206(c)(2), 

for the owner or operator of a CAIR SO2

opt-in unit under subpart III of this part, 

by the date on which the CAIR SO2 optin unit enters the CAIR SO2 Trading 

Program as provided in § 96.284(g). 

(c) Reporting data. (1) Except as 

provided in paragraph (c)(2) of this 

section, the owner or operator of a CAIR 

SO2 unit that does not meet the 

applicable compliance date set forth in 

paragraph (b) of this section for any 

monitoring system under paragraph 

(a)(1) of this section shall, for each such 

monitoring system, determine, record, 

and report maximum potential (or, as 

appropriate, minimum potential) values 

for SO2 concentration, SO2 emission 

rate, stack gas flow rate, stack gas 

moisture content, fuel flow rate, and any 

other parameters required to determine 

SO2 mass emissions and heat input in 

accordance with § 75.31(b)(2) or (c)(3) of 

this chapter or section 2.4 of appendix 

D to part 75 of this chapter, as 

applicable. 

(2) The owner or operator of a CAIR 

SO2 unit that does not meet the 

applicable compliance date set forth in 

paragraph (b)(3) of this section for any 

monitoring system under paragraph 

(a)(1) of this section shall, for each such 

monitoring system, determine, record, 

and report substitute data using the 

applicable missing data procedures in 

subpart D of or appendix D to part 75 

of this chapter, in lieu of the maximum 

potential (or, as appropriate, minimum 

potential) values, for a parameter if the 

owner or operator demonstrates that 

there is continuity between the data 

streams for that parameter before and 

after the construction or installation 

under paragraph (b)(3) of this section. 

(d) Prohibitions. (1) No owner or 

operator of a CAIR SO2 unit shall use 

any alternative monitoring system, 

alternative reference method, or any 

other alternative to any requirement of 

this subpart without having obtained 

prior written approval in accordance 

with § 96.275. 

(2) No owner or operator of a CAIR 

SO2 unit shall operate the unit so as to 

discharge, or allow to be discharged, 

SO2 emissions to the atmosphere 

without accounting for all such 

emissions in accordance with the 

applicable provisions of this subpart 

and part 75 of this chapter. 

(3) No owner or operator of a CAIR 

SO2 unit shall disrupt the continuous 

emission monitoring system, any 

portion thereof, or any other approved 

emission monitoring method, and 

thereby avoid monitoring and recording 

SO2 mass emissions discharged into the 

atmosphere, except for periods of 

recertification or periods when 

calibration, quality assurance testing, or 

maintenance is performed in accordance 

with the applicable provisions of this 

subpart and part 75 of this chapter. 

(4) No owner or operator of a CAIR 

SO2 unit shall retire or permanently 

discontinue use of the continuous 

emission monitoring system, any 

component thereof, or any other 

approved monitoring system under this 

subpart, except under any one of the 

following circumstances: 

(i) During the period that the unit is 

covered by an exemption under § 96.205 

that is in effect; 

(ii) The owner or operator is 

monitoring emissions from the unit with 

another certified monitoring system 

approved, in accordance with the 

applicable provisions of this subpart 

and part 75 of this chapter, by the 

permitting authority for use at that unit 

that provides emission data for the same 

pollutant or parameter as the retired or 

discontinued monitoring system; or 

(iii) The CAIR designated 

representative submits notification of 

the date of certification testing of a 

replacement monitoring system for the 

retired or discontinued monitoring 

system in accordance with 

§ 96.271(d)(3)(i).

25376 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

§ 96.271 Initial certification and 

recertification procedures. 

(a) The owner or operator of a CAIR 

SO2 unit shall be exempt from the initial 

certification requirements of this section 

for a monitoring system under 

§ 96.270(a)(1) if the following conditions 

are met: 

(1) The monitoring system has been 

previously certified in accordance with 

part 75 of this chapter; and 

(2) The applicable quality-assurance 

and quality-control requirements of 

§ 75.21 of this chapter and appendix B 

and appendix D to part 75 of this 

chapter are fully met for the certified 

monitoring system described in 

paragraph (a)(1) of this section. 

(b) The recertification provisions of 

this section shall apply to a monitoring 

system under § 96.270(a)(1) exempt 

from initial certification requirements 

under paragraph (a) of this section.

(c) If the Administrator has previously 

approved a petition under 

§ § 75.16(b)(2)(ii) of this chapter for 

apportioning the SO2 mass emissions 

measured in a common stack or a 

petition under § 75.66 of this chapter for 

an alternative to a requirement in 

§ 75.11 or § 75.16 of this chapter, the 

CAIR designated representative shall 

resubmit the petition to the 

Administrator under § 96.275(a) to 

determine whether the approval applies 

under the CAIR SO2 Trading Program. 

(d) Except as provided in paragraph 

(a) of this section, the owner or operator 

of a CAIR SO2 unit shall comply with 

the following initial certification and 

recertification procedures, for a 

continuous monitoring system (i.e., a 

continuous emission monitoring system 

and an excepted monitoring system 

under appendix D to part 75 of this 

chapter) under § 96.270(a)(1). The 

owner or operator of a unit that qualifies 

to use the low mass emissions excepted 

monitoring methodology under § 75.19 

of this chapter or that qualifies to use an 

alternative monitoring system under 

subpart E of part 75 of this chapter shall 

comply with the procedures in 

paragraph (e) or (f) of this section 

respectively. 

(1) Requirements for initial 

certification. The owner or operator 

shall ensure that each continuous 

monitoring system under § 96.270(a)(1) 

(including the automated data 

acquisition and handling system) 

successfully completes all of the initial 

certification testing required under 

§ 75.20 of this chapter by the applicable 

deadline in § 96.270(b). In addition, 

whenever the owner or operator installs 

a monitoring system to meet the 

requirements of this subpart in a 

location where no such monitoring 

system was previously installed, initial 

certification in accordance with § 75.20 

of this chapter is required. 

(2) Requirements for recertification.

Whenever the owner or operator makes 

a replacement, modification, or change 

in any certified continuous emission 

monitoring system under § 96.270(a)(1) 

that may significantly affect the ability 

of the system to accurately measure or 

record SO2 mass emissions or heat input 

rate or to meet the quality-assurance and 

quality-control requirements of § 75.21 

of this chapter or appendix B to part 75 

of this chapter, the owner or operator 

shall recertify the monitoring system in 

accordance with § 75.20(b) of this 

chapter. Furthermore, whenever the 

owner or operator makes a replacement, 

modification, or change to the flue gas 

handling system or the unit’s operation 

that may significantly change the stack 

flow or concentration profile, the owner 

or operator shall recertify each 

continuous emission monitoring system 

whose accuracy is potentially affected 

by the change, in accordance with 

§ 75.20(b) of this chapter. Examples of 

changes to a continuous emission 

monitoring system that require 

recertification include: Replacement of 

the analyzer, complete replacement of 

an existing continuous emission 

monitoring system, or change in 

location or orientation of the sampling 

probe or site. Any fuel flowmeter system 

under § 96.270(a)(1) is subject to the 

recertification requirements in 

§ 75.20(g)(6) of this chapter. 

(3) Approval process for initial 

certification and recertification.

Paragraphs (d)(3)(i) through (iv) of this 

section apply to both initial certification 

and recertification of a continuous 

monitoring system under § 96.270(a)(1). 

For recertifications, replace the words 

‘‘certification’’ and ‘‘initial certification’’

with the word ‘‘recertification’’, replace 

the word ‘‘certified’’ with the word 

‘‘recertified,’’ and follow the procedures 

in §§ 75.20(b)(5) and (g)(7) of this 

chapter in lieu of the procedures in 

paragraph (d)(3)(v) of this section. 

(i) Notification of certification. The 

CAIR designated representative shall 

submit to the permitting authority, the 

appropriate EPA Regional Office, and 

the Administrator written notice of the 

dates of certification testing, in 

accordance with § 96.273. 

(ii) Certification application. The 

CAIR designated representative shall 

submit to the permitting authority a 

certification application for each 

monitoring system. A complete 

certification application shall include 

the information specified in § 75.63 of 

this chapter. 

(iii) Provisional certification date. The 

provisional certification date for a 

monitoring system shall be determined 

in accordance with § 75.20(a)(3) of this 

chapter. A provisionally certified 

monitoring system may be used under 

the CAIR SO2 Trading Program for a 

period not to exceed 120 days after 

receipt by the permitting authority of 

the complete certification application 

for the monitoring system under 

paragraph (d)(3)(ii) of this section. Data 

measured and recorded by the 

provisionally certified monitoring 

system, in accordance with the 

requirements of part 75 of this chapter, 

will be considered valid quality-assured 

data (retroactive to the date and time of 

provisional certification), provided that 

the permitting authority does not 

invalidate the provisional certification 

by issuing a notice of disapproval 

within 120 days of the date of receipt of 

the complete certification application by 

the permitting authority. 

(iv) Certification application approval 

process. The permitting authority will 

issue a written notice of approval or 

disapproval of the certification 

application to the owner or operator 

within 120 days of receipt of the 

complete certification application under 

paragraph (d)(3)(ii) of this section. In the 

event the permitting authority does not 

issue such a notice within such 120-day 

period, each monitoring system that 

meets the applicable performance 

requirements of part 75 of this chapter 

and is included in the certification 

application will be deemed certified for 

use under the CAIR SO2 Trading 

Program.

(A) Approval notice. If the 

certification application is complete and 

shows that each monitoring system 

meets the applicable performance 

requirements of part 75 of this chapter, 

then the permitting authority will issue 

a written notice of approval of the 

certification application within 120 

days of receipt. 

(B) Incomplete application notice. If 

the certification application is not 

complete, then the permitting authority 

will issue a written notice of 

incompleteness that sets a reasonable 

date by which the CAIR designated 

representative must submit the 

additional information required to 

complete the certification application. If 

the CAIR designated representative does 

not comply with the notice of 

incompleteness by the specified date, 

then the permitting authority may issue 

a notice of disapproval under paragraph 

(d)(3)(iv)(C) of this section. The 120-day 

review period shall not begin before 

receipt of a complete certification 

application. 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25377

(C) Disapproval notice. If the 

certification application shows that any 

monitoring system does not meet the 

performance requirements of part 75 of 

this chapter or if the certification 

application is incomplete and the 

requirement for disapproval under 

paragraph (d)(3)(iv)(B) of this section is 

met, then the permitting authority will 

issue a written notice of disapproval of 

the certification application. Upon 

issuance of such notice of disapproval, 

the provisional certification is 

invalidated by the permitting authority 

and the data measured and recorded by 

each uncertified monitoring system 

shall not be considered valid qualityassured data beginning with the date 

and hour of provisional certification (as 

defined under § 75.20(a)(3) of this 

chapter). The owner or operator shall 

follow the procedures for loss of 

certification in paragraph (d)(3)(v) of 

this section for each monitoring system 

that is disapproved for initial 

certification. 

(D) Audit decertification. The 

permitting authority or, for a CAIR SO2

opt-in unit or a unit for which a CAIR 

opt-in permit application is submitted 

and not withdrawn and a CAIR opt-in 

permit is not yet issued or denied under 

subpart III of this part, the 

Administrator may issue a notice of 

disapproval of the certification status of 

a monitor in accordance with 

§ 96.272(b). 

(v) Procedures for loss of certification.

If the permitting authority or the 

Administrator issues a notice of 

disapproval of a certification 

application under paragraph 

(d)(3)(iv)(C) of this section or a notice of 

disapproval of certification status under 

paragraph (d)(3)(iv)(D) of this section, 

then: 

(A) The owner or operator shall 

substitute the following values, for each 

disapproved monitoring system, for 

each hour of unit operation during the 

period of invalid data specified under 

§ 75.20(a)(4)(iii), § 75.20(g)(7), or 

§ 75.21(e) of this chapter and continuing 

until the applicable date and hour 

specified under § 75.20(a)(5)(i) or (g)(7) 

of this chapter: 

(1) For a disapproved SO2 pollutant 

concentration monitor and disapproved 

flow monitor, respectively, the 

maximum potential concentration of 

SO2 and the maximum potential flow 

rate, as defined in sections 2.1.1.1 and 

2.1.4.1 of appendix A to part 75 of this 

chapter. 

(2) For a disapproved moisture 

monitoring system and disapproved 

diluent gas monitoring system, 

respectively, the minimum potential 

moisture percentage and either the 

maximum potential CO2 concentration 

or the minimum potential O2

concentration (as applicable), as defined 

in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of 

appendix A to part 75 of this chapter. 

(3) For a disapproved fuel flowmeter 

system, the maximum potential fuel 

flow rate, as defined in section 2.4.2.1 

of appendix D to part 75 of this chapter. 

(B) The CAIR designated 

representative shall submit a 

notification of certification retest dates 

and a new certification application in 

accordance with paragraphs (d)(3)(i) and 

(ii) of this section. 

(C) The owner or operator shall repeat 

all certification tests or other 

requirements that were failed by the 

monitoring system, as indicated in the 

permitting authority’s or the 

Administrator’s notice of disapproval, 

no later than 30 unit operating days 

after the date of issuance of the notice 

of disapproval. 

(e) Initial certification and 

recertification procedures for units 

using the low mass emission excepted 

methodology under § 75.19 of this 

chapter. The owner or operator of a unit 

qualified to use the low mass emissions 

(LME) excepted methodology under 

§ 75.19 of this chapter shall meet the 

applicable certification and 

recertification requirements in 

§§ 75.19(a)(2) and 75.20(h) of this 

chapter. If the owner or operator of such 

a unit elects to certify a fuel flowmeter 

system for heat input determination, the 

owner or operator shall also meet the 

certification and recertification 

requirements in § 75.20(g) of this 

chapter. 

(f) Certification/recertification 

procedures for alternative monitoring 

systems. The CAIR designated 

representative of each unit for which the 

owner or operator intends to use an 

alternative monitoring system approved 

by the Administrator and, if applicable, 

the permitting authority under subpart E 

of part 75 of this chapter shall comply 

with the applicable notification and 

application procedures of § 75.20(f) of 

this chapter.

§ 96.272 Out of control periods. 

(a) Whenever any monitoring system 

fails to meet the quality-assurance and 

quality-control requirements or data 

validation requirements of part 75 of 

this chapter, data shall be substituted 

using the applicable missing data 

procedures in subpart D of or appendix 

D to 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 monitoring system should not have 

been certified or recertified because it 

did not meet a particular performance 

specification or other requirement under 

§ 96.271 or the applicable provisions of 

part 75 of this chapter, both at the time 

of the initial certification or 

recertification application submission 

and at the time of the audit, the 

permitting authority or, for a CAIR SO2

opt-in unit or a unit for which a CAIR 

opt-in permit application is submitted 

and not withdrawn and a CAIR opt-in 

permit is not yet issued or denied under 

subpart III of this part, the 

Administrator will issue a notice of 

disapproval of the certification status of 

such monitoring system. For the 

purposes of this paragraph, an audit 

shall be either a field audit or an audit 

of any information submitted to the 

permitting authority or the 

Administrator. By issuing the notice of 

disapproval, the permitting authority or 

the Administrator revokes prospectively 

the certification status of the monitoring 

system. The data measured and 

recorded by the monitoring system shall 

not be considered valid quality-assured 

data from the date of issuance of the 

notification of the revoked certification 

status until the date and time that the 

owner or operator completes 

subsequently approved initial 

certification or recertification tests for 

the monitoring system. The owner or 

operator shall follow the applicable 

initial certification or recertification 

procedures in § 96.271 for each 

disapproved monitoring system.

§ 96.273 Notifications. 

The CAIR designated representative 

for a CAIR SO2 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.

§ 96.274 Recordkeeping and reporting. 

(a) General provisions. The CAIR 

designated representative shall comply 

with all recordkeeping and reporting 

requirements in this section, the 

applicable recordkeeping and reporting 

requirements in subparts F and G of part 

75 of this chapter, and the requirements 

of § 96.210(e)(1). 

(b) Monitoring plans. The owner or 

operator of a CAIR SO2 unit shall 

comply with requirements of § 75.62 of 

this chapter and, for a unit for which a 

CAIR opt-in permit application is 

submitted and not withdrawn and a 

CAIR opt-in permit is not yet issued or 

denied under subpart III of this part, 

§§ 96.283 and 96.284(a). 

25378 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

(c) Certification applications. The 

CAIR designated representative shall 

submit an application to the permitting 

authority within 45 days after 

completing all initial certification or 

recertification tests required under 

§ 96.271, including the information 

required under § 75.63 of this chapter. 

(d) Quarterly reports. The CAIR 

designated representative shall submit 

quarterly reports, as follows: 

(1) The CAIR designated 

representative shall report the SO2 mass 

emissions data and heat input data for 

the CAIR SO2 unit, in an electronic 

quarterly report in a format prescribed 

by the Administrator, for each calendar 

quarter beginning with: 

(i) For a unit that commences 

commercial operation before July 1, 

2008, the calendar quarter covering 

January 1, 2009 through March 31, 2009; 

or 

(ii) For a unit that commences 

commercial operation on or after July 1, 

2008, the calendar quarter 

corresponding to the earlier of the date 

of provisional certification or the 

applicable deadline for initial 

certification under § 96.270(b), unless 

that quarter is the third or fourth quarter 

of 2008, in which case reporting shall 

commence in the quarter covering 

January 1, 2009 through March 31, 2009. 

(2) The CAIR designated 

representative shall submit each 

quarterly report to the Administrator 

within 30 days following the end of the 

calendar quarter covered by the report. 

Quarterly reports shall be submitted in 

the manner specified in § 75.64 of this 

chapter.

(3) For CAIR SO2 units that are also 

subject to an Acid Rain emissions 

limitation or the CAIR NOX Annual 

Trading Program or CAIR NOX Ozone 

Season Trading Program, quarterly 

reports shall include the applicable data 

and information required by subparts F 

through H of part 75 of this chapter as 

applicable, in addition to the SO2 mass 

emission data, heat input data, and 

other information required by this 

subpart. 

(e) Compliance certification. The 

CAIR designated representative shall 

submit to the Administrator a 

compliance certification (in a format 

prescribed by the Administrator) in 

support of each quarterly report based 

on reasonable inquiry of those persons 

with primary responsibility for ensuring 

that all of the unit’s emissions are 

correctly and fully monitored. The 

certification shall state that: 

(1) The monitoring data submitted 

were recorded in accordance with the 

applicable requirements of this subpart 

and part 75 of this chapter, including 

the quality assurance procedures and 

specifications; and 

(2) For a unit with add-on SO2

emission controls and for all hours 

where SO2 data are substituted in 

accordance with § 75.34(a)(1) of this 

chapter, the add-on emission controls 

were operating within the range of 

parameters listed in the quality 

assurance/quality control program 

under appendix B to part 75 of this 

chapter and the substitute data values 

do not systematically underestimate SO2

emissions.

§ 96.275 Petitions. 

(a) The CAIR designated 

representative of a CAIR SO2 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 in writing by the 

Administrator, in consultation with the 

permitting authority. 

(b) The CAIR designated 

representative of a CAIR SO2 unit that 

is not subject to an Acid Rain emissions 

limitation may submit a petition under 

§ 75.66 of this chapter to the permitting 

authority and the Administrator 

requesting approval to apply an 

alternative to any requirement of this 

subpart. Application of an alternative to 

any requirement of this subpart is in 

accordance with this subpart only to the 

extent that the petition is approved in 

writing by both the permitting authority 

and the Administrator.

§ 96.276 Additional requirements to 

provide heat input data. 

The owner or operator of a CAIR SO2

unit that monitors and reports SO2 mass 

emissions using a SO2 concentration 

system and a flow system shall also 

monitor and report heat input rate at the 

unit level using the procedures set forth 

in part 75 of this chapter.

Subpart III—CAIR SO2 Opt-in Units

§ 96.280 Applicability. 

A CAIR SO2 opt-in unit must be a unit 

that: 

(a) Is located in the State; 

(b) Is not a CAIR SO2 unit under 

§ 96.204 and is not covered by a retired 

unit exemption under § 96.205 that is in 

effect; 

(c) Is not covered by a retired unit 

exemption under § 72.8 of this chapter 

that is in effect and is not an opt-in 

source under part 74 of this chapter; 

(d) Has or is required or qualified to 

have a title V operating permit or other 

federally enforceable permit; and 

(e) Vents all of its emissions to a stack 

and can meet the monitoring, 

recordkeeping, and reporting 

requirements of subpart HHH of this 

part.

§ 96.281 General. 

(a) Except as otherwise provided in 

§§ 96.201 through 96.204, §§ 96.206 

through 96.208, and subparts BBB and 

CCC and subparts FFF through HHH of 

this part, a CAIR SO2 opt-in unit shall 

be treated as a CAIR SO2 unit for 

purposes of applying such sections and 

subparts of this part. 

(b) Solely for purposes of applying, as 

provided in this subpart, the 

requirements of subpart HHH of this 

part to a unit for which a CAIR opt-in 

permit application is submitted and not 

withdrawn and a CAIR opt-in permit is 

not yet issued or denied under this 

subpart, such unit shall be treated as a 

CAIR SO2 unit before issuance of a CAIR 

opt-in permit for such unit.

§ 96.282 CAIR designated representative. 

Any CAIR SO2 opt-in unit, and any 

unit for which a CAIR opt-in permit 

application is submitted and not 

withdrawn and a CAIR opt-in permit is 

not yet issued or denied under this 

subpart, located at the same source as 

one or more CAIR SO2 units shall have 

the same CAIR designated 

representative and alternate CAIR 

designated representative as such CAIR 

SO2 units.

§ 96.283 Applying for CAIR opt-in permit. 

(a) Applying for initial CAIR opt-in 

permit. The CAIR designated 

representative of a unit meeting the 

requirements for a CAIR SO2 opt-in unit 

in § 96.280 may apply for an initial 

CAIR opt-in permit at any time, except 

as provided under § 96.286(f) and (g), 

and, in order to apply, must submit the 

following: 

(1) A complete CAIR permit 

application under § 96.222; 

(2) A certification, in a format 

specified by the permitting authority, 

that the unit: 

(i) Is not a CAIR SO2 unit under 

§ 96.204 and is not covered by a retired 

unit exemption under § 96.205 that is in 

effect; 

(ii) Is not covered by a retired unit 

exemption under § 72.8 of this chapter 

that is in effect; 

(iii) Is not and, so long as the unit is 

a CAIR opt-in unit, will not become, an 

opt-in source under part 74 of this 

chapter;

(iv) Vents all of its emissions to a 

stack; and 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25379

(v) Has documented heat input for 

more than 876 hours during the 6 

months immediately preceding 

submission of the CAIR permit 

application under § 96.222; 

(3) A monitoring plan in accordance 

with subpart HHH of this part; 

(4) A complete certificate of 

representation under § 96.213 consistent 

with § 96.282, if no CAIR designated 

representative has been previously 

designated for the source that includes 

the unit; and 

(5) A statement, in a format specified 

by the permitting authority, whether the 

CAIR designated representative requests 

that the unit be allocated CAIR SO2

allowances under § 96.288(c) (subject to 

the conditions in §§ 96.284(h) and 

96.286(g)). 

(b) Duty to reapply. (1) The CAIR 

designated representative of a CAIR SO2

opt-in unit shall submit a complete 

CAIR permit application under § 96.222 

to renew the CAIR opt-in unit permit in 

accordance with the permitting 

authority’s regulations for title V 

operating permits, or permitting 

authority’s regulations for other 

federally enforceable permits if 

applicable, addressing permit renewal. 

(2) Unless the permitting authority 

issues a notification of acceptance of 

withdrawal of the CAIR opt-in unit from 

the CAIR SO2 Trading Program in 

accordance with § 96.286 or the unit 

becomes a CAIR SO2 unit under 

§ 96.204, the CAIR SO2 opt-in unit shall 

remain subject to the requirements for a 

CAIR SO2 opt-in unit, even if the CAIR 

designated representative for the CAIR 

SO2 opt-in unit fails to submit a CAIR 

permit application that is required for 

renewal of the CAIR opt-in permit under 

paragraph (b)(1) of this section.

§ 96.284 Opt-in process. 

The permitting authority will issue or 

deny a CAIR opt-in permit for a unit for 

which an initial application for a CAIR 

opt-in permit under § 96.283 is 

submitted in accordance with the 

following: 

(a) Interim review of monitoring plan.

The permitting authority and the 

Administrator will determine, on an 

interim basis, the sufficiency of the 

monitoring plan accompanying the 

initial application for a CAIR opt-in 

permit under § 96.283. A monitoring 

plan is sufficient, for purposes of 

interim review, if the plan appears to 

contain information demonstrating that 

the SO2 emissions rate and heat input of 

the unit are monitored and reported in 

accordance with subpart HHH of this 

part. A determination of sufficiency 

shall not be construed as acceptance or 

approval of the monitoring plan. 

(b) Monitoring and reporting. (1)(i) If 

the permitting authority and the 

Administrator determine that the 

monitoring plan is sufficient under 

paragraph (a) of this section, the owner 

or operator shall monitor and report the 

SO2 emissions rate and the heat input of 

the unit and all other applicable 

parameters, in accordance with subpart 

HHH of this part, starting on the date of 

certification of the appropriate 

monitoring systems under subpart HHH 

of this part and continuing until a CAIR 

opt-in permit is denied under § 96.284(f) 

or, if a CAIR opt-in permit is issued, the 

date and time when the unit is 

withdrawn from the CAIR SO2 Trading 

Program in accordance with § 96.286. 

