[Federal Register Volume 70, Number 91 (Thursday, May 12, 2005)]
[Rules and Regulations]
[Pages 25162-25405]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 05-5723]



[[Page 25161]]

-----------------------------------------------------------------------

Part II





Environmental Protection Agency





-----------------------------------------------------------------------



40 CFR Parts 51, 72, et al.



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; Final Rule

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

[[Page 25162]]


-----------------------------------------------------------------------

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 [email protected]. 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 [email protected]. 
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 
[email protected]. 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 [email protected]. 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 [email protected]. 
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 [email protected]. 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 [email protected]. 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 
[email protected]. 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 [email protected].

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

[[Page 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-fuel-fired 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:

------------------------------------------------------------------------
                                                         Examples of
          Category               \1\ NAICS code          potentially
                                                     regulated entities
------------------------------------------------------------------------
Industry...................  221112 and others      Electric service
                                                     providers, boilers,
                                                     turbines, and
                                                     internal combustion
                                                     engines from a wide
                                                     range of
                                                     industries.
Federal government.........  22112\2\               Fossil fuel-fired
                                                     electric utility
                                                     steam generating
                                                     units owned by the
                                                     Federal government.
State/local/Tribal           22112\2\               Fossil fuel-fired
 government.                 921150                  