(ii) The monitoring and reporting 

under paragraph (b)(1)(i) of this section 

shall include the entire control period 

immediately before the date on which 

the unit enters the CAIR SO2 Trading 

Program under § 96.284(g), during 

which period monitoring system 

availability must not be less than 90 

percent under subpart HHH of this part 

and the unit must be in full compliance 

with any applicable State or Federal 

emissions or emissions-related 

requirements. 

(2) To the extent the SO2 emissions 

rate and the heat input of the unit are 

monitored and reported in accordance 

with subpart HHH of this part for one 

or more control periods, in addition to 

the control period under paragraph 

(b)(1)(ii) of this section, during which 

control periods monitoring system 

availability is not less than 90 percent 

under subpart HHH of this part and the 

unit is in full compliance with any 

applicable State or Federal emissions or 

emissions-related requirements and 

which control periods begin not more 

than 3 years before the unit enters the 

CAIR SO2 Trading Program under 

§ 96.284(g), such information shall be 

used as provided in paragraphs (c) and 

(d) of this section. 

(c) Baseline heat input. The unit’s 

baseline heat rate shall equal: 

(1) If the unit’s SO2 emissions rate and 

heat input are monitored and reported 

for only one control period, in 

accordance with paragraph (b)(1) of this 

section, the unit’s total heat input (in 

mmBtu) for the control period; or 

(2) If the unit’s SO2 emissions rate and 

heat input are monitored and reported 

for more than one control period, in 

accordance with paragraphs (b)(1) and 

(2) of this section, the average of the 

amounts of the unit’s total heat input (in 

mmBtu) for the control period under 

paragraph (b)(1)(ii) of this section and 

the control periods under paragraph 

(b)(2) of this section. 

(d) Baseline SO2 emission rate. The 

unit’s baseline SO2 emission rate shall 

equal: 

(1) If the unit’s SO2 emissions rate and 

heat input are monitored and reported 

for only one control period, in 

accordance with paragraph (b)(1) of this 

section, the unit’s SO2 emissions rate (in 

lb/mmBtu) for the control period;

(2) If the unit’s SO2 emissions rate and 

heat input are monitored and reported 

for more than one control period, in 

accordance with paragraphs (b)(1) and 

(2) of this section, and the unit does not 

have add-on SO2 emission controls 

during any such control periods, the 

average of the amounts of the unit’s SO2

emissions rate (in lb/mmBtu) for the 

control period under paragraph (b)(1)(ii) 

of this section and the control periods 

under paragraph (b)(2) of this section; or 

(3) If the unit’s SO2 emissions rate and 

heat input are monitored and reported 

for more than one control period, in 

accordance with paragraphs (b)(1) and 

(2) of this section, and the unit has addon SO2 emission controls during any 

such control periods, the average of the 

amounts of the unit’s SO2 emissions rate 

(in lb/mmBtu) for such control period 

during which the unit has add-on SO2

emission controls. 

(e) Issuance of CAIR opt-in permit.

After calculating the baseline heat input 

and the baseline SO2 emissions rate for 

the unit under paragraphs (c) and (d) of 

this section and if the permitting 

authority determines that the CAIR 

designated representative shows that the 

unit meets the requirements for a CAIR 

SO2 opt-in unit in § 96.280 and meets 

the elements certified in § 96.283(a)(2), 

the permitting authority will issue a 

CAIR opt-in permit. The permitting 

authority will provide a copy of the 

CAIR opt-in permit to the 

Administrator, who will then establish 

a compliance account for the source that 

includes the CAIR SO2 opt-in unit 

unless the source already has a 

compliance account. 

(f) Issuance of denial of CAIR opt-in 

permit. Notwithstanding paragraphs (a) 

through (e) of this section, if at any time 

before issuance of a CAIR opt-in permit 

for the unit, the permitting authority 

determines that the CAIR designated 

representative fails to show that the unit 

meets the requirements for a CAIR SO2

opt-in unit in § 96.280 or meets the 

elements certified in § 96.283(a)(2), the 

permitting authority will issue a denial 

of a CAIR SO2 opt-in permit for the unit. 

(g) Date of entry into CAIR SO2

Trading Program. A unit for which an 

initial CAIR opt-in permit is issued by 

the permitting authority shall become a 

CAIR SO2 opt-in unit, and a CAIR SO2

unit, as of the later of January 1, 2010 

25380 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

or January 1 of the first control period 

during which such CAIR opt-in permit 

is issued. 

(h) Repowered CAIR SO2 opt-in unit.

(1) If CAIR designated representative 

requests, and the permitting authority 

issues a CAIR opt-in permit providing 

for, allocation to a CAIR SO2 opt-in unit 

of CAIR SO2 allowances under 

§ 96.288(c) and such unit is repowered 

after its date of entry into the CAIR SO2

Trading Program under paragraph (g) of 

this section, the repowered unit shall be 

treated as a CAIR SO2 opt-in unit 

replacing the original CAIR SO2 opt-in 

unit, as of the date of start-up of the 

repowered unit’s combustion chamber. 

(2) Notwithstanding paragraphs (c) 

and (d) of this section, as of the date of 

start-up under paragraph (h)(1) of this 

section, the repowered unit shall be 

deemed to have the same date of 

commencement of operation, date of 

commencement of commercial 

operation, baseline heat input, and 

baseline SO2 emission rate as the 

original CAIR SO2 opt-in unit, and the 

original CAIR SO2 opt-in unit shall no 

longer be treated as a CAIR opt-in unit 

or a CAIR SO2 unit.

§ 96.285 CAIR opt-in permit contents. 

(a) Each CAIR opt-in permit will 

contain: 

(1) All elements required for a 

complete CAIR permit application 

under § 96.222; 

(2) The certification in § 96.283(a)(2); 

(3) The unit’s baseline heat input 

under § 96.284(c); 

(4) The unit’s baseline SO2 emission 

rate under § 96.284(d); 

(5) A statement whether the unit is to 

be allocated CAIR SO2 allowances under 

§ 96.288(c) (subject to the conditions in 

§§ 96.284(h) and 96.286(g)); 

(6) A statement that the unit may 

withdraw from the CAIR SO2 Trading 

Program only in accordance with 

§ 96.286; and 

(7) A statement that the unit is subject 

to, and the owners and operators of the 

unit must comply with, the 

requirements of § 96.287. 

(b) Each CAIR opt-in permit is 

deemed to incorporate automatically the 

definitions of terms under § 96.202 and, 

upon recordation by the Administrator 

under subpart FFF or GGG of this part 

or this subpart, every allocation, 

transfer, or deduction of CAIR SO2

allowances to or from the compliance 

account of the source that includes a 

CAIR SO2 opt-in unit covered by the 

CAIR opt-in permit.

§ 96.286 Withdrawal from CAIR SO2

Trading Program. 

Except as provided under paragraph 

(g) of this section, a CAIR SO2 opt-in 

unit may withdraw from the CAIR SO2

Trading Program, but only if the 

permitting authority issues a 

notification to the CAIR designated 

representative of the CAIR SO2 opt-in 

unit of the acceptance of the withdrawal 

of the CAIR SO2 opt-in unit in 

accordance with paragraph (d) of this 

section. 

(a) Requesting withdrawal. In order to 

withdraw a CAIR opt-in unit from the 

CAIR SO2 Trading Program, the CAIR 

designated representative of the CAIR 

SO2 opt-in unit shall submit to the 

permitting authority a request to 

withdraw effective as of midnight of 

December 31 of a specified calendar 

year, which date must be at least 4 years 

after December 31 of the year of entry 

into the CAIR SO2 Trading Program 

under § 96.284(g). The request must be 

submitted no later than 90 days before 

the requested effective date of 

withdrawal.

(b) Conditions for withdrawal. Before 

a CAIR SO2 opt-in unit covered by a 

request under paragraph (a) of this 

section may withdraw from the CAIR 

SO2 Trading Program and the CAIR optin permit may be terminated under 

paragraph (e) of this section, the 

following conditions must be met: 

(1) For the control period ending on 

the date on which the withdrawal is to 

be effective, the source that includes the 

CAIR SO2 opt-in unit must meet the 

requirement to hold CAIR SO2

allowances under § 96.206(c) and 

cannot have any excess emissions. 

(2) After the requirement for 

withdrawal under paragraph (b)(1) of 

this section is met, the Administrator 

will deduct from the compliance 

account of the source that includes the 

CAIR SO2 opt-in unit CAIR SO2

allowances equal in number to and 

allocated for the same or a prior control 

period as any CAIR SO2 allowances 

allocated to the CAIR SO2 opt-in unit 

under § 96.188 for any control period for 

which the withdrawal is to be effective. 

If there are no remaining CAIR SO2

units at the source, the Administrator 

will close the compliance account, and 

the owners and operators of the CAIR 

SO2 opt-in unit may submit a CAIR SO2

allowance transfer for any remaining 

CAIR SO2 allowances to another CAIR 

SO2 Allowance Tracking System in 

accordance with subpart GGG of this 

part. 

(c) Notification. (1) After the 

requirements for withdrawal under 

paragraphs (a) and (b) of this section are 

met (including deduction of the full 

amount of CAIR SO2 allowances 

required), the permitting authority will 

issue a notification to the CAIR 

designated representative of the CAIR 

SO2 opt-in unit of the acceptance of the 

withdrawal of the CAIR SO2 opt-in unit 

as of midnight on December 31 of the 

calendar year for which the withdrawal 

was requested. 

(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 

CAIR designated representative of the 

CAIR SO2 opt-in unit that the CAIR SO2

opt-in unit’s request to withdraw is 

denied. Such CAIR SO2 opt-in unit shall 

continue to be a CAIR SO2 opt-in unit. 

(d) Permit amendment. After the 

permitting authority issues a 

notification under paragraph (c)(1) of 

this section that the requirements for 

withdrawal have been met, the 

permitting authority will revise the 

CAIR permit covering the CAIR SO2 optin unit to terminate the CAIR opt-in 

permit for such unit as of the effective 

date specified under paragraph (c)(1) of 

this section. The unit shall continue to 

be a CAIR SO2 opt-in unit until the 

effective date of the termination and 

shall comply with all requirements 

under the CAIR SO2 Trading Program 

concerning any control periods for 

which the unit is a CAIR SO2 opt-in 

unit, even if such requirements arise or 

must be complied with after the 

withdrawal takes effect. 

(e) Reapplication upon failure to meet 

conditions of withdrawal. If the 

permitting authority denies the CAIR 

SO2 opt-in unit’s request to withdraw, 

the CAIR designated representative may 

submit another request to withdraw in 

accordance with paragraphs (a) and (b) 

of this section. 

(f) Ability to reapply to the CAIR

SO2 Trading Program. Once a CAIR SO2

opt-in unit withdraws from the CAIR 

SO2 Trading Program and its CAIR optin permit is terminated under this 

section, the CAIR designated 

representative may not submit another 

application for a CAIR opt-in permit 

under § 96.283 for such CAIR SO2 optin unit before the date that is 4 years 

after the date on which the withdrawal 

became effective. Such new application 

for a CAIR opt-in permit will be treated 

as an initial application for a CAIR optin permit under § 96.284. 

(g) Inability to withdraw.

Notwithstanding paragraphs (a) through 

(f) of this section, a CAIR SO2 opt-in 

unit shall not be eligible to withdraw 

from the CAIR SO2 Trading Program if 

the CAIR designated representative of 

the CAIR SO2 opt-in unit requests, and 

the permitting authority issues a CAIR 

opt-in permit providing for, allocation 

to the CAIR SO2 opt-in unit of CAIR SO2

allowances under § 96.288(c).

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25381

§ 96.287 Change in regulatory status. 

(a) Notification. If a CAIR SO2 opt-in 

unit becomes a CAIR SO2 unit under 

§ 96.204, then the CAIR designated 

representative shall notify in writing the 

permitting authority and the 

Administrator of such change in the 

CAIR SO2 opt-in unit’s regulatory status, 

within 30 days of such change. 

(b) Permitting authority’s and 

Administrator’s actions. (1) If a CAIR 

SO2 opt-in unit becomes a CAIR SO2

unit under § 96.204, the permitting 

authority will revise the CAIR SO2 optin unit’s CAIR opt-in permit to meet the 

requirements of a CAIR permit under 

§ 96.223 as of the date on which the 

CAIR SO2 opt-in unit becomes a CAIR 

SO2 unit under § 96.204. 

(2)(i) The Administrator will deduct 

from the compliance account of the 

source that includes a CAIR SO2 opt-in 

unit that becomes a CAIR SO2 unit 

under § 96.204, CAIR SO2 allowances 

equal in number to and allocated for the 

same or a prior control period as: 

(A) Any CAIR SO2 allowances 

allocated to the CAIR SO2 opt-in unit 

under § 96.288 for any control period 

after the date on which the CAIR SO2

opt-in unit becomes a CAIR SO2 unit 

under § 96.204; and 

(B) If the date on which the CAIR SO2

opt-in unit becomes a CAIR SO2 unit 

under § 96.204 is not December 31, the 

CAIR SO2 allowances allocated to the 

CAIR SO2 opt-in unit under § 96.288 for 

the control period that includes the date 

on which the CAIR SO2 opt-in unit 

becomes a CAIR SO2 unit under 

§ 96.204, multiplied by the ratio of the 

number of days, in the control period, 

starting with the date on which the 

CAIR SO2 opt-in unit becomes a CAIR 

SO2 unit under § 96.204 divided by the 

total number of days in the control 

period and rounded to the nearest 

whole allowance as appropriate.

(ii) The CAIR designated 

representative shall ensure that the 

compliance account of the source that 

includes the CAIR SO2 unit that 

becomes a CAIR SO2 unit under 

§ 96.204 contains the CAIR SO2

allowances necessary for completion of 

the deduction under paragraph (b)(2)(i) 

of this section. 

(3)(i) For every control period after 

the date on which a CAIR SO2 opt-in 

unit becomes a CAIR SO2 unit under 

§ 96.204, the CAIR SO2 opt-in unit will 

be treated, solely for purposes of CAIR 

SO2 allowance allocations under 

§ 96.242, as a unit that commences 

operation on the date on which the 

CAIR SO2 opt-in unit becomes a CAIR 

SO2 unit under § 96.204 and will be 

allocated CAIR SO2 allowances under 

§ 96.242. 

(ii) Notwithstanding paragraph 

(b)(3)(i) of this section, if the date on 

which the CAIR SO2 opt-in unit 

becomes a CAIR SO2 unit under 

§ 96.204 is not January 1, the following 

number of CAIR SO2 allowances will be 

allocated to the CAIR SO2 opt-in unit (as 

a CAIR SO2 unit) under § 96.242 for the 

control period that includes the date on 

which the CAIR SO2 opt-in unit 

becomes a CAIR SO2 unit under 

§ 96.204: 

(A) The number of CAIR SO2

allowances otherwise allocated to the 

CAIR SO2 opt-in unit (as a CAIR SO2

unit) under § 96.242 for the control 

period multiplied by; 

(B) The ratio of the number of days, 

in the control period, starting with the 

date on which the CAIR SO2 opt-in unit 

becomes a CAIR SO2 unit under 

§ 96.204, divided by the total number of 

days in the control period; and 

(C) Rounded to the nearest whole 

allowance as appropriate.

§ 96.288 SO2 allowance allocations to 

CAIR SO2 opt-in units. 

(a) Timing requirements. (1) When the 

CAIR opt-in permit is issued under 

§ 96.284(e), the permitting authority will 

allocate CAIR SO2 allowances to the 

CAIR SO2 opt-in unit, and submit to the 

Administrator the allocation for the 

control period in which a CAIR SO2 optin unit enters the CAIR SO2 Trading 

Program under § 96.284(g), in 

accordance with paragraph (b) or (c) of 

this section. 

(2) By no later than October 31 of the 

control period in which a CAIR opt-in 

unit enters the CAIR SO2 Trading 

Program under § 96.284(g) and October 

31 of each year thereafter, the permitting 

authority will allocate CAIR SO2

allowances to the CAIR SO2 opt-in unit, 

and submit to the Administrator the 

allocation for the control period that 

includes such submission deadline and 

in which the unit is a CAIR SO2 opt-in 

unit, in accordance with paragraph (b) 

or (c) of this section. 

(b) Calculation of allocation. For each 

control period for which a CAIR SO2

opt-in unit is to be allocated CAIR SO2

allowances, the permitting authority 

will allocate in accordance with the 

following procedures: 

(1) The heat input (in mmBtu) used 

for calculating the CAIR SO2 allowance 

allocation will be the lesser of: 

(i) The CAIR SO2 opt-in unit’s 

baseline heat input determined under 

§ 96.284(c); or 

(ii) The CAIR SO2 opt-in unit’s heat 

input, as determined in accordance with 

subpart HHH of this part, for the 

immediately prior control period, 

except when the allocation is being 

calculated for the control period in 

which the CAIR SO2 opt-in unit enters 

the CAIR SO2 Trading Program under 

§ 96.284(g). 

(2) The SO2 emission rate (in lb/

mmBtu) used for calculating CAIR SO2

allowance allocations will be the lesser 

of: 

(i) The CAIR SO2 opt-in unit’s 

baseline SO2 emissions rate (in lb/

mmBtu) determined under § 96.284(d) 

and multiplied by 70 percent; or 

(ii) The most stringent State or 

Federal SO2 emissions limitation 

applicable to the CAIR SO2 opt-in unit 

at any time during the control period for 

which CAIR SO2 allowances are to be 

allocated. 

(3) The permitting authority will 

allocate CAIR SO2 allowances to the 

CAIR SO2 opt-in unit with a tonnage 

equivalent equal to, or less than by the 

smallest possible amount, the heat input 

under paragraph (b)(1) of this section, 

multiplied by the SO2 emission rate 

under paragraph (b)(2) of this section, 

and divided by 2,000 lb/ton. 

(c) Notwithstanding paragraph (b) of 

this section and if the CAIR designated 

representative requests, and the 

permitting authority issues a CAIR optin permit providing for, allocation to a 

CAIR SO2 opt-in unit of CAIR SO2

allowances under this paragraph 

(subject to the conditions in 

§§ 96.284(h) and 96.286(g)), the 

permitting authority will allocate to the 

CAIR SO2 opt-in unit as follows: 

(1) For each control period in 2010 

through 2014 for which the CAIR SO2

opt-in unit is to be allocated CAIR SO2

allowances, 

(i) The heat input (in mmBtu) used for 

calculating CAIR SO2 allowance 

allocations will be determined as 

described in paragraph (b)(1) of this 

section. 

(ii) The SO2 emission rate (in lb/

mmBtu) used for calculating CAIR SO2

allowance allocations will be the lesser 

of: 

(A) The CAIR SO2 opt-in unit’s 

baseline SO2 emissions rate (in lb/

mmBtu) determined under § 96.284(d); 

or 

(B) The most stringent State or 

Federal SO2 emissions limitation 

applicable to the CAIR SO2 opt-in unit 

at any time during the control period in 

which the CAIR SO2 opt-in unit enters 

the CAIR SO2 Trading Program under 

§ 96.284(g). 

(iii) The permitting authority will 

allocate CAIR SO2 allowances to the 

CAIR SO2 opt-in unit with a tonnage 

equivalent equal to, or less than by the 

smallest possible amount, the heat input 

under paragraph (c)(1)(i) of this section, 

multiplied by the SO2 emission rate 

25382 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

under paragraph (c)(1)(ii) of this section, 

and divided by 2,000 lb/ton. 

(2) For each control period in 2015 

and thereafter for which the CAIR SO2

opt-in unit is to be allocated CAIR SO2

allowances, 

(i) The heat input (in mmBtu) used for 

calculating the CAIR SO2 allowance 

allocations will be determined as 

described in paragraph (b)(1) of this 

section. 

(ii) The SO2 emission rate (in lb/

mmBtu) used for calculating the CAIR 

SO2 allowance allocation will be the 

lesser of: 

(A) The CAIR SO2 opt-in unit’s 

baseline SO2 emissions rate (in lb/

mmBtu) determined under § 96.284(d) 

multiplied by 10 percent; or 

(B) The most stringent State or 

Federal SO2 emissions limitation 

applicable to the CAIR SO2 opt-in unit 

at any time during the control period for 

which CAIR SO2 allowances are to be 

allocated. 

(iii) The permitting authority will 

allocate CAIR SO2 allowances to the 

CAIR SO2 opt-in unit with a tonnage 

equivalent equal to, or less than by the 

smallest possible amount, the heat input 

under paragraph (c)(2)(i) of this section, 

multiplied by the SO2 emission rate 

under paragraph (c)(2)(ii) of this section, 

and divided by 2,000 lb/ton.

(d) Recordation. (1) The 

Administrator will record, in the 

compliance account of the source that 

includes the CAIR SO2 opt-in unit, the 

CAIR SO2 allowances allocated by the 

permitting authority to the CAIR SO2

opt-in unit under paragraph (a)(1) of this 

section. 

(2) By December 1 of the control 

period in which a CAIR opt-in unit 

enters the CAIR SO2 Trading Program 

under § 96.284(g), and December 1 of 

each year thereafter, the Administrator 

will record, in the compliance account 

of the source that includes the CAIR SO2

opt-in unit, the CAIR SO2 allowances 

allocated by the permitting authority to 

the CAIR SO2 opt-in unit under 

paragraph (a)(2) of this section.

■ 4. Part 96 is amended by adding 

subparts AAAA through CCCC, adding 

and reserving subpart DDDD and adding 

subparts EEEE through IIII to read as 

follows:

Subpart AAAA—CAIR NOX Ozone 

Season Trading Program General 

Provisions 

Sec. 

96.301 Purpose. 

96.302 Definitions. 

96.303 Measurements, abbreviations, and 

acronyms. 

96.304 Applicability. 

96.305 Retired unit exemption. 

96.306 Standard requirements. 

96.307 Computation of time. 

96.308 Appeal procedures.

Subpart BBBB—CAIR Designated 

Representative for CAIR NOX Ozone 

Season Sources 

96.310 Authorization and responsibilities of 

CAIR designated representative. 

96.311 Alternate CAIR designated 

representative. 

96.312 Changing CAIR designated 

representative and alternate CAIR 

designated representative; changes in 

owners and operators. 

96.313 Certificate of representation. 

96.314 Objections concerning CAIR 

designated representative.

Subpart CCCC—Permits 

96.320 General CAIR NOX Ozone Season 

Trading Program permit requirements. 

96.321 Submission of CAIR permit 

applications. 

96.322 Information requirements for CAIR 

permit applications. 

96.323 CAIR permit contents and term. 

96.324 CAIR permit revisions.

Subpart DDDD—[Reserved]

Subpart EEEE—CAIR NOX Ozone 

Season Allowance Allocations 

96.340 State trading budgets. 

96.341 Timing requirements for CAIR NOX

Ozone Season allowance allocations. 

96.342 CAIR NOX Ozone Season allowance 

allocations.

Subpart FFFF—CAIR NOX Ozone 

Season Allowance Tracking System 

96.350 [Reserved] 

96.351 Establishment of accounts. 

96.352 Responsibilities of CAIR authorized 

account representative. 

96.353 Recordation of CAIR NOX Ozone 

Season allowance allocations. 

96.354 Compliance with CAIR NOX

emissions limitation. 

96.355 Banking. 

96.356 Account error. 

96.357 Closing of general accounts.

Subpart GGGG—CAIR NOX Ozone 

Season Allowance Transfers 

96.360 Submission of CAIR NOX Ozone 

Season allowance transfers. 

96.361 EPA recordation. 

96.362 Notification.

Subpart HHHH—Monitoring and 

Reporting 

96.370 General requirements. 

96.371 Initial certification and 

recertification procedures. 

96.372 Out of control periods. 

96.373 Notifications. 

96.374 Recordkeeping and reporting. 

96.375 Petitions. 

96.376 Additional requirements to provide 

heat input data.

Subpart IIII—CAIR NOX Ozone Season 

Opt-in Units 

96.380 Applicability.

96.381 General. 

96.382 CAIR designated representative. 

96.383 Applying for CAIR opt-in permit. 

96.384 Opt-in process. 

96.385 CAIR opt-in permit contents. 

96.386 Withdrawal from CAIR NOX Ozone 

Season Trading Program. 

96.387 Change in regulatory status. 

96.388 NOX allowance allocations to CAIR 

NOX Ozone Season opt-in units.

Subpart AAAA—CAIR NOX Ozone 

Season Trading Program General 

Provisions

§ 96.301 Purpose. 

This subpart and subparts BBBB 

through IIII establish the model rule 

comprising general provisions and the 

designated representative, permitting, 

allowance, monitoring, and opt-in 

provisions for the State Clean Air 

Interstate Rule (CAIR) NOX Ozone 

Season Trading Program, under section 

110 of the Clean Air Act and § 51.123 

of this chapter, as a means of mitigating 

interstate transport of ozone and 

nitrogen oxides. The owner or operator 

of a unit or a source shall comply with 

the requirements of this subpart and 

subparts BBBB through IIII as a matter 

of federal law only if the State with 

jurisdiction over the unit and the source 

incorporates by reference such subparts 

or otherwise adopts the requirements of 

such subparts in accordance with 

§ 51.123(aa)(1) or (2), of this chapter, the 

State submits to the Administrator one 

or more revisions of the State 

implementation plan that include such 

adoption, and the Administrator 

approves such revisions. If the State 

adopts the requirements of such 

subparts in accordance with 

§ 51.123(aa)(1) or (2), (bb), or (dd) of this 

chapter, then the State authorizes the 

Administrator to assist the State in 

implementing the CAIR NOX Ozone 

Season Trading Program by carrying out 

the functions set forth for the 

Administrator in such subparts.

§ 96.302 Definitions. 

The terms used in this subpart and 

subparts BBBB through IIII shall have 

the meanings set forth in this section as 

follows: 

Account number means the 

identification number given by the 

Administrator to each CAIR NOX Ozone 

Season Allowance Tracking System 

account. 

Acid Rain emissions limitation means 

a limitation on emissions of sulfur 

dioxide or nitrogen oxides under the 

Acid Rain Program. 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25383

Acid Rain Program means a multistate sulfur dioxide and nitrogen oxides 

air pollution control and emission 

reduction program established by the 

Administrator under title IV of the CAA 

and parts 72 through 78 of this chapter. 

Administrator means the 

Administrator of the United States 

Environmental Protection Agency or the 

Administrator’s duly authorized 

representative.

Allocate or allocation means, with 

regard to CAIR NOX Ozone Season 

allowances issued under subpart EEEE, 

the determination by the permitting 

authority or the Administrator of the 

amount of such CAIR NOX Ozone 

Season allowances to be initially 

credited to a CAIR NOX Ozone Season 

unit or a new unit set-aside and, with 

regard to CAIR NOX Ozone Season 

allowances issued under § 96.388 or 

§ 51.123(aa)(2)(iii)(A) of this chapter, the 

determination by the permitting 

authority of the amount of such CAIR 

NOX Ozone Season allowances to be 

initially credited to a CAIR NOX Ozone 

Season unit. 

Allowance transfer deadline means, 

for a control period, midnight of 

November 30, if it is a business day, or, 

if November 30 is not a business day, 

midnight of the first business day 

thereafter immediately following the 

control period and is the deadline by 

which a CAIR NOX Ozone Season 

allowance transfer must be submitted 

for recordation in a CAIR NOX Ozone 

Season source’s compliance account in 

order to be used to meet the source’s 

CAIR NOX Ozone Season emissions 

limitation for such control period in 

accordance with § 96.354. 

Alternate CAIR designated 

representative means, for a CAIR NOX

Ozone Season source and each CAIR 

NOX Ozone Season unit at the source, 

the natural person who is authorized by 

the owners and operators of the source 

and all such units at the source in 

accordance with subparts BBBB and IIII 

of this part, to act on behalf of the CAIR 

designated representative in matters 

pertaining to the CAIR NOX Ozone 

Season Trading Program. If the CAIR 

NOX Ozone Season source is also a 

CAIR NOX source, then this natural 

person shall be the same person as the 

alternate CAIR designated 

representative under the CAIR NOX

Annual Trading Program. If the CAIR 

NOX Ozone Season source is also a 

CAIR SO2 source, then this natural 

person shall be the same person as the 

alternate CAIR designated 

representative under the CAIR SO2

Trading Program. If the CAIR NOX

Ozone Season source is also subject to 

the Acid Rain Program, then this natural 

person shall be the same person as the 

alternate designated representative 

under the Acid Rain Program. 

Automated data acquisition and 

handling system or DAHS means that 

component of the continuous emission 

monitoring system, or other emissions 

monitoring system approved for use 

under subpart HHHH 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 

HHHH of this part. 

Boiler means an enclosed fossil- or 

other-fuel-fired combustion device used 

to produce heat and to transfer heat to 

recirculating water, steam, or other 

medium. 

Bottoming-cycle cogeneration unit

means a cogeneration unit in which the 

energy input to the unit is first used to 

produce useful thermal energy and at 

least some of the reject heat from the 

useful thermal energy application or 

process is then used for electricity 

production. 

CAIR authorized account 

representative means, with regard to a 

general account, a responsible natural 

person who is authorized, in accordance 

with subparts BBBB and IIII of this part, 

to transfer and otherwise dispose of 

CAIR NOX Ozone Season allowances 

held in the general account and, with 

regard to a compliance account, the 

CAIR designated representative of the 

source. 

CAIR designated representative

means, for a CAIR NOX Ozone Season 

source and each CAIR NOX Ozone 

Season unit at the source, the natural 

person who is authorized by the owners 

and operators of the source and all such 

units at the source, in accordance with 

subparts BBBB and IIII of this part, to 

represent and legally bind each owner 

and operator in matters pertaining to the 

CAIR NOX Ozone Season Trading 

Program. If the CAIR NOX Ozone Season 

source is also a CAIR NOX source, then 

this natural person shall be the same 

person as the CAIR designated 

representative under the CAIR NOX

Annual Trading Program. If the CAIR 

NOX Ozone Season source is also a 

CAIR SO2 source, then this natural 

person shall be the same person as the 

CAIR designated representative under 

the CAIR SO2 Trading Program. If the 

CAIR NOX Ozone Season source is also 

subject to the Acid Rain Program, then 

this natural person shall be the same 

person as the designated representative 

under the Acid Rain Program. 

CAIR NOX Annual Trading Program

means a multi-state nitrogen oxides air 

pollution control and emission 

reduction program approved and 

administered by the Administrator in 

accordance with subparts AA through II 

of this part and § 51.123 of this chapter, 

as a means of mitigating interstate 

transport of fine particulates and 

nitrogen oxides. 

CAIR NOX Ozone Season allowance

means a limited authorization issued by 

the permitting authority under subpart 

EEEE of this part, § 96.388, or 

§ 51.123(aa)(2)(iii)(A), (bb)(2)(iii) or (iv), 

or (dd)(3) or (4) of this chapter to emit 

one ton of nitrogen oxides during a 

control period of the specified calendar 

year for which the authorization is 

allocated or of any calendar year 

thereafter under the CAIR NOX Ozone 

Season Trading Program or a limited 

authorization issued by the permitting 

authority for a control period during 

2003 through 2008 under the NOX

Budget Trading Program to emit one ton 

of nitrogen oxides during a control 

period, provided that the provision in 

§ 51.121(b)(2)(i)(E) of this chapter shall 

not be used in applying this definition. 

An authorization to emit nitrogen 

oxides that is not issued under 

provisions of a State implementation 

plan that meet the requirements of 

§ 51.121(p) of this chapter or 

§ 51.123(aa)(1) or (2), (and (bb)(1)), 

(bb)(2), or (dd) of this chapter shall not 

be a CAIR NOX Ozone Season 

allowance.

CAIR NOX Ozone Season allowance 

deduction or deduct CAIR NOX Ozone 

Season allowances means the 

permanent withdrawal of CAIR NOX

Ozone Season allowances by the 

Administrator from a compliance 

account in order to account for a 

specified number of tons of total 

nitrogen oxides emissions from all CAIR 

NOX Ozone Season units at a CAIR NOX

Ozone Season source for a control 

period, determined in accordance with 

subpart HHHH of this part, or to account 

for excess emissions. 

CAIR NOX Ozone Season Allowance 

Tracking System means the system by 

which the Administrator records 

allocations, deductions, and transfers of 

CAIR NOX Ozone Season allowances 

under the CAIR NOX Ozone Season 

Trading Program. Such allowances will 

be allocated, held, deducted, or 

transferred only as whole allowances. 

CAIR NOX Ozone Season Allowance 

Tracking System account means an 

account in the CAIR NOX Ozone Season 

Allowance Tracking System established 

by the Administrator for purposes of 

recording the allocation, holding, 

25384 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

transferring, or deducting of CAIR NOX

Ozone Season allowances. 

CAIR NOX Ozone Season allowances 

held or hold CAIR NOX Ozone Season 

allowances means the CAIR NOX Ozone 

Season allowances recorded by the 

Administrator, or submitted to the 

Administrator for recordation, in 

accordance with subparts FFFF, GGGG, 

and IIII of this part, in a CAIR NOX

Ozone Season Allowance Tracking 

System account. 

CAIR NOX Ozone Season emissions 

limitation means, for a CAIR NOX

Ozone Season source, the tonnage 

equivalent of the CAIR NOX Ozone 

Season allowances available for 

deduction for the source under 

§ 96.354(a) and (b) for a control period. 

CAIR NOX Ozone Season Trading 

Program means a multi-state nitrogen 

oxides air pollution control and 

emission reduction program approved 

and administered by the Administrator 

in accordance with subparts AAAA 

through IIII of this part and § 51.123 of 

this chapter, as a means of mitigating 

interstate transport of ozone and 

nitrogen oxides. 

CAIR NOX Ozone Season source

means a source that includes one or 

more CAIR NOX Ozone Season units. 

CAIR NOX Ozone Season unit means 

a unit that is subject to the CAIR NOX

Ozone Season Trading Program under 

§ 96.304 and, except for purposes of 

§ 96.305 and subpart EEEE of this part, 

a CAIR NOX Ozone Season opt-in unit 

under subpart IIII of this part. 

CAIR NOX source means a source that 

includes one or more CAIR NOX units. 

CAIR NOX unit means a unit that is 

subject to the CAIR NOX Annual 

Trading Program under § 96.104 and a 

CAIR NOX opt-in unit under subpart II 

of this part. 

CAIR permit means the legally 

binding and federally enforceable 

written document, or portion of such 

document, issued by the permitting 

authority under subpart CCCC of this 

part, including any permit revisions, 

specifying the CAIR NOX Ozone Season 

Trading Program requirements 

applicable to a CAIR NOX Ozone Season 

source, to each CAIR NOX Ozone Season 

unit at the source, and to the owners 

and operators and the CAIR designated 

representative of the source and each 

such unit. 

CAIR SO2 source means a source that 

includes one or more CAIR SO2 units. 

CAIR SO2 Trading Program means a 

multi-state sulfur dioxide air pollution 

control and emission reduction program 

approved and administered by the 

Administrator in accordance with 

subparts AAA through III of this part 

and § 51.124 of this chapter, as a means 

of mitigating interstate transport of fine 

particulates and sulfur dioxide. 

CAIR SO2 unit means a unit that is 

subject to the CAIR SO2 Trading 

Program under § 96.204 and a CAIR SO2

opt-in unit under subpart III of this part. 

Clean Air Act or CAA means the 

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

Coal means any solid fuel classified as 

anthracite, bituminous, subbituminous, 

or lignite. 

Coal-derived fuel means any fuel 

(whether in a solid, liquid, or gaseous 

state) produced by the mechanical, 

thermal, or chemical processing of coal.

Coal-fired means: 

(1) Except for purposes of subpart 

EEEE of this part, combusting any 

amount of coal or coal-derived fuel, 

alone or in combination with any 

amount of any other fuel, during any 

year; or 

(2) For purposes of subpart EEEE of 

this part, combusting any amount of 

coal or coal-derived fuel, alone or in 

combination with any amount of any 

other fuel, during a specified year. 

Cogeneration unit means a stationary, 

fossil-fuel-fired boiler or stationary, 

fossil-fuel-fired combustion turbine: 

(1) Having equipment used to produce 

electricity and useful thermal energy for 

industrial, commercial, heating, or 

cooling purposes through the sequential 

use of energy; and 

(2) Producing during the 12-month 

period starting on the date the unit first 

produces electricity and during any 

calendar year after which the unit first 

produces electricity—

(i) For a topping-cycle cogeneration 

unit, 

(A) Useful thermal energy not less 

than 5 percent of total energy output; 

and 

(B) Useful power that, when added to 

one-half of useful thermal energy 

produced, is not less then 42.5 percent 

of total energy input, if useful thermal 

energy produced is 15 percent or more 

of total energy output, or not less than 

45 percent of total energy input, if 

useful thermal energy produced is less 

than 15 percent of total energy output. 

(ii) For a bottoming-cycle 

cogeneration unit, useful power not less 

than 45 percent of total energy input. 

Combustion turbine means: 

(1) An enclosed device comprising a 

compressor, a combustor, and a turbine 

and in which the flue gas resulting from 

the combustion of fuel in the combustor 

passes through the turbine, rotating the 

turbine; and 

(2) If the enclosed device under 

paragraph (1) of this definition is 

combined cycle, any associated heat 

recovery steam generator and steam 

turbine. 

Commence commercial operation

means, with regard to a unit serving a 

generator: 

(1) To have begun to produce steam, 

gas, or other heated medium used to 

generate electricity for sale or use, 

including test generation, except as 

provided in § 96.305. 

(i) For a unit that is a CAIR NOX

Ozone Season unit under § 96.304 on 

the date the unit commences 

commercial operation as defined in 

paragraph (1) of this definition and that 

subsequently undergoes a physical 

change (other than replacement of the 

unit by a unit at the same source), such 

date shall remain the unit’s date of 

commencement of commercial 

operation. 

(ii) For a unit that is a CAIR NOX

Ozone Season unit under § 96.304 on 

the date the unit commences 

commercial operation as defined in 

paragraph (1) of this definition and that 

is subsequently replaced by a unit at the 

same source (e.g., repowered), the 

replacement unit shall be treated as a 

separate unit with a separate date for 

commencement of commercial 

operation as defined in paragraph (1), 

(2), or (3) of this definition as 

appropriate. 

(2) Notwithstanding paragraph (1) of 

this definition and except as provided 

in § 96.305, for a unit that is not a CAIR 

NOX Ozone Season unit under § 96.304 

on the date the unit commences 

commercial operation as defined in 

paragraph (1) of this definition and is 

not a unit under paragraph (3) of this 

definition, the unit’s date for 

commencement of commercial 

operation shall be the date on which the 

unit becomes a CAIR NOX Ozone 

Season unit under § 96.304. 

(i) For a unit with a date for 

commencement of commercial 

operation as defined in paragraph (2) of 

this definition and that subsequently 

undergoes a physical change (other than 

replacement of the unit by a unit at the 

same source), such date shall remain the 

unit’s date of commencement of 

commercial operation. 

(ii) For a unit with a date for 

commencement of commercial 

operation as defined in paragraph (2) of 

this definition and that is subsequently 

replaced by a unit at the same source 

(e.g., repowered), the replacement unit 

shall be treated as a separate unit with 

a separate date for commencement of 

commercial operation as defined in 

paragraph (1), (2), or (3) of this 

definition as appropriate.

(3) Notwithstanding paragraph (1) of 

this definition and except as provided 

in § 96.384(h) or § 96.387(b)(3), for a 

CAIR NOX Ozone Season opt-in unit or 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25385

a unit for which a CAIR opt-in permit 

application is submitted and not 

withdrawn and a CAIR opt-in permit is 

not yet issued or denied under subpart 

IIII of this part, the unit’s date for 

commencement of commercial 

operation shall be the date on which the 

owner or operator is required to start 

monitoring and reporting the NOX

emissions rate and the heat input of the 

unit under § 96.384(b)(1)(i). 

(i) For a unit with a date for 

commencement of commercial 

operation as defined in paragraph (3) of 

this definition and that subsequently 

undergoes a physical change (other than 

replacement of the unit by a unit at the 

same source), such date shall remain the 

unit’s date of commencement of 

commercial operation. 

(ii) For a unit with a date for 

commencement of commercial 

operation as defined in paragraph (3) of 

this definition and that is subsequently 

replaced by a unit at the same source 

(e.g., repowered), the replacement unit 

shall be treated as a separate unit with 

a separate date for commencement of 

commercial operation as defined in 

paragraph (1), (2), or (3) of this 

definition as appropriate. 

(4) Notwithstanding paragraphs (1) 

through (3) of this definition, for a unit 

not serving a generator producing 

electricity for sale, the unit’s date of 

commencement of operation shall also 

be the unit’s date of commencement of 

commercial operation. 

Commence operation means: 

(1) To have begun any mechanical, 

chemical, or electronic process, 

including, with regard to a unit, start-up 

of a unit’s combustion chamber, except 

as provided in § 96.305. 

(i) For a unit that is a CAIR NOX

Ozone Season unit under § 96.304 on 

the date the unit commences operation 

as defined in paragraph (1) of this 

definition and that subsequently 

undergoes a physical change (other than 

replacement of the unit by a unit at the 

same source), such date shall remain the 

unit’s date of commencement of 

operation. 

(ii) For a unit that is a CAIR NOX

Ozone Season unit under § 96.304 on 

the date the unit commences operation 

as defined in paragraph (1) of this 

definition and that is subsequently 

replaced by a unit at the same source 

(e.g., repowered), the replacement unit 

shall be treated as a separate unit with 

a separate date for commencement of 

operation as defined in paragraph (1), 

(2), or (3) of this definition as 

appropriate. 

(2) Notwithstanding paragraph (1) of 

this definition and except as provided 

in § 96.305, for a unit that is not a CAIR 

NOX Ozone Season unit under § 96.304 

on the date the unit commences 

operation as defined in paragraph (1) of 

this definition and is not a unit under 

paragraph (3) of this definition, the 

unit’s date for commencement of 

operation shall be the date on which the 

unit becomes a CAIR NOX Ozone 

Season unit under § 96.304. 

(i) For a unit with a date for 

commencement of operation as defined 

in paragraph (2) of this definition and 

that subsequently undergoes a physical 

change (other than replacement of the 

unit by a unit at the same source), such 

date shall remain the unit’s date of 

commencement of operation. 

(ii) For a unit with a date for 

commencement of operation as defined 

in paragraph (2) of this definition and 

that is subsequently replaced by a unit 

at the same source (e.g., repowered), the 

replacement unit shall be treated as a 

separate unit with a separate date for 

commencement of operation as defined 

in paragraph (1),(2), or (3) of this 

definition as appropriate. 

(3) Notwithstanding paragraph (1) of 

this definition and except as provided 

in § 96.384(h) or § 96.387(b)(3), for a 

CAIR NOX Ozone Season opt-in unit or 

a unit for which a CAIR opt-in permit 

application is submitted and not 

withdrawn and a CAIR opt-in permit is 

not yet issued or denied under subpart 

IIII of this part, the unit’s date for 

commencement of operation shall be the 

date on which the owner or operator is 

required to start monitoring and 

reporting the NOX emissions rate and 

the heat input of the unit under 

§ 96.384(b)(1)(i). 

(i) For a unit with a date for 

commencement of operation as defined 

in paragraph (3) of this definition and 

that subsequently undergoes a physical 

change (other than replacement of the 

unit by a unit at the same source), such 

date shall remain the unit’s date of 

commencement of operation. 

(ii) For a unit with a date for 

commencement of operation as defined 

in paragraph (3) of this definition and 

that is subsequently replaced by a unit 

at the source (e.g., repowered), the 

replacement unit shall be treated as a 

separate unit with a separate date for 

commencement of operation as defined 

in paragraph (1), (2), or (3) of this 

definition as appropriate. 

Common stack means a single flue 

through which emissions from 2 or 

more units are exhausted. 

Compliance account means a CAIR 

NOX Ozone Season Allowance Tracking 

System account, established by the 

Administrator for a CAIR NOX Ozone 

Season source under subpart FFFF or 

IIII of this part, in which any CAIR NOX

Ozone Season allowance allocations for 

the CAIR NOX Ozone Season units at 

the source are initially recorded and in 

which are held any CAIR NOX Ozone 

Season allowances available for use for 

a control period in order to meet the 

source’s CAIR NOX Ozone Season 

emissions limitation in accordance with 

§ 96.354.

Continuous emission monitoring 

system or CEMS means the equipment 

required under subpart HHHH of this 

part to sample, analyze, measure, and 

provide, by means of readings recorded 

at least once every 15 minutes (using an 

automated data acquisition and 

handling system (DAHS)), a permanent 

record of nitrogen oxides emissions, 

stack gas volumetric flow rate, stack gas 

moisture content, and oxygen or carbon 

dioxide concentration (as applicable), in 

a manner consistent with part 75 of this 

chapter. The following systems are the 

principal types of continuous emission 

monitoring systems required under 

subpart HHHH of this part: 

(1) A flow monitoring system, 

consisting of a stack flow rate monitor 

and an automated data acquisition and 

handling system and providing a 

permanent, continuous record of stack 

gas volumetric flow rate, in standard 

cubic feet per hour (scfh); 

(2) A nitrogen oxides concentration 

monitoring system, consisting of a NOX

pollutant concentration monitor and an 

automated data acquisition and 

handling system and providing a 

permanent, continuous record of NOX

emissions, in parts per million (ppm); 

(3) A nitrogen oxides emission rate (or 

NOX-diluent) monitoring system, 

consisting of a NOX pollutant 

concentration monitor, a diluent gas 

(CO2 or O2) monitor, and an automated 

data acquisition and handling system 

and providing a permanent, continuous 

record of NOX concentration, in parts 

per million (ppm), diluent gas 

concentration, in percent CO2 or O2, and 

NOX emission rate, in pounds per 

million British thermal units (lb/

mmBtu); 

(4) A moisture monitoring system, as 

defined in § 75.11(b)(2) of this chapter 

and providing a permanent, continuous 

record of the stack gas moisture content, 

in percent H2O; 

(5) A carbon dioxide monitoring 

system, consisting of a CO2 pollutant 

concentration monitor (or an oxygen 

monitor plus suitable mathematical 

equations from which the CO2

concentration is derived) and an 

automated data acquisition and 

handling system and providing a 

permanent, continuous record of CO2

emissions, in percent CO2; and 

25386 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

(6) An oxygen monitoring system, 

consisting of an O2 concentration 

monitor and an automated data 

acquisition and handling system and 

providing a permanent, continuous 

record of O2 in percent O2. 

Control period or ozone season means 

the period beginning May 1 of a 

calendar 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 

CAIR designated representative and as 

determined by the Administrator in 

accordance with subpart HHHH of this 

part. 

Excess emissions means any ton of 

nitrogen oxides emitted by the CAIR 

NOX Ozone Season units at a CAIR NOX

Ozone Season source during a control 

period that exceeds the CAIR NOX

Ozone Season emissions limitation for 

the source. 

Fossil fuel means natural gas, 

petroleum, coal, or any form of solid, 

liquid, or gaseous fuel derived from 

such material. 

Fossil-fuel-fired means, with regard to 

a unit, combusting any amount of fossil 

fuel in any calendar year. 

Fuel oil means any petroleum-based 

fuel (including diesel fuel or petroleum 

derivatives such as oil tar) and any 

recycled or blended petroleum products 

or petroleum by-products used as a fuel 

whether in a liquid, solid, or gaseous 

state. 

General account means a CAIR NOX

Ozone Season Allowance Tracking 

System account, established under 

subpart FFFF of this part, that is not a 

compliance account. 

Generator means a device that 

produces electricity. 

Gross electrical output means, with 

regard to a cogeneration unit, electricity 

made available for use, including any 

such electricity used in the power 

production process (which process 

includes, but is not limited to, any onsite processing or treatment of fuel 

combusted at the unit and any on-site 

emission controls). 

Heat input means, with regard to a 

specified period of time, the product (in 

mmBtu/time) of the gross calorific value 

of the fuel (in Btu/lb) divided by 

1,000,000 Btu/mmBtu and multiplied by 

the fuel feed rate into a combustion 

device (in lb of fuel/time), as measured, 

recorded, and reported to the 

Administrator by the CAIR designated 

representative and determined by the 

Administrator in accordance with 

subpart HHHH of this part and 

excluding the heat derived from 

preheated combustion air, recirculated 

flue gases, or exhaust from other 

sources. 

Heat input rate means the amount of 

heat input (in mmBtu) divided by unit 

operating time (in hr) or, with regard to 

a specific fuel, the amount of heat input 

attributed to the fuel (in mmBtu) 

divided by the unit operating time (in 

hr) during which the unit combusts the 

fuel. 

Life-of-the-unit, firm power 

contractual arrangement means a unit 

participation power sales agreement 

under which a utility or industrial 

customer reserves, or is entitled to 

receive, a specified amount or 

percentage of nameplate capacity and 

associated energy generated by any 

specified unit and pays its proportional 

amount of such unit’s total costs, 

pursuant to a contract: 

(1) For the life of the unit; 

(2) For a cumulative term of no less 

than 30 years, including contracts that 

permit an election for early termination; 

or 

(3) For a period no less than 25 years 

or 70 percent of the economic useful life 

of the unit determined as of the time the 

unit is built, with option rights to 

purchase or release some portion of the 

nameplate capacity and associated 

energy generated by the unit at the end 

of the period.

Maximum design heat input means, 

starting from the initial installation of a 

unit, the maximum amount of fuel per 

hour (in Btu/hr) that a unit is capable of 

combusting on a steady state basis as 

specified by the manufacturer of the 

unit, or, starting from the completion of 

any subsequent physical change in the 

unit resulting in a decrease in the 

maximum amount of fuel per hour (in 

Btu/hr) that a unit is capable of 

combusting on a steady state basis, such 

decreased maximum amount as 

specified by the person conducting the 

physical change. 

Monitoring system means any 

monitoring system that meets the 

requirements of subpart HHHH of this 

part, including a continuous emissions 

monitoring system, an alternative 

monitoring system, or an excepted 

monitoring system under part 75 of this 

chapter. 

Most stringent State or Federal NOX

emissions limitation means, with regard 

to a unit, 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, starting 

from the initial installation of a 

generator, the maximum electrical 

generating output (in MWe) that the 

generator is capable of producing on a 

steady state basis and during continuous 

operation (when not restricted by 

seasonal or other deratings) as specified 

by the manufacturer of the generator or, 

starting from the completion of any 

subsequent physical change in the 

generator resulting in an increase in the 

maximum electrical generating output 

(in MWe) that the generator is capable 

of producing on a steady state basis and 

during continuous operation (when not 

restricted by seasonal or other 

deratings), such increased maximum 

amount as specified by the person 

conducting the physical change. 

Oil-fired means, for purposes of 

subpart EEEE of this part, combusting 

fuel oil for more than 15.0 percent of the 

annual heat input in a specified year. 

Operator means any person who 

operates, controls, or supervises a CAIR 

NOX Ozone Season unit or a CAIR NOX

Ozone Season source and shall include, 

but not be limited to, any holding 

company, utility system, or plant 

manager of such a unit or source. 

Owner means any of the following 

persons: 

(1) With regard to a CAIR NOX Ozone 

Season source or a CAIR NOX Ozone 

Season unit at a source, respectively: 

(i) Any holder of any portion of the 

legal or equitable title in a CAIR NOX

Ozone Season unit at the source or the 

CAIR NOX Ozone Season unit; 

(ii) Any holder of a leasehold interest 

in a CAIR NOX Ozone Season unit at the 

source or the CAIR NOX Ozone Season 

unit; or 

(iii) Any purchaser of power from a 

CAIR NOX Ozone Season unit at the 

source or the CAIR NOX Ozone Season 

unit under a life-of-the-unit, firm power 

contractual arrangement; provided that, 

unless expressly provided for in a 

leasehold agreement, owner shall not 

include a passive lessor, or a person 

who has an equitable interest through 

such lessor, whose rental payments are 

not based (either directly or indirectly) 

on the revenues or income from such 

CAIR NOX Ozone Season unit; or 

(2) With regard to any general 

account, any person who has an 

ownership interest with respect to the 

CAIR NOX Ozone Season allowances 

held in the general account and who is 

subject to the binding agreement for the 

CAIR authorized account representative 

to represent the person’s ownership 

interest with respect to CAIR NOX

Ozone Season allowances. 

Permitting authority means the State 

air pollution control agency, local 

agency, other State agency, or other 

agency authorized by the Administrator 

to issue or revise permits to meet the 

requirements of the CAIR NOX Ozone 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25387

Season Trading Program in accordance 

with subpart CCCC of this part or, if no 

such agency has been so authorized, the 

Administrator. 

Potential electrical output capacity

means 33 percent of a unit’s maximum 

design heat input, divided by 3,413 Btu/

kWh, divided by 1,000 kWh/MWh, and 

multiplied by 8,760 hr/yr. 

Receive or receipt of means, when 

referring to the permitting authority or 

the Administrator, to come into 

possession of a document, information, 

or correspondence (whether sent in hard 

copy or by authorized electronic 

transmission), as indicated in an official 

correspondence log, or by a notation 

made on the document, information, or 

correspondence, by the permitting 

authority or the Administrator in the 

regular course of business. 

Recordation, record, or recorded

means, with regard to CAIR NOX Ozone 

Season allowances, the movement of 

CAIR NOX Ozone Season allowances by 

the Administrator into or between CAIR 

NOX Ozone Season Allowance Tracking 

System accounts, for purposes of 

allocation, transfer, or deduction. 

Reference method means any direct 

test method of sampling and analyzing 

for an air pollutant as specified in 

§ 75.22 of this chapter. 

Repowered means, with regard to a 

unit, replacement of a coal-fired boiler 

with one of the following coal-fired 

technologies at the same source as the 

coal-fired boiler: 

(1) Atmospheric or pressurized 

fluidized bed combustion; 

(2) Integrated gasification combined 

cycle; 

(3) Magnetohydrodynamics; 

(4) Direct and indirect coal-fired 

turbines; 

(5) Integrated gasification fuel cells; or 

(6) As determined by the 

Administrator in consultation with the 

Secretary of Energy, a derivative of one 

or more of the technologies under 

paragraphs (1) through (5) of this 

definition and any other coal-fired 

technology capable of controlling 

multiple combustion emissions 

simultaneously with improved boiler or 

generation efficiency and with 

significantly greater waste reduction 

relative to the performance of 

technology in widespread commercial 

use as of January 1, 2005.

Serial number means, for a CAIR NOX

Ozone Season allowance, the unique 

identification number assigned to each 

CAIR NOX Ozone Season allowance by 

the Administrator. 

Sequential use of energy means: 

(1) For a topping-cycle cogeneration 

unit, the use of reject heat from 

electricity production in a useful 

thermal energy application or process; 

or 

(2) For a bottoming-cycle cogeneration 

unit, the use of reject heat from useful 

thermal energy application or process in 

electricity production. 

Source means all buildings, 

structures, or installations located in 

one or more contiguous or adjacent 

properties under common control of the 

same person or persons. For purposes of 

section 502(c) of the Clean Air Act, a 

‘‘source,’’ including a ‘‘source’’ with 

multiple units, shall be considered a 

single ‘‘facility.’’

State means one of the States or the 

District of Columbia that adopts the 

CAIR NOX Ozone Season Trading 

Program pursuant to § 51.123(aa)(1) or 

(2), (bb), or (dd) of this chapter. 

Submit or serve means to send or 

transmit a document, information, or 

correspondence to the person specified 

in accordance with the applicable 

regulation: 

(1) In person; 

(2) By United States Postal Service; or 

(3) By other means of dispatch or 

transmission and delivery. Compliance 

with any ‘‘submission’’ or ‘‘service’’

deadline shall be determined by the 

date of dispatch, transmission, or 

mailing and not the date of receipt. 

Title V operating permit means a 

permit issued under title V of the Clean 

Air Act and part 70 or part 71 of this 

chapter. 

Title V operating permit regulations

means the regulations that the 

Administrator has approved or issued as 

meeting the requirements of title V of 

the Clean Air Act and part 70 or 71 of 

this chapter. 

Ton means 2,000 pounds. For the 

purpose of determining compliance 

with the CAIR NOX Ozone Season 

emissions limitation, total tons of 

nitrogen oxides emissions for a control 

period shall be calculated as the sum of 

all recorded hourly emissions (or the 

mass equivalent of the recorded hourly 

emission rates) in accordance with 

subpart HHHH of this part, but with any 

remaining fraction of a ton equal to or 

greater than 0.50 tons deemed to equal 

one ton and any remaining fraction of a 

ton less than 0.50 tons deemed to equal 

zero tons. 

Topping-cycle cogeneration unit

means a cogeneration unit in which the 

energy input to the unit is first used to 

produce useful power, including 

electricity, and at least some of the 

reject heat from the electricity 

production is then used to provide 

useful thermal energy. 

Total energy input means, with regard 

to a cogeneration unit, total energy of all 

forms supplied to the cogeneration unit, 

excluding energy produced by the 

cogeneration unit itself. 

Total energy output means, with 

regard to a cogeneration unit, the sum 

of useful power and useful thermal 

energy produced by the cogeneration 

unit. 

Unit means a stationary, fossil-fuelfired boiler or combustion turbine or 

other stationary, fossil-fuel-fired 

combustion device. 

Unit operating day means a calendar 

day in which a unit combusts any fuel. 

Unit operating hour or hour of unit 

operation means an hour in which a 

unit combusts any fuel. 

Useful power means, with regard to a 

cogeneration unit, electricity or 

mechanical energy made available for 

use, excluding any such energy used in 

the power production process (which 

process includes, but is not limited to, 

any on-site processing or treatment of 

fuel combusted at the unit and any onsite emission controls). 

Useful thermal energy means, with 

regard to a cogeneration unit, thermal 

energy that is: 

(1) Made available to an industrial or 

commercial process (not a power 

production process), excluding any heat 

contained in condensate return or 

makeup water; 

(2) Used in a heat application (e.g., 

space heating or domestic hot water 

heating); or 

(3) Used in a space cooling 

application (i.e., thermal energy used by 

an absorption chiller). 

Utility power distribution system

means the portion of an electricity grid 

owned or operated by a utility and 

dedicated to delivering electricity to 

customers.

§ 96.303 Measurements, abbreviations, 

and acronyms. 

Measurements, abbreviations, and 

acronyms used in this part are defined 

as follows:

Btu—British thermal unit. 

CO2—carbon dioxide. 

1NOX—nitrogen oxides. 

hr—hour. 

kW—kilowatt electrical. 

kWh—kilowatt hour. 

mmBtu—million Btu. 

MWe—megawatt electrical. 

MWh—megawatt hour. 

O2—oxygen. 

ppm—parts per million. 

lb—pound.

scfh—standard cubic feet per hour. 

SO2—sulfur dioxide. 

H2O—water. 

yr-year.

§ 96.304 Applicability. 

The following units in a State shall be 

CAIR NOX Ozone Season units, and any 

25388 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

source that includes one or more such 

units shall be a CAIR NOX Ozone 

Season source, subject to the 

requirements of this subpart and 

subparts BBBB through HHHH of this 

part: 

(a) Except as provided in paragraph 

(b) of this section, a stationary, fossilfuel-fired boiler or stationary, fossilfuel-fired combustion turbine serving at 

any time, since the start-up of a unit’s 

combustion chamber, a generator with 

nameplate capacity of more than 25 

MWe producing electricity for sale. 

(b) For a unit that qualifies as a 

cogeneration unit during the 12-month 

period starting on the date the unit first 

produces electricity and continues to 

qualify as a cogeneration unit, a 

cogeneration unit serving at any time a 

generator with nameplate capacity of 

more than 25 MWe and supplying in 

any calendar year more than one-third 

of the unit’s potential electric output 

capacity or 219,000 MWh, whichever is 

greater, to any utility power distribution 

system for sale. If a unit qualifies as a 

cogeneration unit during the 12-month 

period starting on the date the unit first 

produces electricity but subsequently no 

longer qualifies as a cogeneration unit, 

the unit shall be subject to paragraph (a) 

of this section starting on the day on 

which the unit first no longer qualifies 

as a cogeneration unit.

§ 96.305 Retired unit exemption. 

(a)(1) Any CAIR NOX Ozone Season 

unit that is permanently retired and is 

not a CAIR NOX Ozone Season opt-in 

unit shall be exempt from the CAIR NOX

Ozone Season Trading Program, except 

for the provisions of this section, 

§ 96.302, § 96.303, § 96.304, 

§ 96.306(c)(4) through (8), § 96.307, and 

subparts EEEE through GGGG of this 

part. 

(2) The exemption under paragraph 

(a)(1) of this section shall become 

effective the day on which the CAIR 

NOX Ozone Season unit is permanently 

retired. Within 30 days of the unit’s 

permanent retirement, the CAIR 

designated representative shall submit a 

statement to the permitting authority 

otherwise responsible for administering 

any CAIR permit for the unit and shall 

submit a copy of the statement to the 

Administrator. The statement shall 

state, in a format prescribed by the 

permitting authority, that the unit was 

permanently retired on a specific date 

and will comply with the requirements 

of paragraph (b) of this section. 

(3) After receipt of the statement 

under paragraph (a)(2) of this section, 

the permitting authority will amend any 

permit under subpart CCCC of this part 

covering the source at which the unit is 

located to add the provisions and 

requirements of the exemption under 

paragraphs (a)(1) and (b) of this section. 

(b) Special provisions. (1) A unit 

exempt under paragraph (a) of this 

section shall not emit any nitrogen 

oxides, starting on the date that the 

exemption takes effect. 

(2) The permitting authority will 

allocate CAIR NOX Ozone Season 

allowances under subpart EEEE of this 

part to a unit exempt under paragraph 

(a) of this section. 

(3) For a period of 5 years from the 

date the records are created, the owners 

and operators of a unit exempt under 

paragraph (a) of 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 before the end of the 

period, in writing by the permitting 

authority or the Administrator. The 

owners and operators bear the burden of 

proof that the unit is permanently 

retired. 

(4) The owners and operators and, to 

the extent applicable, the CAIR 

designated representative of a unit 

exempt under paragraph (a) of this 

section shall comply with the 

requirements of the CAIR NOX Ozone 

Season Trading Program concerning all 

periods for which the exemption is not 

in effect, even if such requirements 

arise, or must be complied with, after 

the exemption takes effect.

(5) A unit exempt under paragraph (a) 

of this section and located at a source 

that is required, or but for this 

exemption would be required, to have a 

title V operating permit shall not resume 

operation unless the CAIR designated 

representative of the source submits a 

complete CAIR permit application 

under § 96.322 for the unit not less than 

18 months (or such lesser time provided 

by the permitting authority) before the 

later of January 1, 2009 or the date on 

which the unit resumes operation. 

(6) On the earlier of the following 

dates, a unit exempt under paragraph (a) 

of this section shall lose its exemption: 

(i) The date on which the CAIR 

designated representative submits a 

CAIR permit application for the unit 

under paragraph (b)(5) of this section; 

(ii) The date on which the CAIR 

designated representative is required 

under paragraph (b)(5) of this section to 

submit a CAIR permit application for 

the unit; or 

(iii) The date on which the unit 

resumes operation, if the CAIR 

designated representative is not 

required to submit a CAIR permit 

application for the unit. 

(7) For the purpose of applying 

monitoring, reporting, and 

recordkeeping requirements under 

subpart HHHH of this part, a unit that 

loses its exemption under paragraph (a) 

of this section shall be treated as a unit 

that commences operation and 

commercial operation on the first date 

on which the unit resumes operation.

§ 96.306 Standard requirements. 

(a) Permit requirements. (1) The CAIR 

designated representative of each CAIR 

NOX Ozone Season source required to 

have a title V operating permit and each 

CAIR NOX Ozone Season unit required 

to have a title V operating permit at the 

source shall: 

(i) Submit to the permitting authority 

a complete CAIR permit application 

under § 96.322 in accordance with the 

deadlines specified in § 96.321(a) and 

(b); and 

(ii) Submit in a timely manner any 

supplemental information that the 

permitting authority determines is 

necessary in order to review a CAIR 

permit application and issue or deny a 

CAIR permit. 

(2) The owners and operators of each 

CAIR NOX Ozone Season source 

required to have a title V operating 

permit and each CAIR NOX Ozone 

Season unit required to have a title V 

operating permit at the source shall 

have a CAIR permit issued by the 

permitting authority under subpart 

CCCC of this part for the source and 

operate the source and the unit in 

compliance with such CAIR permit. 

(3) Except as provided in subpart IIII 

of this part, the owners and operators of 

a CAIR NOX Ozone Season source that 

is not otherwise required to have a title 

V operating permit and each CAIR NOX

Ozone Season unit that is not otherwise 

required to have a title V operating 

permit are not required to submit a 

CAIR permit application, and to have a 

CAIR permit, under subpart CCCC of 

this part for such CAIR NOX Ozone 

Season source and such CAIR NOX

Ozone Season unit. 

(b) Monitoring, reporting, and 

recordkeeping requirements. (1) The 

owners and operators, and the CAIR 

designated representative, of each CAIR 

NOX Ozone Season source and each 

CAIR NOX Ozone Season unit at the 

source shall comply with the 

monitoring, reporting, and 

recordkeeping requirements of subpart 

HHHH of this part. 

(2) The emissions measurements 

recorded and reported in accordance 

with subpart HHHH of this part shall be 

used to determine compliance by each 

CAIR NOX Ozone Season source with 

the CAIR NOX Ozone Season emissions 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25389

limitation under paragraph (c) of this 

section. 

(c) Nitrogen oxides ozone season 

emission requirements. (1) As of the 

allowance transfer deadline for a control 

period, the owners and operators of 

each CAIR NOX Ozone Season source 

and each CAIR NOX Ozone Season unit 

at the source shall hold, in the source’s 

compliance account, CAIR NOX Ozone 

Season allowances available for 

compliance deductions for the control 

period under § 96.354(a) in an amount 

not less than the tons of total nitrogen 

oxides emissions for the control period 

from all CAIR NOX Ozone Season units 

at the source, as determined in 

accordance with subpart HHHH of this 

part. 

(2) A CAIR NOX Ozone Season unit 

shall be subject to the requirements 

under paragraph (c)(1) of this section 

starting on the later of May 1, 2009 or 

the deadline for meeting the unit’s 

monitor certification requirements 

under § 96.370(b)(1), (2), (3), or (7). 

(3) A CAIR NOX Ozone Season 

allowance shall not be deducted, for 

compliance with the requirements 

under paragraph (c)(1) of this section, 

for a control period in a calendar year 

before the year for which the CAIR NOX

Ozone Season allowance was allocated. 

(4) CAIR NOX Ozone Season 

allowances shall be held in, deducted 

from, or transferred into or among CAIR 

NOX Ozone Season Allowance Tracking 

System accounts in accordance with 

subpart EEEE of this part. 

(5) A CAIR NOX Ozone Season 

allowance is a limited authorization to 

emit one ton of nitrogen oxides in 

accordance with the CAIR NOX Ozone 

Season Trading Program. No provision 

of the CAIR NOX Ozone Season Trading 

Program, the CAIR permit application, 

the CAIR permit, or an exemption under 

§ 96.305 and no provision of law shall 

be construed to limit the authority of the 

State or the United States to terminate 

or limit such authorization. 

(6) A CAIR NOX Ozone Season 

allowance does not constitute a property 

right.

(7) Upon recordation by the 

Administrator under subpart FFFF, 

GGGG, or IIII of this part, every 

allocation, transfer, or deduction of a 

CAIR NOX Ozone Season allowance to 

or from a CAIR NOX Ozone Season 

unit’s compliance account is 

incorporated automatically in any CAIR 

permit of the source that includes the 

CAIR NOX Ozone Season unit. 

(d) Excess emissions requirements. (1) 

If a CAIR NOX Ozone Season source 

emits nitrogen oxides during any 

control period in excess of the CAIR 

NOX Ozone Season emissions 

limitation, then: 

(i) The owners and operators of the 

source and each CAIR NOX Ozone 

Season unit at the source shall 

surrender the CAIR NOX Ozone Season 

allowances required for deduction 

under § 96.354(d)(1) and pay any fine, 

penalty, or assessment or comply with 

any other remedy imposed, for the same 

violations, under the Clean Air Act or 

applicable State law; and 

(ii) Each ton of such excess emissions 

and each day of such control period 

shall constitute a separate violation of 

this subpart, the Clean Air Act, and 

applicable State law. 

(2) [Reserved] 

(e) Recordkeeping and reporting 

requirements. (1) Unless otherwise 

provided, the owners and operators of 

the CAIR NOX Ozone Season source and 

each CAIR NOX Ozone Season 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 

before the end of 5 years, in writing by 

the permitting authority or the 

Administrator. 

(i) The certificate of representation 

under § 96.313 for the CAIR designated 

representative for the source and each 

CAIR NOX Ozone Season unit at the 

source and all documents that 

demonstrate the truth of the statements 

in the certificate of representation; 

provided that the certificate and 

documents shall be retained on site at 

the source beyond such 5-year period 

until such documents are superseded 

because of the submission of a new 

certificate of representation under 

§ 96.313 changing the CAIR designated 

representative. 

(ii) All emissions monitoring 

information, in accordance with subpart 

HHHH of this part, provided that to the 

extent that subpart HHHH of this part 

provides for a 3-year period for 

recordkeeping, the 3-year period shall 

apply. 

(iii) Copies of all reports, compliance 

certifications, and other submissions 

and all records made or required under 

the CAIR NOX Ozone Season Trading 

Program. 

(iv) Copies of all documents used to 

complete a CAIR permit application and 

any other submission under the CAIR 

NOX Ozone Season Trading Program or 

to demonstrate compliance with the 

requirements of the CAIR NOX Ozone 

Season Trading Program. 

(2) The CAIR designated 

representative of a CAIR NOX Ozone 

Season source and each CAIR NOX

Ozone Season unit at the source shall 

submit the reports required under the 

CAIR NOX Ozone Season Trading 

Program, including those under subpart 

HHHH of this part. 

(f) Liability. (1) Each CAIR NOX Ozone 

Season source and each CAIR NOX

Ozone Season unit shall meet the 

requirements of the CAIR NOX Ozone 

Season Trading Program. 

(2) Any provision of the CAIR NOX

Ozone Season Trading Program that 

applies to a CAIR NOX Ozone Season 

source or the CAIR designated 

representative of a CAIR NOX Ozone 

Season source shall also apply to the 

owners and operators of such source 

and of the CAIR NOX Ozone Season 

units at the source. 

(3) Any provision of the CAIR NOX

Ozone Season Trading Program that 

applies to a CAIR NOX Ozone Season 

unit or the CAIR designated 

representative of a CAIR NOX Ozone 

Season unit shall also apply to the 

owners and operators of such unit. 

(g) Effect on other authorities. No 

provision of the CAIR NOX Ozone 

Season Trading Program, a CAIR permit 

application, a CAIR permit, or an 

exemption under § 96.305 shall be 

construed as exempting or excluding the 

owners and operators, and the CAIR 

designated representative, of a CAIR 

NOX Ozone Season source or CAIR NOX

Ozone Season unit from compliance 

with any other provision of the 

applicable, approved State 

implementation plan, a federally 

enforceable permit, or the Clean Air Act.

§ 96.307 Computation of time. 

(a) Unless otherwise stated, any time 

period scheduled, under the CAIR NOX

Ozone Season Trading Program, to begin 

on the occurrence of an act or event 

shall begin on the day the act or event 

occurs. 

(b) Unless otherwise stated, any time 

period scheduled, under the CAIR NOX

Ozone Season Trading Program, to begin 

before the occurrence of an act or event 

shall be computed so that the period 

ends the day before the act or event 

occurs. 

(c) Unless otherwise stated, if the final 

day of any time period, under the CAIR 

NOX Ozone Season Trading Program, 

falls on a weekend or a State or Federal 

holiday, the time period shall be 

extended to the next business day.

§ 96.308 Appeal procedures. 

The appeal procedures for decisions 

of the Administrator under the CAIR 

NOX Ozone Season Trading Program are 

set forth in part 78 of this chapter.

25390 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

Subpart BBBB—CAIR Designated 

Representative for CAIR NOX Ozone 

Season Sources

§ 96.310 Authorization and responsibilities 

of CAIR designated representative. 

(a) Except as provided under § 96.311, 

each CAIR NOX Ozone Season source, 

including all CAIR NOX Ozone Season 

units at the source, shall have one and 

only one CAIR designated 

representative, with regard to all matters 

under the CAIR NOX Ozone Season 

Trading Program concerning the source 

or any CAIR NOX Ozone Season unit at 

the source. 

(b) The CAIR designated 

representative of the CAIR NOX Ozone 

Season source shall be selected by an 

agreement binding on the owners and 

operators of the source and all CAIR 

NOX Ozone Season units at the source 

and shall act in accordance with the 

certification statement in 

§ 96.313(a)(4)(iv). 

(c) Upon receipt by the Administrator 

of a complete certificate of 

representation under § 96.313, the CAIR 

designated representative of the source 

shall represent and, by his or her 

representations, actions, inactions, or 

submissions, legally bind each owner 

and operator of the CAIR NOX Ozone 

Season source represented and each 

CAIR NOX Ozone Season unit at the 

source in all matters pertaining to the 

CAIR NOX Ozone Season Trading 

Program, notwithstanding any 

agreement between the CAIR designated 

representative and such owners and 

operators. The owners and operators 

shall be bound by any decision or order 

issued to the CAIR designated 

representative by the permitting 

authority, the Administrator, or a court 

regarding the source or unit. 

(d) No CAIR permit will be issued, no 

emissions data reports will be accepted, 

and no CAIR NOX Ozone Season 

Allowance Tracking System account 

will be established for a CAIR NOX

Ozone Season unit at a source, until the 

Administrator has received a complete 

certificate of representation under 

§ 96.313 for a CAIR designated 

representative of the source and the 

CAIR NOX Ozone Season units at the 

source. 

(e)(1) Each submission under the 

CAIR NOX Ozone Season Trading 

Program shall be submitted, signed, and 

certified by the CAIR designated 

representative for each CAIR NOX

Ozone Season source on behalf of which 

the submission is made. Each such 

submission shall include the following 

certification statement by the CAIR 

designated representative: ‘‘I am 

authorized to make this submission on 

behalf of the owners and operators of 

the source or units for which the 

submission is made. I certify under 

penalty of law that I have personally 

examined, and am familiar with, the 

statements and information submitted 

in this document and all its 

attachments. Based on my inquiry of 

those individuals with primary 

responsibility for obtaining the 

information, I certify that the statements 

and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’

(2) The permitting authority and the 

Administrator will accept or act on a 

submission made on behalf of owner or 

operators of a CAIR NOX Ozone Season 

source or a CAIR NOX Ozone Season 

unit only if the submission has been 

made, signed, and certified in 

accordance with paragraph (e)(1) of this 

section.

§ 96.311 Alternate CAIR designated 

representative. 

(a) A certificate of representation 

under § 96.313 may designate one and 

only one alternate CAIR designated 

representative, who may act on behalf of 

the CAIR designated representative. The 

agreement by which the alternate CAIR 

designated representative is selected 

shall include a procedure for 

authorizing the alternate CAIR 

designated representative to act in lieu 

of the CAIR designated representative. 

(b) Upon receipt by the Administrator 

of a complete certificate of 

representation under § 96.313, any 

representation, action, inaction, or 

submission by the alternate CAIR 

designated representative shall be 

deemed to be a representation, action, 

inaction, or submission by the CAIR 

designated representative. 

(c) Except in this section and 

§§ 96.302, 96.310(a) and (d), 96.312, 

96.313, 96.351, and 96.382 whenever 

the term ‘‘CAIR designated 

representative’’ is used in subparts 

AAAA through IIII of this part, the term 

shall be construed to include the CAIR 

designated representative or any 

alternate CAIR designated 

representative.

§ 96.312 Changing CAIR designated 

representative and alternate CAIR 

designated representative; changes in 

owners and operators.

(a) Changing CAIR designated 

representative. The CAIR designated 

representative may be changed at any 

time upon receipt by the Administrator 

of a superseding complete certificate of 

representation under § 96.313. 

Notwithstanding any such change, all 

representations, actions, inactions, and 

submissions by the previous CAIR 

designated representative before the 

time and date when the Administrator 

receives the superseding certificate of 

representation shall be binding on the 

new CAIR designated representative and 

the owners and operators of the CAIR 

NOX Ozone Season source and the CAIR 

NOX Ozone Season units at the source. 

(b) Changing alternate CAIR 

designated representative. The alternate 

CAIR designated representative may be 

changed at any time upon receipt by the 

Administrator of a superseding 

complete certificate of representation 

under § 96.313. Notwithstanding any 

such change, all representations, 

actions, inactions, and submissions by 

the previous alternate CAIR designated 

representative before the time and date 

when the Administrator receives the 

superseding certificate of representation 

shall be binding on the new alternate 

CAIR designated representative and the 

owners and operators of the CAIR NOX

Ozone Season source and the CAIR NOX

Ozone Season units at the source. 

(c) Changes in owners and operators.

(1) In the event a new owner or operator 

of a CAIR NOX Ozone Season source or 

a CAIR NOX Ozone Season unit is not 

included in the list of owners and 

operators in the certificate of 

representation under § 96.313, such new 

owner or operator shall be deemed to be 

subject to and bound by the certificate 

of representation, the representations, 

actions, inactions, and submissions of 

the CAIR designated representative and 

any alternate CAIR designated 

representative of the source or unit, and 

the decisions and orders of the 

permitting authority, the Administrator, 

or a court, as if the new owner or 

operator were included in such list. 

(2) Within 30 days following any 

change in the owners and operators of 

a CAIR NOX Ozone Season source or a 

CAIR NOX Ozone Season unit, 

including the addition of a new owner 

or operator, the CAIR designated 

representative or any alternate CAIR 

designated representative shall submit a 

revision to the certificate of 

representation under § 96.313 amending 

the list of owners and operators to 

include the change.

§ 96.313 Certificate of representation. 

(a) A complete certificate of 

representation for a CAIR designated 

representative or an alternate CAIR 

designated representative shall include 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25391

the following elements in a format 

prescribed by the Administrator: 

(1) Identification of the CAIR NOX

Ozone Season source, and each CAIR 

NOX Ozone Season unit at the source, 

for which the certificate of 

representation is submitted. 

(2) The name, address, e-mail address 

(if any), telephone number, and 

facsimile transmission number (if any) 

of the CAIR designated representative 

and any alternate CAIR designated 

representative. 

(3) A list of the owners and operators 

of the CAIR NOX Ozone Season source 

and of each CAIR NOX Ozone Season 

unit at the source. 

(4) The following certification 

statements by the CAIR designated 

representative and any alternate CAIR 

designated representative—

(i) ‘‘I certify that I was selected as the 

CAIR designated representative or 

alternate CAIR designated 

representative, as applicable, by an 

agreement binding on the owners and 

operators of the source and each CAIR 

NOX Ozone Season unit at the source.’’

(ii) ‘‘I certify that I have all the 

necessary authority to carry out my 

duties and responsibilities under the 

CAIR NOX Ozone Season Trading 

Program on behalf of the owners and 

operators of the source and of each 

CAIR NOX Ozone Season unit at the 

source and that each such owner and 

operator shall be fully bound by my 

representations, actions, inactions, or 

submissions.’’

(iii) ‘‘I certify that the owners and 

operators of the source and of each 

CAIR NOX Ozone Season unit at the 

source shall be bound by any order 

issued to me by the Administrator, the 

permitting authority, or a court 

regarding the source or unit.’’

(iv) ‘‘Where there are multiple holders 

of a legal or equitable title to, or a 

leasehold interest in, a CAIR NOX

Ozone Season unit, or where a customer 

purchases power from a CAIR NOX

Ozone Season unit under a life-of-theunit, firm power contractual 

arrangement, I certify that: I have given 

a written notice of my selection as the 

‘CAIR designated representative’ or 

‘alternate CAIR designated 

representative’, as applicable, and of the 

agreement by which I was selected to 

each owner and operator of the source 

and of each CAIR NOX Ozone Season 

unit at the source; and CAIR NOX Ozone 

Season allowances and proceeds of 

transactions involving CAIR NOX Ozone 

Season allowances will be deemed to be 

held or distributed in proportion to each 

holder’s legal, equitable, leasehold, or 

contractual reservation or entitlement, 

except that, if such multiple holders 

have expressly provided for a different 

distribution of CAIR NOX Ozone Season 

allowances by contract, CAIR NOX

Ozone Season allowances and proceeds 

of transactions involving CAIR NOX

Ozone Season allowances will be 

deemed to be held or distributed in 

accordance with the contract.’’

(5) The signature of the CAIR 

designated representative and any 

alternate CAIR designated 

representative and the dates signed.

(b) Unless otherwise required by the 

permitting authority or the 

Administrator, documents of agreement 

referred to in the certificate of 

representation shall not be submitted to 

the permitting authority or the 

Administrator. Neither the permitting 

authority nor the Administrator shall be 

under any obligation to review or 

evaluate the sufficiency of such 

documents, if submitted.

§ 96.314 Objections concerning CAIR 

designated representative. 

(a) Once a complete certificate of 

representation under § 96.313 has been 

submitted and received, the permitting 

authority and the Administrator will 

rely on the certificate of representation 

unless and until a superseding complete 

certificate of representation under 

§ 96.313 is received by the 

Administrator. 

(b) Except as provided in § 96.312(a) 

or (b), no objection or other 

communication submitted to the 

permitting authority or the 

Administrator concerning the 

authorization, or any representation, 

action, inaction, or submission, of the 

CAIR designated representative shall 

affect any representation, action, 

inaction, or submission of the CAIR 

designated representative or the finality 

of any decision or order by the 

permitting authority or the 

Administrator under the CAIR NOX

Ozone Season Trading Program. 

(c) Neither the permitting authority 

nor the Administrator will adjudicate 

any private legal dispute concerning the 

authorization or any representation, 

action, inaction, or submission of any 

CAIR designated representative, 

including private legal disputes 

concerning the proceeds of CAIR NOX

Ozone Season allowance transfers.

Subpart CCCC—Permits

§ 96.320 General CAIR NOX Ozone Season 

Trading Program permit requirements. 

(a) For each CAIR NOX Ozone Season 

source required to have a title V 

operating permit or required, under 

subpart IIII of this part, to have a title 

V operating permit or other federally 

enforceable permit, such permit shall 

include a CAIR permit administered by 

the permitting authority for the title V 

operating permit or the federally 

enforceable permit as applicable. The 

CAIR portion of the title V permit or 

other federally enforceable permit as 

applicable shall be administered in 

accordance with the permitting 

authority’s title V operating permits 

regulations promulgated under part 70 

or 71 of this chapter or the permitting 

authority’s regulations for other 

federally enforceable permits as 

applicable, except as provided 

otherwise by this subpart and subpart 

IIII of this part. 

(b) Each CAIR permit shall contain, 

with regard to the CAIR NOX Ozone 

Season source and the CAIR NOX Ozone 

Season units at the source covered by 

the CAIR permit, all applicable CAIR 

NOX Ozone Season Trading Program, 

CAIR NOX Annual Trading Program, 

and CAIR SO2 Trading Program 

requirements and shall be a complete 

and separable portion of the title V 

operating permit or other federally 

enforceable permit under paragraph (a) 

of this section.

§ 96.321 Submission of CAIR permit 

applications. 

(a) Duty to apply. The CAIR 

designated representative of any CAIR 

NOX Ozone Season source required to 

have a title V operating permit shall 

submit to the permitting authority a 

complete CAIR permit application 

under § 96.322 for the source covering 

each CAIR NOX Ozone Season unit at 

the source at least 18 months (or such 

lesser time provided by the permitting 

authority) before the later of January 1, 

2009 or the date on which the CAIR 

NOX Ozone Season unit commences 

operation. 

(b) Duty to Reapply. For a CAIR NOX

Ozone Season source required to have a 

title V operating permit, the CAIR 

designated representative shall submit a 

complete CAIR permit application 

under § 96.322 for the source covering 

each CAIR NOX Ozone Season unit at 

the source to renew the CAIR permit in 

accordance with the permitting 

authority’s title V operating permits 

regulations addressing permit renewal.

§ 96.322 Information requirements for 

CAIR permit applications. 

A complete CAIR permit application 

shall include the following elements 

concerning the CAIR NOX Ozone Season 

source for which the application is 

submitted, in a format prescribed by the 

permitting authority:

(a) Identification of the CAIR NOX

Ozone Season source; 

25392 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

(b) Identification of each CAIR NOX

Ozone Season unit at the CAIR NOX

Ozone Season source; and 

(c) The standard requirements under 

§ 96.306.

§ 96.323 CAIR permit contents and term. 

(a) Each CAIR permit will contain, in 

a format prescribed by the permitting 

authority, all elements required for a 

complete CAIR permit application 

under § 96.322. 

(b) Each CAIR permit is deemed to 

incorporate automatically the 

definitions of terms under § 96.302 and, 

upon recordation by the Administrator 

under subpart FFFF, GGGG, or IIII of 

this part, every allocation, transfer, or 

deduction of a CAIR NOX Ozone Season 

allowance to or from the compliance 

account of the CAIR NOX Ozone Season 

source covered by the permit. 

(c) The term of the CAIR permit will 

be set by the permitting authority, as 

necessary to facilitate coordination of 

the renewal of the CAIR permit with 

issuance, revision, or renewal of the 

CAIR NOX Ozone Season source’s title 

V operating permit or other federally 

enforceable permit as applicable.

§ 96.324 CAIR permit revisions. 

Except as provided in § 96.323(b), the 

permitting authority will revise the 

CAIR permit, as necessary, in 

accordance with the permitting 

authority’s title V operating permits 

regulations or the permitting authority’s 

regulations for other federally 

enforceable permits as applicable 

addressing permit revisions.

Subpart DDDD—[Reserved]

Subpart EEEE—CAIR NOX Ozone 

Season Allowance Allocations

§ 96.340 State trading budgets. 

(a) Except as provided in paragraph 

(b) of this section, the State trading 

budgets for annual allocations of CAIR 

NOX Ozone Season allowances for the 

control periods in 2009 through 2014 

and in 2015 and thereafter are 

respectively as follows:

State State trading budget 

for 2009–2014 (tons) 

State trading budget 

for 2015 and thereafter (tons) 

Alabama ........................................................................................................................................... 32,182 26,818

Arkansas .......................................................................................................................................... 11,515 9,596

Connecticut ...................................................................................................................................... 2,559 2,559

Delaware .......................................................................................................................................... 2,226 1,855

District of Columbia ......................................................................................................................... 112 94

Florida .............................................................................................................................................. 47,912 39,926

Illinois ............................................................................................................................................... 30,701 28,981

Indiana ............................................................................................................................................. 45,952 39,273

Iowa ................................................................................................................................................. 14,263 11,886

Kentucky .......................................................................................................................................... 36,045 30,587

Louisiana .......................................................................................................................................... 17,085 14,238

Maryland .......................................................................................................................................... 12,834 10,695

Massachusetts ................................................................................................................................. 7,551 6,293

Michigan ........................................................................................................................................... 28,971 24,142

Mississippi ........................................................................................................................................ 8,714 7,262

Missouri ............................................................................................................................................ 26,678 22,231

New Jersey ...................................................................................................................................... 6,654 5,545

New York ......................................................................................................................................... 20,632 17,193

North Carolina .................................................................................................................................. 28,392 23,660

Ohio ................................................................................................................................................. 45,664 39,945

Pennsylvania .................................................................................................................................... 42,171 35,143

South Carolina ................................................................................................................................. 15,249 12,707

Tennessee ....................................................................................................................................... 22,842 19,035

Virginia ............................................................................................................................................. 15,994 13,328

West Virginia .................................................................................................................................... 26,859 26,525

Wisconsin ......................................................................................................................................... 17,987 14,989

(b) If a permitting authority issues 

additional CAIR NOX Ozone Season 

allowance allocations under 

§ 51.123(aa)(2)(iii)(A) of this chapter, the 

amount in the State trading budget for 

a control period in a calendar year will 

be the sum of the amount set forth for 

the State and for the year in paragraph 

(a) of this section and the amount of 

additional CAIR NOX Ozone Season 

allowance allocations issued under 

§ 51.123(aa)(2)(iii)(A) of this chapter for 

the year.

§ 96.341 Timing requirements for CAIR 

NOX Ozone Season allowance allocations. 

(a) By October 31, 2006, the 

permitting authority will submit to the 

Administrator the CAIR NOX Ozone 

Season allowance allocations, in a 

format prescribed by the Administrator 

and in accordance with § 96.342(a) and 

(b), for the control periods in 2009, 

2010, 2011, 2012, 2013, and 2014. 

(b)(1) By October 31, 2009 and 

October 31 of each year thereafter, the 

permitting authority will submit to the 

Administrator the CAIR NOX Ozone 

Season allowance allocations, in a 

format prescribed by the Administrator 

and in accordance with § 96.342(a) and 

(b), for the control period in the sixth 

year after the year of the applicable 

deadline for submission under this 

paragraph.

(2) If the permitting authority fails to 

submit to the Administrator the CAIR 

NOX Ozone Season allowance 

allocations in accordance with 

paragraph (b)(1), the Administrator will 

assume that the allocations of CAIR 

NOX Ozone Season allowances for the 

applicable control period are the same 

as for the control period that 

immediately precedes the applicable 

control period, except that, if the 

applicable control period is in 2015, the 

Administrator will assume that the 

allocations equal 83 percent of the 

allocations for the control period that 

immediately precedes the applicable 

control period. 

(c)(1) By July 31, 2009 and July 31 of 

each year thereafter, the permitting 

authority will submit to the 

Administrator the CAIR NOX Ozone 

Season allowance allocations, in a 

format prescribed by the Administrator 

and in accordance with § 96.342(c), (a), 

and (d), for the control period in the 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25393

year of the applicable deadline for 

submission under this paragraph. 

(2) If the permitting authority fails to 

submit to the Administrator the CAIR 

NOX Ozone Season allowance 

allocations in accordance with 

paragraph (c)(1) of this section, the 

Administrator will assume that the 

allocations of CAIR NOX Ozone Season 

allowances for the applicable control 

period are the same as for the control 

period that immediately precedes the 

applicable control period, except that, if 

the applicable control period is in 2015, 

the Administrator will assume that the 

allocations equal 83 percent of the 

allocations for the control period that 

immediately precedes the applicable 

control period and except that any CAIR 

NOX Ozone Season unit that would 

otherwise be allocated CAIR NOX Ozone 

Season allowances under § 96.342(a) 

and (b), as well as under § 96.342(a), (c), 

and (d), for the applicable control 

period will be assumed to be allocated 

no CAIR NOX Ozone Season allowances 

under § 96.342(a), (c), and (d) for the 

applicable control period.

§ 96.342 CAIR NOX Ozone Season 

allowance allocations. 

(a)(1) The baseline heat input (in 

mmBtu) used with respect to CAIR NOX

Ozone Season allowance allocations 

under paragraph (b) of this section for 

each CAIR NOX Ozone Season unit will 

be: 

(i) For units commencing operation 

before January 1, 2001 the average of the 

3 highest amounts of the unit’s adjusted 

control period heat input for 2000 

through 2004, with the adjusted control 

period heat input for each year 

calculated as follows: 

(A) If the unit is coal-fired during the 

year, the unit’s control period heat input 

for such year is multiplied by 100 

percent; 

(B) If the unit is oil-fired during the 

year, the unit’s control period heat input 

for such year is multiplied by 60 

percent; and 

(C) If the unit is not subject to 

paragraph (a)(1)(i)(A) or (B) of this 

section, the unit’s control period heat 

input for such year is multiplied by 40 

percent. 

(ii) For units commencing operation 

on or after January 1, 2001 and 

operating each calendar year during a 

period of 5 or more consecutive 

calendar years, the average of the 3 

highest amounts of the unit’s total 

converted control period heat input over 

the first such 5 years. 

(2)(i) A unit’s control period heat 

input, and a unit’s status as coal-fired or 

oil-fired, for a calendar year under 

paragraph (a)(1)(i) of this section, and a 

unit’s total tons of NOX emissions 

during a calendar year under paragraph 

(c)(3) of this section, will be determined 

in accordance with part 75 of this 

chapter, to the extent the 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, to the extent the unit was not 

otherwise subject to the requirements of 

part 75 of this chapter for the year. 

(ii) A unit’s converted control period 

heat input for a calendar year specified 

under paragraph (a)(1)(ii) of this section 

equals: 

(A) Except as provided in paragraph 

(a)(2)(ii)(B) or (C) of this section, the 

control period gross electrical output of 

the generator or generators served by the 

unit multiplied by 7,900 Btu/kWh, if the 

unit is coal-fired for the year, or 6,675 

Btu/kWh, if the unit is not coal-fired for 

the year, and divided by 1,000,000 Btu/

mmBtu, provided that if a generator is 

served by 2 or more units, then the gross 

electrical output of the generator will be 

attributed to each unit in proportion to 

the unit’s share of the total control 

period heat input of such units for the 

year; 

(B) For a unit that is a boiler and has 

equipment used to produce electricity 

and useful thermal energy for industrial, 

commercial, heating, or cooling 

purposes through the sequential use of 

energy, the total heat energy (in Btu) of 

the steam produced by the boiler during 

the control period, divided by 0.8 and 

by 1,000,000 Btu/mmBtu; or 

(C) For a unit that is a combustion 

turbine and has equipment used to 

produce electricity and useful thermal 

energy for industrial, commercial, 

heating, or cooling purposes through the 

sequential use of energy, the control 

period gross electrical output of the 

enclosed device comprising the 

compressor, combustor, and turbine 

multiplied by 3,414 Btu/kWh, plus the 

total heat energy (in Btu) of the steam 

produced by any associated heat 

recovery steam generator during the 

control period divided by 0.8, and with 

the sum divided by 1,000,000 Btu/

mmBtu. 

(b)(1) For each control period in 2009 

and thereafter, the permitting authority 

will allocate to all CAIR NOX Ozone 

Season units in the State that have a 

baseline heat input (as determined 

under paragraph (a) of this section) a 

total amount of CAIR NOX Ozone 

Season allowances equal to 95 percent 

for a control period during 2009 through 

2014, and 97 percent for a control 

period during 2015 and thereafter, of the 

tons of NOX emissions in the State 

trading budget under § 96.340 (except as 

provided in paragraph (d) of this 

section).

(2) The permitting authority will 

allocate CAIR NOX Ozone Season 

allowances to each CAIR NOX Ozone 

Season unit under paragraph (b)(1) of 

this section in an amount determined by 

multiplying the total amount of CAIR 

NOX Ozone Season allowances allocated 

under paragraph (b)(1) of this section by 

the ratio of the baseline heat input of 

such CAIR NOX Ozone Season unit to 

the total amount of baseline heat input 

of all such CAIR NOX Ozone Season 

units in the State and rounding to the 

nearest whole allowance as appropriate. 

(c) For each control period in 2009 

and thereafter, the permitting authority 

will allocate CAIR NOX Ozone Season 

allowances to CAIR NOX Ozone Season 

units in the State that commenced 

operation on or after January 1, 2001 

and do not yet have a baseline heat 

input (as determined under paragraph 

(a) of this section), in accordance with 

the following procedures: 

(1) The permitting authority will 

establish a separate new unit set-aside 

for each control period. Each new unit 

set-aside will be allocated CAIR NOX

Ozone Season allowances equal to 5 

percent for a control period in 2009 

through 2013, and 3 percent for a 

control period in 2014 and thereafter, of 

the amount of tons of NOX emissions in 

the State trading budget under § 96.340. 

(2) The CAIR designated 

representative of such a CAIR NOX

Ozone Season unit may submit to the 

permitting authority a request, in a 

format specified by the permitting 

authority, to be allocated CAIR NOX

Ozone Season allowances, starting with 

the later of the control period in 2009 

or the first control period after the 

control period in which the CAIR NOX

Ozone Season unit commences 

commercial operation and until the first 

control period for which the unit is 

allocated CAIR NOX Ozone Season 

allowances under paragraph (b) of this 

section. The CAIR NOX Ozone Season 

allowance allocation request must be 

submitted on or before April 1 before 

the first control period for which the 

CAIR NOX Ozone Season allowances are 

requested and after the date on which 

the CAIR NOX Ozone Season unit 

commences commercial operation. 

(3) In a CAIR NOX Ozone Season 

allowance allocation request under 

paragraph (c)(2) of this section, the 

CAIR designated representative may 

request for a control period CAIR NOX

Ozone Season allowances in an amount 

not exceeding the CAIR NOX Ozone 

Season unit’s total tons of NOX

emissions during the control period 

immediately before such control period. 

25394 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

(4) The permitting authority will 

review each CAIR NOX Ozone Season 

allowance allocation request under 

paragraph (c)(2) of this section and will 

allocate CAIR NOX Ozone Season 

allowances for each control period 

pursuant to such request as follows: 

(i) The permitting authority will 

accept an allowance allocation request 

only if the request meets, or is adjusted 

by the permitting authority as necessary 

to meet, the requirements of paragraphs 

(c)(2) and (3) of this section. 

(ii) On or after April 1 before the 

control period, the permitting authority 

will determine the sum of the CAIR 

NOX Ozone Season allowances 

requested (as adjusted under paragraph 

(c)(4)(i) of this section) in all allowance 

allocation requests accepted under 

paragraph (c)(4)(i) of this section for the 

control period. 

(iii) If the amount of CAIR NOX Ozone 

Season allowances in the new unit setaside for the control period is greater 

than or equal to the sum under 

paragraph (c)(4)(ii) of this section, then 

the permitting authority will allocate 

the amount of CAIR NOX Ozone Season 

allowances requested (as adjusted under 

paragraph (c)(4)(i) of this section) to 

each CAIR NOX Ozone Season unit 

covered by an allowance allocation 

request accepted under paragraph 

(c)(4)(i) of this section. 

(iv) If the amount of CAIR NOX Ozone 

Season allowances in the new unit setaside for the control period is less than 

the sum under paragraph (c)(4)(ii) of 

this section, then the permitting 

authority will allocate to each CAIR 

NOX Ozone Season unit covered by an 

allowance allocation request accepted 

under paragraph (c)(4)(i) of this section 

the amount of the CAIR NOX Ozone 

Season allowances requested (as 

adjusted under paragraph (c)(4)(i) of this 

section), multiplied by the amount of 

CAIR NOX Ozone Season allowances in 

the new unit set-aside for the control 

period, divided by the sum determined 

under paragraph (c)(4)(ii) of this section, 

and rounded to the nearest whole 

allowance as appropriate. 

(v) The permitting authority will 

notify each CAIR designated 

representative that submitted an 

allowance allocation request of the 

amount of CAIR NOX Ozone Season 

allowances (if any) allocated for the 

control period to the CAIR NOX Ozone 

Season unit covered by the request. 

(d) If, after completion of the 

procedures under paragraph (c)(4) of 

this section for a control period, any 

unallocated CAIR NOX Ozone Season 

allowances remain in the new unit setaside for the control period, the 

permitting authority will allocate to 

each CAIR NOX Ozone Season unit that 

was allocated CAIR NOX Ozone Season 

allowances under paragraph (b) of this 

section an amount of CAIR NOX Ozone 

Season allowances equal to the total 

amount of such remaining unallocated 

CAIR NOX Ozone Season allowances, 

multiplied by the unit’s allocation 

under paragraph (b) of this section, 

divided by 95 percent for a control 

period during 2009 through 2014, and 

97 percent for a control period during 

2015 and thereafter, of the amount of 

tons of NOX emissions in the State 

trading budget under § 96.340, and 

rounded to the nearest whole allowance 

as appropriate.

Subpart FFFF—CAIR NOX Ozone 

Season Allowance Tracking System

§ 96.350 [Reserved]

§ 96.351 Establishment of accounts. 

(a) Compliance accounts. Except as 

provided in § 96.384(e), upon receipt of 

a complete certificate of representation 

under § 96.313, the Administrator will 

establish a compliance account for the 

CAIR NOX Ozone Season source for 

which the certificate of representation 

was submitted, unless the source 

already has a compliance account. 

(b) General accounts—(1) Application 

for general account.

(i) Any person may apply to open a 

general account for the purpose of 

holding and transferring CAIR NOX

Ozone Season allowances. An 

application for a general account may 

designate one and only one CAIR 

authorized account representative and 

one and only one alternate CAIR 

authorized account representative who 

may act on behalf of the CAIR 

authorized account representative. The 

agreement by which the alternate CAIR 

authorized account representative is 

selected shall include a procedure for 

authorizing the alternate CAIR 

authorized account representative to act 

in lieu of the CAIR authorized account 

representative. 

(ii) A complete application for a 

general account shall be submitted to 

the Administrator and shall include the 

following elements in a format 

prescribed by the Administrator: 

(A) Name, mailing address, e-mail 

address (if any), telephone number, and 

facsimile transmission number (if any) 

of the CAIR authorized account 

representative and any alternate CAIR 

authorized account representative; 

(B) Organization name and type of 

organization, if applicable; 

(C) A list of all persons subject to a 

binding agreement for the CAIR 

authorized account representative and 

any alternate CAIR authorized account 

representative to represent their 

ownership interest with respect to the 

CAIR NOX Ozone Season allowances 

held in the general account; 

(D) The following certification 

statement by the CAIR authorized 

account representative and any alternate 

CAIR authorized account representative: 

‘‘I certify that I was selected as the CAIR 

authorized account representative or the 

alternate CAIR authorized account 

representative, as applicable, by an 

agreement that is binding on all persons 

who have an ownership interest with 

respect to CAIR NOX Ozone Season 

allowances held in the general account. 

I certify that I have all the necessary 

authority to carry out my duties and 

responsibilities under the CAIR NOX

Ozone Season Trading Program on 

behalf of such persons and that each 

such person shall be fully bound by my 

representations, actions, inactions, or 

submissions and by any order or 

decision issued to me by the 

Administrator or a court regarding the 

general account.’’

(E) The signature of the CAIR 

authorized account representative and 

any alternate CAIR authorized account 

representative and the dates signed. 

(iii) Unless otherwise required by the 

permitting authority or the 

Administrator, documents of agreement 

referred to in the application for a 

general account shall not be submitted 

to the permitting authority or the 

Administrator. Neither the permitting 

authority nor the Administrator shall be 

under any obligation to review or 

evaluate the sufficiency of such 

documents, if submitted. 

(2) Authorization of CAIR authorized 

account representative.

(i) Upon receipt by the Administrator 

of a complete application for a general 

account under paragraph (b)(1) of this 

section: 

(A) The Administrator will establish a 

general account for the person or 

persons for whom the application is 

submitted. 

(B) The CAIR authorized account 

representative and any alternate CAIR 

authorized account representative for 

the general account shall represent and, 

by his or her representations, actions, 

inactions, or submissions, legally bind 

each person who has an ownership 

interest with respect to CAIR NOX

Ozone Season allowances held in the 

general account in all matters pertaining 

to the CAIR NOX Ozone Season Trading 

Program, notwithstanding any 

agreement between the CAIR authorized 

account representative or any alternate 

CAIR authorized account representative 

and such person. Any such person shall 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25395

be bound by any order or decision 

issued to the CAIR authorized account 

representative or any alternate CAIR 

authorized account representative by 

the Administrator or a court regarding 

the general account. 

(C) Any representation, action, 

inaction, or submission by any alternate 

CAIR authorized account representative 

shall be deemed to be a representation, 

action, inaction, or submission by the 

CAIR authorized account representative. 

(ii) Each submission concerning the 

general account shall be submitted, 

signed, and certified by the CAIR 

authorized account representative or 

any alternate CAIR authorized account 

representative for the persons having an 

ownership interest with respect to CAIR 

NOX Ozone Season allowances held in 

the general account. Each such 

submission shall include the following 

certification statement by the CAIR 

authorized account representative or 

any alternate CAIR authorized account 

representative: ‘‘I am authorized to 

make this submission on behalf of the 

persons having an ownership interest 

with respect to the CAIR NOX Ozone 

Season 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.’’

(iii) 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)(ii) of 

this section. 

(3) Changing CAIR authorized 

account representative and alternate 

CAIR authorized account 

representative; changes in persons with 

ownership interest.

(i) The CAIR authorized account 

representative for a general account may 

be changed at any time upon receipt by 

the Administrator of a superseding 

complete application for a general 

account under paragraph (b)(1) of this 

section. Notwithstanding any such 

change, all representations, actions, 

inactions, and submissions by the 

previous CAIR authorized account 

representative before the time and date 

when the Administrator receives the 

superseding application for a general 

account shall be binding on the new 

CAIR authorized account representative 

and the persons with an ownership 

interest with respect to the CAIR NOX

Ozone Season allowances in the general 

account.

(ii) The alternate CAIR authorized 

account representative for a general 

account may be changed at any time 

upon receipt by the Administrator of a 

superseding complete application for a 

general account under paragraph (b)(1) 

of this section. Notwithstanding any 

such change, all representations, 

actions, inactions, and submissions by 

the previous alternate CAIR authorized 

account representative before the time 

and date when the Administrator 

receives the superseding application for 

a general account shall be binding on 

the new alternate CAIR authorized 

account representative and the persons 

with an ownership interest with respect 

to the CAIR NOX Ozone Season 

allowances in the general account. 

(iii)(A) In the event a new person 

having an ownership interest with 

respect to CAIR NOX Ozone Season 

allowances in the general account is not 

included in the list of such persons in 

the application for a general account, 

such new person shall be deemed to be 

subject to and bound by the application 

for a general account, the 

representation, actions, inactions, and 

submissions of the CAIR authorized 

account representative and any alternate 

CAIR authorized account representative 

of the account, and the decisions and 

orders of the Administrator or a court, 

as if the new person were included in 

such list. 

(B) Within 30 days following any 

change in the persons having an 

ownership interest with respect to CAIR 

NOX Ozone Season allowances in the 

general account, including the addition 

of persons, the CAIR authorized account 

representative or any alternate CAIR 

authorized account representative shall 

submit a revision to the application for 

a general account amending the list of 

persons having an ownership interest 

with respect to the CAIR NOX Ozone 

Season allowances in the general 

account to include the change. 

(4) Objections concerning CAIR 

authorized account representative.

(i) Once a complete application for a 

general account under paragraph (b)(1) 

of this section has been submitted and 

received, the Administrator will rely on 

the application unless and until a 

superseding complete application for a 

general account under paragraph (b)(1) 

of this section is received by the 

Administrator. 

(ii) Except as provided in paragraph 

(b)(3)(i) or (ii) of this section, no 

objection or other communication 

submitted to the Administrator 

concerning the authorization, or any 

representation, action, inaction, or 

submission of the CAIR authorized 

account representative or any 

alternative CAIR authorized account 

representative for a general account 

shall affect any representation, action, 

inaction, or submission of the CAIR 

authorized account representative or 

any alternative CAIR authorized account 

representative or the finality of any 

decision or order by the Administrator 

under the CAIR NOX Ozone Season 

Trading Program. 

(iii) The Administrator will not 

adjudicate any private legal dispute 

concerning the authorization or any 

representation, action, inaction, or 

submission of the CAIR authorized 

account representative or any 

alternative CAIR authorized account 

representative for a general account, 

including private legal disputes 

concerning the proceeds of CAIR NOX

Ozone Season 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.

§ 96.352 Responsibilities of CAIR 

authorized account representative. 

Following the establishment of a 

CAIR NOX Ozone Season Allowance 

Tracking System account, all 

submissions to the Administrator 

pertaining to the account, including, but 

not limited to, submissions concerning 

the deduction or transfer of CAIR NOX

Ozone Season allowances in the 

account, shall be made only by the CAIR 

authorized account representative for 

the account.

§ 96.353 Recordation of CAIR NOX Ozone 

Season allowance allocations.

(a) By December 1, 2006, the 

Administrator will record in the CAIR 

NOX Ozone Season source’s compliance 

account the CAIR NOX Ozone Season 

allowances allocated for the CAIR NOX

Ozone Season units at a source, as 

submitted by the permitting authority in 

accordance with § 96.341(a), for the 

control periods in 2009, 2010, 2011, 

2012, 2013, and 2014. 

(b) By December 1, 2009, the 

Administrator will record in the CAIR 

NOX Ozone Season source’s compliance 

account the CAIR NOX Ozone Season 

allowances allocated for the CAIR NOX

Ozone Season units at the source, as 

submitted by the permitting authority or 

as determined by the Administrator in 

25396 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

accordance with § 96.341(b), for the 

control period in 2015. 

(c) In 2011 and each year thereafter, 

after the Administrator has made all 

deductions (if any) from a CAIR NOX

Ozone Season source’s compliance 

account under § 96.354, the 

Administrator will record in the CAIR 

NOX Ozone Season source’s compliance 

account the CAIR NOX Ozone Season 

allowances allocated for the CAIR NOX

Ozone Season units at the source, as 

submitted by the permitting authority or 

determined by the Administrator in 

accordance with § 96.341(b), for the 

control period in the sixth year after the 

year of the control period for which 

such deductions were or could have 

been made. 

(d) By September 1, 2009 and 

September 1 of each year thereafter, the 

Administrator will record in the CAIR 

NOX Ozone Season source’s compliance 

account the CAIR NOX Ozone Season 

allowances allocated for the CAIR NOX

Ozone Season units at the source, as 

submitted by the permitting authority or 

determined by the Administrator in 

accordance with § 96.341(c), for the 

control period in the year of the 

applicable deadline for recordation 

under this paragraph. 

(e) Serial numbers for allocated CAIR 

NOX Ozone Season allowances. When 

recording the allocation of CAIR NOX

Ozone Season allowances for a CAIR 

NOX Ozone Season unit in a compliance 

account, the Administrator will assign 

each CAIR NOX Ozone Season 

allowance a unique identification 

number that will include digits 

identifying the year of the control 

period for which the CAIR NOX Ozone 

Season allowance is allocated.

§ 96.354 Compliance with CAIR NOX

emissions limitation. 

(a) Allowance transfer deadline. The 

CAIR NOX Ozone Season allowances are 

available to be deducted for compliance 

with a source’s CAIR NOX Ozone 

Season emissions limitation for a 

control period in a given calendar year 

only if the CAIR NOX Ozone Season 

allowances: 

(1) Were allocated for the control 

period in the year or a prior year; 

(2) Are held in the compliance 

account as of the allowance transfer 

deadline for the control period or are 

transferred into the compliance account 

by a CAIR NOX Ozone Season allowance 

transfer correctly submitted for 

recordation under § 96.360 by the 

allowance transfer deadline for the 

control period; and 

(3) Are not necessary for deductions 

for excess emissions for a prior control 

period under paragraph (d) of this 

section. 

(b) Deductions for compliance.

Following the recordation, in 

accordance with § 96.361, of CAIR NOX

Ozone Season allowance transfers 

submitted for recordation in a source’s 

compliance account by the allowance 

transfer deadline for a control period, 

the Administrator will deduct from the 

compliance account CAIR NOX Ozone 

Season allowances available under 

paragraph (a) of this section in order to 

determine whether the source meets the 

CAIR NOX Ozone Season emissions 

limitation for the control period, as 

follows: 

(1) Until the amount of CAIR NOX

Ozone Season allowances deducted 

equals the number of tons of total 

nitrogen oxides emissions, determined 

in accordance with subpart HHHH of 

this part, from all CAIR NOX Ozone 

Season units at the source for the 

control period; or 

(2) If there are insufficient CAIR NOX

Ozone Season allowances to complete 

the deductions in paragraph (b)(1) of 

this section, until no more CAIR NOX

Ozone Season allowances available 

under paragraph (a) of this section 

remain in the compliance account. 

(c)(1) Identification of CAIR NO X

Ozone Season allowances by serial 

number. The CAIR authorized account 

representative for a source’s compliance 

account may request that specific CAIR 

NOX Ozone Season allowances, 

identified by serial number, in the 

compliance account be deducted for 

emissions or excess emissions for a 

control period in accordance with 

paragraph (b) or (d) of this section. Such 

request shall be submitted to the 

Administrator by the allowance transfer 

deadline for the control period and 

include, in a format prescribed by the 

Administrator, the identification of the 

CAIR NOX Ozone Season source and the 

appropriate serial numbers. 

(2) First-in, first-out. The 

Administrator will deduct CAIR NOX

Ozone Season allowances under 

paragraph (b) or (d) of this section from 

the source’s compliance account, in the 

absence of an identification or in the 

case of a partial identification of CAIR 

NOX Ozone Season allowances by serial 

number under paragraph (c)(1) of this 

section, on a first-in, first-out (FIFO) 

accounting basis in the following order: 

(i) Any CAIR NOX Ozone Season 

allowances that were allocated to the 

units at the source, in the order of 

recordation; and then 

(ii) Any CAIR NOX Ozone Season 

allowances that were allocated to any 

unit and transferred and recorded in the 

compliance account pursuant to subpart 

GGGG of this part, in the order of 

recordation.

(d) Deductions for excess emissions.

(1) After making the deductions for 

compliance under paragraph (b) of this 

section for a control period in a calendar 

year in which the CAIR NOX Ozone 

Season source has excess emissions, the 

Administrator will deduct from the 

source’s compliance account an amount 

of CAIR NOX Ozone Season allowances, 

allocated for the control period in the 

immediately following calendar year, 

equal to 3 times the number of tons of 

the source’s excess emissions. 

(2) Any allowance deduction required 

under paragraph (d)(1) of this section 

shall not affect the liability of the 

owners and operators of the CAIR NOX

Ozone Season source or the CAIR NOX

Ozone Season units at the source for any 

fine, penalty, or assessment, or their 

obligation to comply with any other 

remedy, for the same violations, as 

ordered under the Clean Air Act or 

applicable State law. 

(e) Recordation of deductions. The 

Administrator will record in the 

appropriate compliance account all 

deductions from such an account under 

paragraph (b) or (d) of this section. 

(f) Administrator’s action on 

submissions. (1) The Administrator may 

review and conduct independent audits 

concerning any submission under the 

CAIR NOX Ozone Season Trading 

Program and make appropriate 

adjustments of the information in the 

submissions. 

(2) The Administrator may deduct 

CAIR NOX Ozone Season allowances 

from or transfer CAIR NOX Ozone 

Season allowances to a source’s 

compliance account based on the 

information in the submissions, as 

adjusted under paragraph (f)(1) of this 

section.

§ 96.355 Banking. 

(a) CAIR NOX Ozone Season 

allowances may be banked for future 

use or transfer in a compliance account 

or a general account in accordance with 

paragraph (b) of this section. 

(b) Any CAIR NOX Ozone Season 

allowance that is held in a compliance 

account or a general account will 

remain in such account unless and until 

the CAIR NOX Ozone Season allowance 

is deducted or transferred under 

§ 96.354, § 96.356, or subpart GG of this 

part.

§ 96.356 Account error. 

The Administrator may, at his or her 

sole discretion and on his or her own 

motion, correct any error in any CAIR 

NOX Ozone Season Allowance Tracking 

System account. Within 10 business 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25397

days of making such correction, the 

Administrator will notify the CAIR 

authorized account representative for 

the account.

§ 96.357 Closing of general accounts. 

(a) The CAIR authorized account 

representative of a general account may 

submit to the Administrator a request to 

close the account, which shall include 

a correctly submitted allowance transfer 

under § 96.360 for any CAIR NOX Ozone 

Season allowances in the account to one 

or more other CAIR NOX Ozone Season 

Allowance Tracking System accounts. 

(b) If a general account has no 

allowance transfers in or out of the 

account for a 12-month period or longer 

and does not contain any CAIR NOX

Ozone Season allowances, the 

Administrator may notify the CAIR 

authorized account representative for 

the account that the account will be 

closed following 20 business days after 

the notice is sent. The account will be 

closed after the 20-day period unless, 

before the end of the 20-day period, the 

Administrator receives a correctly 

submitted transfer of CAIR NOX Ozone 

Season allowances into the account 

under § 96.360 or a statement submitted 

by the CAIR authorized account 

representative demonstrating to the 

satisfaction of the Administrator good 

cause as to why the account should not 

be closed.

Subpart GGGG—CAIR NOX Ozone 

Season Allowance Transfers

§ 96.360 Submission of CAIR NOX Ozone 

Season allowance transfers. 

A CAIR authorized account 

representative seeking recordation of a 

CAIR NOX Ozone Season allowance 

transfer shall submit the transfer to the 

Administrator. To be considered 

correctly submitted, the CAIR NOX

Ozone Season allowance transfer shall 

include the following elements, in a 

format specified by the Administrator: 

(a) The account numbers for both the 

transferor and transferee accounts; 

(b) The serial number of each CAIR 

NOX Ozone Season allowance that is in 

the transferor account and is to be 

transferred; and 

(c) The name and signature of the 

CAIR authorized account representative 

of the transferor account and the date 

signed.

§ 96.361 EPA recordation. 

(a) Within 5 business days (except as 

provided in paragraph (b) of this 

section) of receiving a CAIR NOX Ozone 

Season allowance transfer, the 

Administrator will record a CAIR NOX

Ozone Season allowance transfer by 

moving each CAIR NOX Ozone Season 

allowance from the transferor account to 

the transferee account as specified by 

the request, provided that: 

(1) The transfer is correctly submitted 

under § 96.360; and 

(2) The transferor account includes 

each CAIR NOX Ozone Season 

allowance identified by serial number in 

the transfer. 

(b) A CAIR NOX Ozone Season 

allowance transfer that is submitted for 

recordation after the allowance transfer 

deadline for a control period and that 

includes any CAIR NOX Ozone Season 

allowances allocated for any control 

period before such allowance transfer 

deadline will not be recorded until after 

the Administrator completes the 

deductions under § 96.354 for the 

control period immediately before such 

allowance transfer deadline. 

(c) Where a CAIR NOX Ozone Season 

allowance transfer submitted for 

recordation fails to meet the 

requirements of paragraph (a) of this 

section, the Administrator will not 

record such transfer.

§ 96.362 Notification. 

(a) Notification of recordation. Within 

5 business days of recordation of a CAIR 

NOX Ozone Season allowance transfer 

under § 96.361, the Administrator will 

notify the CAIR authorized account 

representatives of both the transferor 

and transferee accounts. 

(b) Notification of non-recordation.

Within 10 business days of receipt of a 

CAIR NOX Ozone Season allowance 

transfer that fails to meet the 

requirements of § 96.361(a), the 

Administrator will notify the CAIR 

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 CAIR NOX

Ozone Season allowance transfer for 

recordation following notification of 

non-recordation.

Subpart HHHH—Monitoring and 

Reporting

§ 96.370 General requirements. 

The owners and operators, and to the 

extent applicable, the CAIR designated 

representative, of a CAIR NOX Ozone 

Season unit, shall comply with the 

monitoring, recordkeeping, and 

reporting requirements as provided in 

this subpart and in subpart H of part 75 

of this chapter. For purposes of 

complying with such requirements, the 

definitions in § 96.302 and in § 72.2 of 

this chapter shall apply, and the terms 

‘‘affected unit,’’ ‘‘designated 

representative,’’ and ‘‘continuous 

emission monitoring system’’ (or 

‘‘CEMS’’) in part 75 of this chapter shall 

be deemed to refer to the terms ‘‘CAIR 

NOX Ozone Season unit,’’ ‘‘CAIR 

designated representative,’’ and 

‘‘continuous emission monitoring 

system’’ (or ‘‘CEMS’’) respectively, as 

defined in § 96.302. The owner or 

operator of a unit that is not a CAIR 

NOX Ozone Season unit but that is 

monitored under § 75.72(b)(2)(ii) of this 

chapter shall comply with the same 

monitoring, recordkeeping, and 

reporting requirements as a CAIR NOX

Ozone Season unit. 

(a) Requirements for installation, 

certification, and data accounting. The 

owner or operator of each CAIR NOX

Ozone Season unit shall: 

(1) Install all monitoring systems 

required under this subpart for 

monitoring NOX mass emissions and 

individual unit heat input (including all 

systems required to monitor NOX

emission rate, NOX concentration, stack 

gas moisture content, stack gas flow 

rate, CO2 or O2 concentration, and fuel 

flow rate, as applicable, in accordance 

with §§ 75.71 and 75.72 of this chapter); 

(2) Successfully complete all 

certification tests required under 

§ 96.371 and meet all other 

requirements of this subpart and part 75 

of this chapter applicable to the 

monitoring systems under paragraph 

(a)(1) of this section; and 

(3) Record, report, and quality-assure 

the data from the monitoring systems 

under paragraph (a)(1) of this section. 

(b) Compliance deadlines. The owner 

or operator shall meet the monitoring 

system certification and other 

requirements of paragraphs (a)(1) and 

(2) of this section on or before the 

following dates. The owner or operator 

shall record, report, and quality-assure 

the data from the monitoring systems 

under paragraph (a)(1) of this section on 

and after the following dates. 

(1) For the owner or operator of a 

CAIR NOX Ozone Season unit that 

commences commercial operation 

before July 1, 2007, by May 1, 2008. 

(2) For the owner or operator of a 

CAIR NOX Ozone Season unit that 

commences commercial operation on or 

after July 1, 2007 and that reports on an 

annual basis under § 96.374(d), by the 

later of the following dates: 

(i) 90 unit operating days or 180 

calendar days, whichever occurs first, 

after the date on which the unit 

commences commercial operation; or 

(ii) May 1, 2008, if the compliance 

date under paragraph (b)(2)(i) is before 

May 1, 2008. 

25398 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

(3) For the owner or operator of a 

CAIR NOX Ozone Season unit that 

commences operation on or after July 1, 

2007 and that reports on a control 

period basis under § 96.374(d)(2)(ii), by 

the later of the following dates: 

(i) 90 unit operating days or 180 

calendar days, whichever occurs first, 

after the date on which the unit 

commences commercial operation; or 

(ii) If the compliance date under 

paragraph (b)(3)(i) of this section is not 

during a control period, May 1 

immediately following the compliance 

date under paragraph (b)(3)(i) of this 

section. 

(4) For the owner or operator of a 

CAIR NOX Ozone Season unit for which 

construction of a new stack or flue or 

installation of add-on NOX emission 

controls is completed after the 

applicable deadline under paragraph 

(b)(1), (2), (6), or (7) of this section and 

that reports on an annual basis under 

§ 96.374(d), by 90 unit operating days or 

180 calendar days, whichever occurs 

first, after the date on which emissions 

first exit to the atmosphere through the 

new stack or flue or add-on NOX

emissions controls. 

(5) For the owner or operator of a 

CAIR NOX Ozone Season unit for which 

construction of a new stack or flue or 

installation of add-on NOX emission 

controls is completed after the 

applicable deadline under paragraph 

(b)(1), (3), (6), or (7) of this section and 

that reports on a control period basis 

under § 96.374(d)(2)(ii), by the later of 

the following dates: 

(i) 90 unit operating days or 180 

calendar days, whichever occurs first, 

after the date on which emissions first 

exit to the atmosphere through the new 

stack or flue or add-on NOX emissions 

controls; or

(ii) If the compliance date under 

paragraph (b)(5)(i) of this section is not 

during a control period, May 1 

immediately following the compliance 

date under paragraph (b)(5)(i) of this 

section. 

(6) Notwithstanding the dates in 

paragraphs (b)(1), (2), and (3) of this 

section, for the owner or operator of a 

unit for which a CAIR NOX Ozone 

Season opt-in permit application is 

submitted and not withdrawn and a 

CAIR opt-in permit is not yet issued or 

denied under subpart IIII of this part, by 

the date specified in § 96.384(b). 

(7) Notwithstanding the dates in 

paragraphs (b)(1), (2), and (3) of this 

section and solely for purposes of 

§ 96.306(c)(2), for the owner or operator 

of a CAIR NOX Ozone Season opt-in 

unit, by the date on which the CAIR 

NOX Ozone Season opt-in unit enters 

the CAIR NOX Ozone Season Trading 

Program as provided in § 96.384(g). 

(c) Reporting data. (1) Except as 

provided in paragraph (c)(2) of this 

section, the owner or operator of a CAIR 

NOX Ozone Season unit that does not 

meet the applicable compliance date set 

forth in paragraph (b) of this section for 

any monitoring system under paragraph 

(a)(1) of this section shall, for each such 

monitoring system, determine, record, 

and report maximum potential (or, as 

appropriate, minimum potential) values 

for NOX concentration, NOX emission 

rate, stack gas flow rate, stack gas 

moisture content, fuel flow rate, and any 

other parameters required to determine 

NOX mass emissions and heat input in 

accordance with § 75.31(b)(2) or (c)(3) of 

this chapter, section 2.4 of appendix D 

to part 75 of this chapter, or section 2.5 

of appendix E to part 75 of this chapter, 

as applicable. 

(2) The owner or operator of a CAIR 

NOX unit that does not meet the 

applicable compliance date set forth in 

paragraph (b)(4) of this section for any 

monitoring system under paragraph 

(a)(1) of this section shall, for each such 

monitoring system, determine, record, 

and report substitute data using the 

applicable missing data procedures in 

§ 75.74(c)(7) of this chapter or subpart D 

or subpart H of, or appendix D or 

appendix E to, part 75 of this chapter, 

in lieu of the maximum potential (or, as 

appropriate, minimum potential) values, 

for a parameter if the owner or operator 

demonstrates that there is continuity 

between the data streams for that 

parameter before and after the 

construction or installation under 

paragraph (b)(4) of this section. 

(d) Prohibitions. (1) No owner or 

operator of a CAIR NOX Ozone Season 

unit shall use any alternative 

monitoring system, alternative reference 

method, or any other alternative to any 

requirement of this subpart without 

having obtained prior written approval 

in accordance with § 96.375. 

(2) No owner or operator of a CAIR 

NOX Ozone Season unit shall operate 

the unit so as to discharge, or allow to 

be discharged, NOX emissions to the 

atmosphere without accounting for all 

such emissions in accordance with the 

applicable provisions of this subpart 

and part 75 of this chapter. 

(3) No owner or operator of a CAIR 

NOX Ozone Season unit shall disrupt 

the continuous emission monitoring 

system, any portion thereof, or any other 

approved emission monitoring method, 

and thereby avoid monitoring and 

recording NOX mass emissions 

discharged into the atmosphere, except 

for periods of recertification or periods 

when calibration, quality assurance 

testing, or maintenance is performed in 

accordance with the applicable 

provisions of this subpart and part 75 of 

this chapter. 

(4) No owner or operator of a CAIR 

NOX Ozone Season unit shall retire or 

permanently discontinue use of the 

continuous emission monitoring system, 

any component thereof, or any other 

approved monitoring system under this 

subpart, except under any one of the 

following circumstances: 

(i) During the period that the unit is 

covered by an exemption under § 96.305 

that is in effect; 

(ii) The owner or operator is 

monitoring emissions from the unit with 

another certified monitoring system 

approved, in accordance with the 

applicable provisions of this subpart 

and part 75 of this chapter, by the 

permitting authority for use at that unit 

that provides emission data for the same 

pollutant or parameter as the retired or 

discontinued monitoring system; or 

(iii) The CAIR designated 

representative submits notification of 

the date of certification testing of a 

replacement monitoring system for the 

retired or discontinued monitoring 

system in accordance with 

§ 96.371(d)(3)(i).

§ 96.371 Initial certification and 

recertification procedures. 

(a) The owner or operator of a CAIR 

NOX Ozone Season unit shall be exempt 

from the initial certification 

requirements of this section for a 

monitoring system under § 96.370(a)(1) 

if the following conditions are met: 

(1) The monitoring system has been 

previously certified in accordance with 

part 75 of this chapter; and 

(2) The applicable quality-assurance 

and quality-control requirements of 

§ 75.21 of this chapter and appendix B, 

appendix D, and appendix E to part 75 

of this chapter are fully met for the 

certified monitoring system described in 

paragraph (a)(1) of this section. 

(b) The recertification provisions of 

this section shall apply to a monitoring 

system under § 96.370(a)(1) exempt 

from initial certification requirements 

under paragraph (a) of this section.

(c) If the Administrator has previously 

approved a petition under § 75.17(a) or 

(b) of this chapter for apportioning the 

NOX emission rate measured in a 

common stack or a petition under 

§ 75.66 of this chapter for an alternative 

to a requirement in § 75.12, § 75.17, or 

subpart H of part 75 of this chapter, the 

CAIR designated representative shall 

resubmit the petition to the 

Administrator under § 96.375(a) to 

determine whether the approval applies 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25399

under the CAIR NOX Ozone Season 

Trading Program. 

(d) Except as provided in paragraph 

(a) of this section, the owner or operator 

of a CAIR NOX Ozone Season unit shall 

comply with the following initial 

certification and recertification 

procedures for a continuous monitoring 

system (i.e., a continuous emission 

monitoring system and an excepted 

monitoring system under appendices D 

and E to part 75 of this chapter) under 

§ 96.370(a)(1). The owner or operator of 

a unit that qualifies to use the low mass 

emissions excepted monitoring 

methodology under § 75.19 of this 

chapter or that qualifies to use an 

alternative monitoring system under 

subpart E of part 75 of this chapter shall 

comply with the procedures in 

paragraph (e) or (f) of this section 

respectively. 

(1) Requirements for initial 

certification. The owner or operator 

shall ensure that each continuous 

monitoring system under 

§ 96.370(a)(1)(including the automated 

data acquisition and handling system) 

successfully completes all of the initial 

certification testing required under 

§ 75.20 of this chapter by the applicable 

deadline in § 96.370(b). In addition, 

whenever the owner or operator installs 

a monitoring system to meet the 

requirements of this subpart in a 

location where no such monitoring 

system was previously installed, initial 

certification in accordance with § 75.20 

of this chapter is required. 

(2) Requirements for recertification.

Whenever the owner or operator makes 

a replacement, modification, or change 

in any certified continuous emission 

monitoring system under § 96.370(a)(1) 

that may significantly affect the ability 

of the system to accurately measure or 

record NOX mass emissions or heat 

input rate or to meet the qualityassurance and quality-control 

requirements of § 75.21 of this chapter 

or appendix B to part 75 of this chapter, 

the owner or operator shall recertify the 

monitoring system in accordance with 

§ 75.20(b) of this chapter. Furthermore, 

whenever the owner or operator makes 

a replacement, modification, or change 

to the flue gas handling system or the 

unit’s operation that may significantly 

change the stack flow or concentration 

profile, the owner or operator shall 

recertify each continuous emission 

monitoring system whose accuracy is 

potentially affected by the change, in 

accordance with § 75.20(b) of this 

chapter. Examples of changes to a 

continuous emission monitoring system 

that require recertification include: 

Replacement of the analyzer, complete 

replacement of an existing continuous 

emission monitoring system, or change 

in location or orientation of the 

sampling probe or site. Any fuel 

flowmeter systems, and any excepted 

NOX monitoring system under appendix 

E to part 75 of this chapter, under 

§ 96.370(a)(1) are subject to the 

recertification requirements in 

§ 75.20(g)(6) of this chapter. 

(3) Approval process for initial 

certification and recertification.

Paragraphs (d)(3)(i) through (iv) of this 

section apply to both initial certification 

and recertification of a continuous 

monitoring system under § 96.370(a)(1). 

For recertifications, replace the words 

‘‘certification’’ and ‘‘initial certification’’

with the word ‘‘recertification’’, replace 

the word ‘‘certified’’ with the word 

‘‘recertified,’’ and follow the procedures 

in §§ 75.20(b)(5) and (g)(7) of this 

chapter in lieu of the procedures in 

paragraph (d)(3)(v) of this section. 

(i) Notification of certification. The 

CAIR designated representative shall 

submit to the permitting authority, the 

appropriate EPA Regional Office, and 

the Administrator written notice of the 

dates of certification testing, in 

accordance with § 96.373. 

(ii) Certification application. The 

CAIR designated representative shall 

submit to the permitting authority a 

certification application for each 

monitoring system. A complete 

certification application shall include 

the information specified in § 75.63 of 

this chapter.

(iii) Provisional certification date. The 

provisional certification date for a 

monitoring system shall be determined 

in accordance with § 75.20(a)(3) of this 

chapter. A provisionally certified 

monitoring system may be used under 

the CAIR NOX Ozone Season Trading 

Program for a period not to exceed 120 

days after receipt by the permitting 

authority of the complete certification 

application for the monitoring system 

under paragraph (d)(3)(ii) of this 

section. Data measured and recorded by 

the provisionally certified monitoring 

system, in accordance with the 

requirements of part 75 of this chapter, 

will be considered valid quality-assured 

data (retroactive to the date and time of 

provisional certification), provided that 

the permitting authority does not 

invalidate the provisional certification 

by issuing a notice of disapproval 

within 120 days of the date of receipt of 

the complete certification application by 

the permitting authority. 

(iv) Certification application approval 

process. The permitting authority will 

issue a written notice of approval or 

disapproval of the certification 

application to the owner or operator 

within 120 days of receipt of the 

complete certification application under 

paragraph (d)(3)(ii) of this section. In the 

event the permitting authority does not 

issue such a notice within such 120-day 

period, each monitoring system that 

meets the applicable performance 

requirements of part 75 of this chapter 

and is included in the certification 

application will be deemed certified for 

use under the CAIR NOX Ozone Season 

Trading Program. 

(A) Approval notice. If the 

certification application is complete and 

shows that each monitoring system 

meets the applicable performance 

requirements of part 75 of this chapter, 

then the permitting authority will issue 

a written notice of approval of the 

certification application within 120 

days of receipt. 

(B) Incomplete application notice. If 

the certification application is not 

complete, then the permitting authority 

will issue a written notice of 

incompleteness that sets a reasonable 

date by which the CAIR designated 

representative must submit the 

additional information required to 

complete the certification application. If 

the CAIR designated representative does 

not comply with the notice of 

incompleteness by the specified date, 

then the permitting authority may issue 

a notice of disapproval under paragraph 

(d)(3)(iv)(C) of this section. The 120-day 

review period shall not begin before 

receipt of a complete certification 

application. 

(C) Disapproval notice. If the 

certification application shows that any 

monitoring system does not meet the 

performance requirements of part 75 of 

this chapter or if the certification 

application is incomplete and the 

requirement for disapproval under 

paragraph (d)(3)(iv)(B) of this section is 

met, then the permitting authority will 

issue a written notice of disapproval of 

the certification application. Upon 

issuance of such notice of disapproval, 

the provisional certification is 

invalidated by the permitting authority 

and the data measured and recorded by 

each uncertified monitoring system 

shall not be considered valid qualityassured data beginning with the date 

and hour of provisional certification (as 

defined under § 75.20(a)(3) of this 

chapter). The owner or operator shall 

follow the procedures for loss of 

certification in paragraph (d)(3)(v) of 

this section for each monitoring system 

that is disapproved for initial 

certification. 

(D) Audit decertification. The 

permitting authority or, for a CAIR NOX

Ozone Season opt-in unit or a unit for 

which a CAIR opt-in permit application 

is submitted and not withdrawn and a 

25400 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

CAIR opt-in permit is not yet issued or 

denied under subpart IIII of this part, 

the Administrator may issue a notice of 

disapproval of the certification status of 

a monitor in accordance with 

§ 96.372(b). 

(v) Procedures for loss of certification.

If the permitting authority or the 

Administrator issues a notice of 

disapproval of a certification 

application under paragraph 

(d)(3)(iv)(C) of this section or a notice of 

disapproval of certification status under 

paragraph (d)(3)(iv)(D) of this section, 

then: 

(A) The owner or operator shall 

substitute the following values, for each 

disapproved monitoring system, for 

each hour of unit operation during the 

period of invalid data specified under 

§ 75.20(a)(4)(iii), § 75.20(g)(7), or 

§ 75.21(e) of this chapter and continuing 

until the applicable date and hour 

specified under § 75.20(a)(5)(i) or (g)(7) 

of this chapter: 

(1) For a disapproved NOX emission 

rate (i.e., NOX-diluent) system, the 

maximum potential NOX emission rate, 

as defined in § 72.2 of this chapter. 

(2) For a disapproved NOX pollutant 

concentration monitor and disapproved 

flow monitor, respectively, the 

maximum potential concentration of 

NOX and the maximum potential flow 

rate, as defined in sections 2.1.2.1 and 

2.1.4.1 of appendix A to part 75 of this 

chapter. 

(3) For a disapproved moisture 

monitoring system and disapproved 

diluent gas monitoring system, 

respectively, the minimum potential 

moisture percentage and either the 

maximum potential CO2 concentration 

or the minimum potential O2

concentration (as applicable), as defined 

in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of 

appendix A to part 75 of this chapter. 

(4) For a disapproved fuel flowmeter 

system, the maximum potential fuel 

flow rate, as defined in section 2.4.2.1 

of appendix D to part 75 of this chapter. 

(5) For a disapproved excepted NOX

monitoring system under appendix E to 

part 75 of this chapter, the fuel-specific 

maximum potential NOX emission rate, 

as defined in § 72.2 of this chapter.

(B) The CAIR designated 

representative shall submit a 

notification of certification retest dates 

and a new certification application in 

accordance with paragraphs (d)(3)(i) and 

(ii) of this section. 

(C) The owner or operator shall repeat 

all certification tests or other 

requirements that were failed by the 

monitoring system, as indicated in the 

permitting authority’s or the 

Administrator’s notice of disapproval, 

no later than 30 unit operating days 

after the date of issuance of the notice 

of disapproval. 

(e) Initial certification and 

recertification procedures for units 

using the low mass emission excepted 

methodology under § 75.19 of this 

chapter. The owner or operator of a unit 

qualified to use the low mass emissions 

(LME) excepted methodology under 

§ 75.19 of this chapter shall meet the 

applicable certification and 

recertification requirements in 

§§ 75.19(a)(2) and 75.20(h) of this 

chapter. If the owner or operator of such 

a unit elects to certify a fuel flowmeter 

system for heat input determination, the 

owner or operator shall also meet the 

certification and recertification 

requirements in § 75.20(g) of this 

chapter. 

(f) Certification/recertification 

procedures for alternative monitoring 

systems. The CAIR designated 

representative of each unit for which the 

owner or operator intends to use an 

alternative monitoring system approved 

by the Administrator and, if applicable, 

the permitting authority under subpart E 

of part 75 of this chapter shall comply 

with the applicable notification and 

application procedures of § 75.20(f) of 

this chapter.

§ 96.372 Out of control periods. 

(a) Whenever any monitoring system 

fails to meet the quality-assurance and 

quality-control requirements or data 

validation requirements of part 75 of 

this chapter, data shall be substituted 

using the applicable missing data 

procedures in subpart D or subpart H of, 

or appendix D or appendix E to, 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 monitoring system should not have 

been certified or recertified because it 

did not meet a particular performance 

specification or other requirement under 

§ 96.371 or the applicable provisions of 

part 75 of this chapter, both at the time 

of the initial certification or 

recertification application submission 

and at the time of the audit, the 

permitting authority or, for a CAIR NOX

Ozone Season opt-in unit or a unit for 

which a CAIR opt-in permit application 

is submitted and not withdrawn and a 

CAIR opt-in permit is not yet issued or 

denied under subpart IIII of this part, 

the Administrator will issue a notice of 

disapproval of the certification status of 

such monitoring system. For the 

purposes of this paragraph, an audit 

shall be either a field audit or an audit 

of any information submitted to the 

permitting authority or the 

Administrator. By issuing the notice of 

disapproval, the permitting authority or 

the Administrator revokes prospectively 

the certification status of the monitoring 

system. The data measured and 

recorded by the monitoring system shall 

not be considered valid quality-assured 

data from the date of issuance of the 

notification of the revoked certification 

status until the date and time that the 

owner or operator completes 

subsequently approved initial 

certification or recertification tests for 

the monitoring system. The owner or 

operator shall follow the applicable 

initial certification or recertification 

procedures in § 96.371 for each 

disapproved monitoring system.

§ 96.373 Notifications. 

The CAIR designated representative 

for a CAIR NOX Ozone Season 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.

§ 96.374 Recordkeeping and reporting. 

(a) General provisions. The CAIR 

designated representative shall comply 

with all recordkeeping and reporting 

requirements in this section, the 

applicable recordkeeping and reporting 

requirements under § 75.73 of this 

chapter, and the requirements of 

§ 96.310(e)(1). 

(b) Monitoring plans. The owner or 

operator of a CAIR NOX Ozone Season 

unit shall comply with requirements of 

§ 75.73(c) and (e) of this chapter and, for 

a unit for which a CAIR opt-in permit 

application is submitted and not 

withdrawn and a CAIR opt-in permit is 

not yet issued or denied under subpart 

IIII of this part, §§ 96.383 and 96.384(a). 

(c) Certification applications. The 

CAIR designated representative shall 

submit an application to the permitting 

authority within 45 days after 

completing all initial certification or 

recertification tests required under 

§ 96.371, including the information 

required under § 75.63 of this chapter. 

(d) Quarterly reports. The CAIR 

designated representative shall submit 

quarterly reports, as follows: 

(1) If the CAIR NOX Ozone Season 

unit is subject to an Acid Rain 

emissions limitation or a CAIR NOX

emissions limitation or if the owner or 

operator of such unit chooses to report 

on an annual basis under this subpart, 

the CAIR designated representative shall 

meet the requirements of subpart H of 

part 75 of this chapter (concerning 

monitoring of NOX mass emissions) for 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25401

such unit for the entire year and shall 

report the NOX mass emissions data and 

heat input data for such unit, in an 

electronic quarterly report in a format 

prescribed by the Administrator, for 

each calendar quarter beginning with:

(i) For a unit that commences 

commercial operation before July 1, 

2007, the calendar quarter covering May 

1, 2008 through June 30, 2008; or 

(ii) For a unit that commences 

commercial operation on or after July 1, 

2007, the calendar quarter 

corresponding to the earlier of the date 

of provisional certification or the 

applicable deadline for initial 

certification under § 96.370(b), unless 

that quarter is the third or fourth quarter 

of 2007, in which case reporting shall 

commence in the quarter covering May 

1, 2008 through June 30, 2008. 

(2) If the CAIR NOX Ozone Season 

unit is not subject to an Acid Rain 

emissions limitation or a CAIR NOX

emissions limitation, then the CAIR 

designated representative shall either: 

(i) Meet the requirements of subpart H 

of part 75 (concerning monitoring of 

NOX mass emissions) for such unit for 

the entire year and report the NOX mass 

emissions data and heat input data for 

such unit in accordance with paragraph 

(d)(1) of this section; or 

(ii) Meet the requirements of subpart 

H of part 75 for the control period 

(including the requirements in 

§ 75.74(c) of this chapter) and report 

NOX mass emissions data and heat 

input data (including the data described 

in § 75.74(c)(6) of this chapter) for such 

unit only for the control period of each 

year and report, in an electronic 

quarterly report in a format prescribed 

by the Administrator, for each calendar 

quarter beginning with: 

(A) For a unit that commences 

commercial operation before July 1, 

2007, the calendar quarter covering May 

1, 2008 through June 30, 2008; 

(B) For a unit that commences 

commercial operation on or after July 1, 

2007, the calendar quarter 

corresponding to the earlier of the date 

of provisional certification or the 

applicable deadline for initial 

certification under § 96.370(b), unless 

that date is not during a control period, 

in which case reporting shall commence 

in the quarter that includes May 1 

through June 30 of the first control 

period after such date. 

(2) The CAIR designated 

representative shall submit each 

quarterly report to the Administrator 

within 30 days following the end of the 

calendar quarter covered by the report. 

Quarterly reports shall be submitted in 

the manner specified in § 75.73(f) of this 

chapter. 

(3) For CAIR NOX Ozone Season units 

that are also subject to an Acid Rain 

emissions limitation or the CAIR NOX

Annual Trading Program or CAIR SO2

Trading Program, quarterly reports shall 

include the applicable data and 

information required by subparts F 

through H of part 75 of this chapter as 

applicable, in addition to the NOX mass 

emission data, heat input data, and 

other information required by this 

subpart. 

(e) Compliance certification. The 

CAIR designated representative shall 

submit to the Administrator a 

compliance certification (in a format 

prescribed by the Administrator) in 

support of each quarterly report based 

on reasonable inquiry of those persons 

with primary responsibility for ensuring 

that all of the unit’s emissions are 

correctly and fully monitored. The 

certification shall state that: 

(1) The monitoring data submitted 

were recorded in accordance with the 

applicable requirements of this subpart 

and part 75 of this chapter, including 

the quality assurance procedures and 

specifications; 

(2) For a unit with add-on NOX

emission controls and for all hours 

where NOX data are substituted in 

accordance with § 75.34(a)(1) of this 

chapter, the add-on emission controls 

were operating within the range of 

parameters listed in the quality 

assurance/quality control program 

under appendix B to part 75 of this 

chapter and the substitute data values 

do not systematically underestimate 

NOX emissions; and 

(3) For a unit that is reporting on a 

control period basis under paragraph 

(d)(2)(ii) of this section, the NOX

emission rate and NOX concentration 

values substituted for missing data 

under subpart D of part 75 of this 

chapter are calculated using only values 

from a control period and do not 

systematically underestimate NOX

emissions.

§ 96.375 Petitions. 

(a) Except as provided in paragraph 

(b)(2) of this section, the CAIR 

designated representative of a CAIR 

NOX Ozone Season 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 in 

writing by the Administrator, in 

consultation with the permitting 

authority. 

(b)(1) The CAIR designated 

representative of a CAIR NOX Ozone 

Season unit that is not subject to an 

Acid Rain emissions limitation may 

submit a petition under § 75.66 of this 

chapter to the permitting authority and 

the Administrator requesting approval 

to apply an alternative to any 

requirement of this subpart. Application 

of an alternative to any requirement of 

this subpart is in accordance with this 

subpart only to the extent that the 

petition is approved in writing by both 

the permitting authority and the 

Administrator. 

(2) The CAIR designated 

representative of a CAIR NOX Ozone 

Season 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 continuous 

emission monitoring system required 

under § 75.72 of this chapter. 

Application of an alternative to any 

such requirement is in accordance with 

this subpart only to the extent that the 

petition is approved in writing by both 

the permitting authority and the 

Administrator.

§ 96.376 Additional requirements to 

provide heat input data. 

The owner or operator of a CAIR NOX

Ozone Season unit that monitors and 

reports NOX mass emissions using a 

NOX concentration system and a flow 

system shall also monitor and report 

heat input rate at the unit level using the 

procedures set forth in part 75 of this 

chapter.

Subpart IIII—CAIR NOX Ozone Season 

Opt-in Units

§ 96.380 Applicability. 

A CAIR NOX Ozone Season opt-in 

unit must be a unit that: 

(a) Is located in the State; 

(b) Is not a CAIR NOX Ozone Season 

unit under § 96.304 and is not covered 

by a retired unit exemption under 

§ 96.305 that is in effect; 

(c) Is not covered by a retired unit 

exemption under § 72.8 of this chapter 

that is in effect; 

(d) Has or is required or qualified to 

have a title V operating permit or other 

federally enforceable permit; and 

(e) Vents all of its emissions to a stack 

and can meet the monitoring, 

recordkeeping, and reporting 

requirements of subpart HHHH of this 

part.

§ 96.381 General. 

(a) Except as otherwise provided in 

§§ 96.301 through 96.304, §§ 96.306 

25402 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

through 96.308, and subparts BBBB and 

CCCC and subparts FFFF through 

HHHH of this part, a CAIR NOX Ozone 

Season opt-in unit shall be treated as a 

CAIR NOX Ozone Season unit for 

purposes of applying such sections and 

subparts of this part. 

(b) Solely for purposes of applying, as 

provided in this subpart, the 

requirements of subpart HHHH of this 

part to a unit for which a CAIR opt-in 

permit application is submitted and not 

withdrawn and a CAIR opt-in permit is 

not yet issued or denied under this 

subpart, such unit shall be treated as a 

CAIR NOX Ozone Season unit before 

issuance of a CAIR opt-in permit for 

such unit.

§ 96.382 CAIR designated representative. 

Any CAIR NOX Ozone Season opt-in 

unit, and any unit for which a CAIR optin permit application is submitted and 

not withdrawn and a CAIR opt-in 

permit is not yet issued or denied under 

this subpart, located at the same source 

as one or more CAIR NOX Ozone Season 

units shall have the same CAIR 

designated representative and alternate 

CAIR designated representative as such 

CAIR NOX Ozone Season units.

§ 96.383 Applying for CAIR opt-in permit. 

(a) Applying for initial CAIR opt-in 

permit. The CAIR designated 

representative of a unit meeting the 

requirements for a CAIR NOX Ozone 

Season opt-in unit in § 96.380 may 

apply for an initial CAIR opt-in permit 

at any time, except as provided under 

§ 96.386 (f) and (g), and, in order to 

apply, must submit the following: 

(1) A complete CAIR permit 

application under § 96.322; 

(2) A certification, in a format 

specified by the permitting authority, 

that the unit: 

(i) Is not a CAIR NOX Ozone Season 

unit under § 96.304 and is not covered 

by a retired unit exemption under 

§ 96.305 that is in effect; 

(ii) Is not covered by a retired unit 

exemption under § 72.8 of this chapter 

that is in effect; 

(iii) Vents all of its emissions to a 

stack; and 

(iv) Has documented heat input for 

more than 876 hours during the 6 

months immediately preceding 

submission of the CAIR permit 

application under § 96.322; 

(3) A monitoring plan in accordance 

with subpart HHHH of this part; 

(4) A complete certificate of 

representation under § 96.313 consistent 

with § 96.382, if no CAIR designated 

representative has been previously 

designated for the source that includes 

the unit; and

(5) A statement, in a format specified 

by the permitting authority, whether the 

CAIR designated representative requests 

that the unit be allocated CAIR NOX

Ozone Season allowances under 

§ 96.388(c) (subject to the conditions in 

§§ 96.384(h) and 96.386(g)). 

(b) Duty to reapply. (1) The CAIR 

designated representative of a CAIR 

NOX Ozone Season opt-in unit shall 

submit a complete CAIR permit 

application under § 96.322 to renew the 

CAIR opt-in unit permit in accordance 

with the permitting authority’s 

regulations for title V operating permits, 

or the permitting authority’s regulations 

for other federally enforceable permits if 

applicable, addressing permit renewal. 

(2) Unless the permitting authority 

issues a notification of acceptance of 

withdrawal of the CAIR opt-in unit from 

the CAIR NOX Annual Trading Program 

in accordance with § 96.186 or the unit 

becomes a CAIR NOX unit under 

§ 96.304, the CAIR NOX opt-in unit shall 

remain subject to the requirements for a 

CAIR NOX opt-in unit, even if the CAIR 

designated representative for the CAIR 

NOX opt-in unit fails to submit a CAIR 

permit application that is required for 

renewal of the CAIR opt-in permit under 

paragraph (b)(1) of this section.

§ 96.384 Opt-in process. 

The permitting authority will issue or 

deny a CAIR opt-in permit for a unit for 

which an initial application for a CAIR 

opt-in permit under § 96.383 is 

submitted in accordance with the 

following: 

(a) Interim review of monitoring plan.

The permitting authority and the 

Administrator will determine, on an 

interim basis, the sufficiency of the 

monitoring plan accompanying the 

initial application for a CAIR opt-in 

permit under § 96.383. 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 and all other applicable 

parameters are monitored and reported 

in accordance with subpart HHHH of 

this part. A determination of sufficiency 

shall not be construed as acceptance or 

approval of the monitoring plan. 

(b) Monitoring and reporting. (1)(i) If 

the permitting authority and the 

Administrator determine that the 

monitoring plan is sufficient under 

paragraph (a) of this section, the owner 

or operator shall monitor and report the 

NOX emissions rate and the heat input 

of the unit emissions rate and the heat 

input of the unit and all other 

applicable parameters, in accordance 

with subpart HHHH of this part, starting 

on the date of certification of the 

appropriate monitoring systems under 

subpart HHHH of this part and 

continuing until a CAIR opt-in permit is 

denied under § 96.384(f) or, if a CAIR 

opt-in permit is issued, the date and 

time when the unit is withdrawn from 

the CAIR NOX Ozone Season Trading 

Program in accordance with § 96.386. 

(ii) The monitoring and reporting 

under paragraph (b)(1)(i) of this section 

shall include the entire control period 

immediately before the date on which 

the unit enters the CAIR NOX Ozone 

Season Trading Program under 

§ 96.384(g), during which period 

monitoring system availability must not 

be less than 90 percent under subpart 

HHHH of this part and the unit must be 

in full compliance with any applicable 

State or Federal emissions or emissionsrelated requirements. 

(2) To the extent the NOX emissions 

rate and the heat input of the unit are 

monitored and reported in accordance 

with subpart HHHH of this part for one 

or more control periods, in addition to 

the control period under paragraph 

(b)(1)(ii) of this section, during which 

control periods monitoring system 

availability is not less than 90 percent 

under subpart HHHH of this part and 

the unit is in full compliance with any 

applicable State or Federal emissions or 

emissions-related requirements and 

which control periods begin not more 

than 3 years before the unit enters the 

CAIR NOX Ozone Season Trading 

Program under § 96.384(g), such 

information shall be used as provided in 

paragraphs (c) and (d) of this section. 

(c) Baseline heat input. The unit’s 

baseline heat rate shall equal: 

(1) If the unit’s NOX emissions rate 

and heat input are monitored and 

reported for only one control period, in 

accordance with paragraph (b)(1) of this 

section, the unit’s total heat input (in 

mmBtu) for the control period; or

(2) If the unit’s NOX emissions rate 

and heat input are monitored and 

reported for more than one control 

period, in accordance with paragraphs 

(b)(1) and (2) of this section, the average 

of the amounts of the unit’s total heat 

input (in mmBtu) for the control period 

under paragraph (b)(1)(ii) of this section 

and the control periods under paragraph 

(b)(2) of this section. 

(d) Baseline NOX emission rate. The 

unit’s baseline NOX emission rate shall 

equal: 

(1) If the unit’s NOX emissions rate 

and heat input are monitored and 

reported for only one control period, in 

accordance with paragraph (b)(1) of this 

section, the unit’s NOX emissions rate 

(in lb/mmBtu) for the control period; 

(2) If the unit’s NOX emissions rate 

and heat input are monitored and 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25403

reported for more than one control 

period, in accordance with paragraphs 

(b)(1) and (2) of this section, and the 

unit does not have add-on NOX

emission controls during any such 

control periods, the average of the 

amounts of the unit’s NOX emissions 

rate (in lb/mmBtu) for the control period 

under paragraph (b)(1)(ii) of this section 

and the control periods under paragraph 

(b)(2) of this section; or 

(3) If the unit’s NOX emissions rate 

and heat input are monitored and 

reported for more than one control 

period, in accordance with paragraphs 

(b)(1) and (2) of this section, and the 

unit has add-on NOX emission controls 

during any such control periods, the 

average of the amounts of the unit’s 

NOX emissions rate (in lb/mmBtu) for 

such control period during which the 

unit has add-on NOX emission controls. 

(e) Issuance of CAIR opt-in permit.

After calculating the baseline heat input 

and the baseline NOX emissions rate for 

the unit under paragraphs (c) and (d) of 

this section and if the permitting 

authority determines that the CAIR 

designated representative shows that the 

unit meets the requirements for a CAIR 

NOX Ozone Season opt-in unit in 

§ 96.380 and meets the elements 

certified in § 96.383(a)(2), the permitting 

authority will issue a CAIR opt-in 

permit. The permitting authority will 

provide a copy of the CAIR opt-in 

permit to the Administrator, who will 

then establish a compliance account for 

the source that includes the CAIR NOX

Ozone Season opt-in unit unless the 

source already has a compliance 

account. 

(f) Issuance of denial of CAIR opt-in 

permit. Notwithstanding paragraphs (a) 

through (e) of this section, if at any time 

before issuance of a CAIR opt-in permit 

for the unit, the permitting authority 

determines that the CAIR designated 

representative fails to show that the unit 

meets the requirements for a CAIR NOX

Ozone Season opt-in unit in § 96.380 or 

meets the elements certified in 

§ 96.383(a)(2), the permitting authority 

will issue a denial of a CAIR opt-in 

permit for the unit. 

(g) Date of entry into CAIR NOX

Ozone Season Trading Program. A unit 

for which an initial CAIR opt-in permit 

is issued by the permitting authority 

shall become a CAIR NOX Ozone Season 

opt-in unit, and a CAIR NOX Ozone 

Season unit, as of the later of May 1, 

2009 or May 1 of the first control period 

during which such CAIR opt-in permit 

is issued. 

(h) Repowered CAIR NOX Ozone 

Season opt-in unit. (1) If CAIR 

designated representative requests, and 

the permitting authority issues a CAIR 

opt-in permit providing for, allocation 

to a CAIR NOX Ozone Season opt-in 

unit of CAIR NOX Ozone Season 

allowances under § 96.388(c) and such 

unit is repowered after its date of entry 

into the CAIR NOX Ozone Season 

Trading Program under paragraph (g) of 

this section, the repowered unit shall be 

treated as a CAIR NOX Ozone Season 

opt-in unit replacing the original CAIR 

NOX Ozone Season opt-in unit, as of the 

date of start-up of the repowered unit’s 

combustion chamber. 

(2) Notwithstanding paragraphs (c) 

and (d) of this section, as of the date of 

start-up under paragraph (h)(1) of this 

section, the repowered unit shall be 

deemed to have the same date of 

commencement of operation, date of 

commencement of commercial 

operation, baseline heat input, and 

baseline NOX emission rate as the 

original CAIR NOX Ozone Season opt-in 

unit, and the original CAIR NOX Ozone 

Season opt-in unit shall no longer be 

treated as a CAIR opt-in unit or a CAIR 

NOX Ozone Season unit.

§ 96.385 CAIR opt-in permit contents. 

(a) Each CAIR opt-in permit will 

contain: 

(1) All elements required for a 

complete CAIR permit application 

under § 96.322; 

(2) The certification in § 96.383(a)(2); 

(3) The unit’s baseline heat input 

under § 96.384(c); 

(4) The unit’s baseline NOX emission 

rate under § 96.384(d); 

(5) A statement whether the unit is to 

be allocated CAIR NOX Ozone Season 

allowances under § 96.388(c) (subject to 

the conditions in §§ 96.384(h) and 

96.386(g)); 

(6) A statement that the unit may 

withdraw from the CAIR NOX Ozone 

Season Trading Program only in 

accordance with § 96.386; and 

(7) A statement that the unit is subject 

to, and the owners and operators of the 

unit must comply with, the 

requirements of § 96.387. 

(b) Each CAIR opt-in permit is 

deemed to incorporate automatically the 

definitions of terms under § 96.302 and, 

upon recordation by the Administrator 

under subpart FFFF or GGGG of this 

part or this subpart, every allocation, 

transfer, or deduction of CAIR NOX

Ozone Season allowances to or from the 

compliance account of the source that 

includes a CAIR NOX Ozone Season optin unit covered by the CAIR opt-in 

permit.

§ 96.386 Withdrawal from CAIR NOX Ozone 

Season Trading Program. 

Except as provided under paragraph 

(g) of this section, a CAIR NOX Ozone 

Season opt-in unit may withdraw from 

the CAIR NOX Ozone Season Trading 

Program, but only if the permitting 

authority issues a notification to the 

CAIR designated representative of the 

CAIR NOX Ozone Season opt-in unit of 

the acceptance of the withdrawal of the 

CAIR NOX Ozone Season opt-in unit in 

accordance with paragraph (d) of this 

section. 

(a) Requesting withdrawal. In order to 

withdraw a CAIR opt-in unit from the 

CAIR NOX Ozone Season Trading 

Program, the CAIR designated 

representative of the CAIR NOX Ozone 

Season opt-in unit shall submit to the 

permitting authority a request to 

withdraw effective as of midnight of 

September 30 of a specified calendar 

year, which date must be at least 4 years 

after September 30 of the year of entry 

into the CAIR NOX Ozone Season 

Trading Program under § 96.384(g). The 

request must be submitted no later than 

90 days before the requested effective 

date of withdrawal. 

(b) Conditions for withdrawal. Before 

a CAIR NOX Ozone Season opt-in unit 

covered by a request under paragraph 

(a) of this section may withdraw from 

the CAIR NOX Ozone Season Trading 

Program and the CAIR opt-in permit 

may be terminated under paragraph (e) 

of this section, the following conditions 

must be met: 

(1) For the control period ending on 

the date on which the withdrawal is to 

be effective, the source that includes the 

CAIR NOX Ozone Season opt-in unit 

must meet the requirement to hold CAIR 

NOX Ozone Season allowances under 

§ 96.306(c) and cannot have any excess 

emissions. 

(2) After the requirement for 

withdrawal under paragraph (b)(1) of 

this section is met, the Administrator 

will deduct from the compliance 

account of the source that includes the 

CAIR NOX Ozone Season opt-in unit 

CAIR NOX Ozone Season allowances 

equal in number to and allocated for the 

same or a prior control period as any 

CAIR NOX Ozone Season allowances 

allocated to the CAIR NOX Ozone 

Season opt-in unit under § 96.388 for 

any control period for which the 

withdrawal is to be effective. If there are 

no remaining CAIR NOX Ozone Season 

units at the source, the Administrator 

will close the compliance account, and 

the owners and operators of the CAIR 

NOX Ozone Season opt-in unit may 

submit a CAIR NOX Ozone Season 

allowance transfer for any remaining 

CAIR NOX Ozone Season allowances to 

another CAIR NOX Ozone Season 

Allowance Tracking System in 

accordance with subpart GGGG of this 

part. 

25404 Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 

(c) Notification. (1) After the 

requirements for withdrawal under 

paragraphs (a) and (b) of this section are 

met (including deduction of the full 

amount of CAIR NOX Ozone Season 

allowances required), the permitting 

authority will issue a notification to the 

CAIR designated representative of the 

CAIR NOX Ozone Season opt-in unit of 

the acceptance of the withdrawal of the 

CAIR NOX Ozone Season opt-in unit as 

of midnight on September 30 of the 

calendar year for which the withdrawal 

was requested. 

(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 

CAIR designated representative of the 

CAIR NOX Ozone Season opt-in unit 

that the CAIR NOX Ozone Season optin unit’s request to withdraw is denied. 

Such CAIR NOX opt-in unit shall 

continue to be a CAIR NOX Ozone 

Season opt-in unit. 

(d) Permit amendment. After the 

permitting authority issues a 

notification under paragraph (c)(1) of 

this section that the requirements for 

withdrawal have been met, the 

permitting authority will revise the 

CAIR permit covering the CAIR NOX

Ozone Season opt-in unit to terminate 

the CAIR opt-in permit for such unit as 

of the effective date specified under 

paragraph (c)(1) of this section. The unit 

shall continue to be a CAIR NOX Ozone 

Season opt-in unit until the effective 

date of the termination and shall 

comply with all requirements under the 

CAIR NOX Ozone Season Trading 

Program concerning any control periods 

for which the unit is a CAIR NOX Ozone 

Season opt-in unit, even if such 

requirements arise or must be complied 

with after the withdrawal takes effect. 

(e) Reapplication upon failure to meet 

conditions of withdrawal. If the 

permitting authority denies the CAIR 

NOX Ozone Season opt-in unit’s request 

to withdraw, the CAIR designated 

representative may submit another 

request to withdraw in accordance with 

paragraphs (a) and (b) of this section. 

(f) Ability to reapply to the CAIR NOX

Ozone Season Trading Program. Once a 

CAIR NOX Ozone Season opt-in unit 

withdraws from the CAIR NOX Ozone 

Season Trading Program and its CAIR 

opt-in permit is terminated under this 

section, the CAIR designated 

representative may not submit another 

application for a CAIR opt-in permit 

under § 96.383 for such CAIR NOX

Ozone Season opt-in unit before the 

date that is 4 years after the date on 

which the withdrawal became effective. 

Such new application for a CAIR opt-in 

permit will be treated as an initial 

application for a CAIR opt-in permit 

under § 96.384. 

(g) Inability to withdraw.

Notwithstanding paragraphs (a) through 

(f) of this section, a CAIR NOX Ozone 

Season opt-in unit shall not be eligible 

to withdraw from the CAIR NOX Ozone 

Season Trading Program if the CAIR 

designated representative of the CAIR 

NOX opt-in unit requests, and the 

permitting authority issues a CAIR optin permit providing for, allocation to the 

CAIR NOX Ozone Season opt-in unit of 

CAIR NOX Ozone Season allowances 

under § 96.388(c).

§ 96.387 Change in regulatory status.

(a) Notification. If a CAIR NOX Ozone 

Season opt-in unit becomes a CAIR NOX

Ozone Season unit under § 96.304, then 

the CAIR designated representative shall 

notify in writing the permitting 

authority and the Administrator of such 

change in the CAIR NOX Ozone Season 

opt-in unit’s regulatory status, within 30 

days of such change. 

(b) Permitting authority’s and 

Administrator’s actions. (1) If a CAIR 

NOX Ozone Season opt-in unit becomes 

a CAIR NOX Ozone Season unit under 

§ 96.304, the permitting authority will 

revise the CAIR NOX Ozone Season optin unit’s CAIR opt-in permit to meet the 

requirements of a CAIR permit under 

§ 96.323 as of the date on which the 

CAIR NOX Ozone Season opt-in unit 

becomes a CAIR NOX Ozone Season 

unit under § 96.304. 

(2)(i) The Administrator will deduct 

from the compliance account of the 

source that includes the CAIR NOX

Ozone Season opt-in unit that becomes 

a CAIR NOX Ozone Season unit under 

§ 96.304, CAIR NOX Ozone Season 

allowances equal in number to and 

allocated for the same or a prior control 

period as: 

(A) Any CAIR NOX Ozone Season 

allowances allocated to the CAIR NOX

Ozone Season opt-in unit under 

§ 96.388 for any control period after the 

date on which the CAIR NOX Ozone 

Season opt-in unit becomes a CAIR NOX

Ozone Season unit under § 96.304; and 

(B) If the date on which the CAIR NOX

Ozone Season opt-in unit becomes a 

CAIR NOX Ozone Season unit under 

§ 96.304 is not September 30, the CAIR 

NOX Ozone Season allowances allocated 

to the CAIR NOX Ozone Season opt-in 

unit under § 96.388 for the control 

period that includes the date on which 

the CAIR NOX Ozone Season opt-in unit 

becomes a CAIR NOX Ozone Season 

unit under § 96.304, multiplied by the 

ratio of the number of days, in the 

control period, starting with the date on 

which the CAIR NOX Ozone Season optin unit becomes a CAIR NOX Ozone 

Season unit under § 96.304 divided by 

the total number of days in the control 

period and rounded to the nearest 

whole allowance as appropriate. 

(ii) The CAIR designated 

representative shall ensure that the 

compliance account of the source that 

includes the CAIR NOX Ozone Season 

unit that becomes a CAIR NOX Ozone 

Season unit under § 96.304 contains the 

CAIR NOX Ozone Season allowances 

necessary for completion of the 

deduction under paragraph (b)(2)(i) of 

this section. 

(3)(i) For every control period after 

the date on which the CAIR NOX Ozone 

Season opt-in unit becomes a CAIR NOX

Ozone Season unit under § 96.304, the 

CAIR NOX Ozone Season opt-in unit 

will be treated, solely for purposes of 

CAIR NOX Ozone Season allowance 

allocations under § 96.342, as a unit that 

commences operation on the date on 

which the CAIR NOX Ozone Season optin unit becomes a CAIR NOX Ozone 

Season unit under § 96.304 and will be 

allocated CAIR NOX Ozone Season 

allowances under § 96.342. 

(ii) Notwithstanding paragraph 

(b)(3)(i) of this section, if the date on 

which the CAIR NOX Ozone Season optin unit becomes a CAIR NOX Ozone 

Season unit under § 96.304 is not May 

1, the following number of CAIR NOX

Ozone Season allowances will be 

allocated to the CAIR NOX Ozone 

Season opt-in unit (as a CAIR NOX

Ozone Season unit) under § 96.342 for 

the control period that includes the date 

on which the CAIR NOX Ozone Season 

opt-in unit becomes a CAIR NOX Ozone 

Season unit under § 96.304: 

(A) The number of CAIR NOX Ozone 

Season allowances otherwise allocated 

to the CAIR NOX Ozone Season opt-in 

unit (as a CAIR NOX Ozone Season unit) 

under § 96.342 for the control period 

multiplied by; 

(B) The ratio of the number of days, 

in the control period, starting with the 

date on which the CAIR NOX Ozone 

Season opt-in unit becomes a CAIR NOX

Ozone Season unit under § 96.304, 

divided by the total number of days in 

the control period; and 

(C) Rounded to the nearest whole 

allowance as appropriate.

§ 96.388 NOX allowance allocations to 

CAIR NOX Ozone Season opt-in units. 

(a) Timing requirements. (1) When the 

CAIR opt-in permit is issued under 

§ 96.384(e), the permitting authority will 

allocate CAIR NOX Ozone Season 

allowances to the CAIR NOX Ozone 

Season opt-in unit, and submit to the 

Administrator the allocation for the 

control period in which a CAIR NOX

Ozone Season opt-in unit enters the 

Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005 / Rules and Regulations 25405

CAIR NOX Ozone Season Trading 

Program under § 96.384(g), in 

accordance with paragraph (b) or (c) of 

this section. 

(2) By no later than July 31 of the 

control period in which a CAIR opt-in 

unit enters the CAIR NOX Ozone Season 

Trading Program under § 96.384(g) and 

July 31 of each year thereafter, the 

permitting authority will allocate CAIR 

NOX Ozone Season allowances to the 

CAIR NOX Ozone Season opt-in unit, 

and submit to the Administrator the 

allocation for the control period that 

includes such submission deadline and 

in which the unit is a CAIR NOX optin unit, in accordance with paragraph 

(b)or (c) of this section. 

(b) Calculation of allocation. For each 

control period for which a CAIR NOX

Ozone Season opt-in unit is to be 

allocated CAIR NOX Ozone Season 

allowances, the permitting authority 

will allocate in accordance with the 

following procedures: 

(1) The heat input (in mmBtu) used 

for calculating the CAIR NOX Ozone 

Season allowance allocation will be the 

lesser of: 

(i) The CAIR NOX Ozone Season optin unit’s baseline heat input determined 

under § 96.384(c); or 

(ii) The CAIR NOX Ozone Season optin unit’s heat input, as determined in 

accordance with subpart HHHH of this 

part, for the immediately prior control 

period, except when the allocation is 

being calculated for the control period 

in which the CAIR NOX Ozone Season 

opt-in unit enters the CAIR NOX Ozone 

Season Trading Program under 

§ 96.384(g).

(2) The NOX emission rate (in lb/

mmBtu) used for calculating CAIR NOX

Ozone Season allowance allocations 

will be the lesser of: 

(i) The CAIR NOX Ozone Season optin unit’s baseline NOX emissions rate (in 

lb/mmBtu) determined under 

§ 96.384(d) and multiplied by 70 

percent; or 

(ii) The most stringent State or 

Federal NOX emissions limitation 

applicable to the CAIR NOX Ozone 

Season opt-in unit at any time during 

the control period for which CAIR NOX

Ozone Season allowances are to be 

allocated. 

(3) The permitting authority will 

allocate CAIR NOX Ozone Season 

allowances to the CAIR NOX Ozone 

Season opt-in unit in an amount 

equaling the heat input under paragraph 

(b)(1) of this section, multiplied by the 

NOX emission rate under paragraph 

(b)(2) of this section, divided by 2,000 

lb/ton, and rounded to the nearest 

whole allowance as appropriate. 

(c) Notwithstanding paragraph (b) of 

this section and if the CAIR designated 

representative requests, and the 

permitting authority issues a CAIR optin permit providing for, allocation to a 

CAIR NOX Ozone Season opt-in unit of 

CAIR NOX Ozone Season allowances 

under this paragraph (subject to the 

conditions in §§ 96.384(h) and 

96.386(g)), the permitting authority will 

allocate to the CAIR NOX Ozone Season 

opt-in unit as follows: 

(1) For each control period in 2009 

through 2014 for which the CAIR NOX

Ozone Season opt-in unit is to be 

allocated CAIR NOX Ozone Season 

allowances, 

(i) The heat input (in mmBtu) used for 

calculating CAIR NOX Ozone Season 

allowance allocations will be 

determined as described in paragraph 

(b)(1) of this section. 

(ii) The NOX emission rate (in lb/

mmBtu) used for calculating CAIR NOX

Ozone Season allowance allocations 

will be the lesser of: 

(A) The CAIR NOX Ozone Season optin unit’s baseline NOX emissions rate (in 

lb/mmBtu) determined under 

§ 96.384(d); or 

(B) The most stringent State or 

Federal NOX emissions limitation 

applicable to the CAIR NOX Ozone 

Season opt-in unit at any time during 

the control period in which the CAIR 

NOX Ozone Season opt-in unit enters 

the CAIR NOX Ozone Season Trading 

Program under § 96.384(g). 

(iii) The permitting authority will 

allocate CAIR NOX Ozone Season 

allowances to the CAIR NOX Ozone 

Season opt-in unit in an amount 

equaling the heat input under paragraph 

(c)(1)(i) of this section, multiplied by the 

NOX emission rate under paragraph 

(c)(1)(ii) of this section, divided by 

2,000 lb/ton, and rounded to the nearest 

whole allowance as appropriate. 

(2) For each control period in 2015 

and thereafter for which the CAIR NOX

Ozone Season opt-in unit is to be 

allocated CAIR NOX Ozone Season 

allowances, 

(i) The heat input (in mmBtu) used for 

calculating the CAIR NOX Ozone Season 

allowance allocations will be 

determined as described in paragraph 

(b)(1) of this section. 

(ii) The NOX emission rate (in lb/

mmBtu) used for calculating the CAIR 

NOX Ozone Season allowance allocation 

will be the lesser of: 

(A) 0.15 lb/mmBtu; 

(B) The CAIR NOX Ozone Season optin unit’s baseline NOX emissions rate (in 

lb/mmBtu) determined under 

§ 96.384(d); or 

(C) The most stringent State or 

Federal NOX emissions limitation 

applicable to the CAIR NOX Ozone 

Season opt-in unit at any time during 

the control period for which CAIR NOX

Ozone Season allowances are to be 

allocated. 

(iii) The permitting authority will 

allocate CAIR NOX Ozone Season 

allowances to the CAIR NOX Ozone 

Season opt-in unit in an amount 

equaling the heat input under paragraph 

(c)(2)(i) of this section, multiplied by the 

NOX emission rate under paragraph 

(c)(2)(ii) of this section, divided by 

2,000 lb/ton, and rounded to the nearest 

whole allowance as appropriate. 

(d) Recordation. (1) The 

Administrator will record, in the 

compliance account of the source that 

includes the CAIR NOX Ozone Season 

opt-in unit, the CAIR NOX Ozone 

Season allowances allocated by the 

permitting authority to the CAIR NOX

Ozone Season opt-in unit under 

paragraph (a)(1) of this section. 

(2) By September 1, of the control 

period in which a CAIR opt-in unit 

enters the CAIR NOX Ozone Season 

Trading Program under § 96.384(g), and 

September 1 of each year thereafter, the 

Administrator will record, in the 

compliance account of the source that 

includes the CAIR NOX Ozone Season 

opt-in unit, the CAIR NOX Ozone 

Season allowances allocated by the 

permitting authority to the CAIR NOX

Ozone Season opt-in unit under 

paragraph (a)(2) of this section.

[FR Doc. 05–5723 Filed 5–11–05; 8:45 am] 

BILLING CODE 6560–50–P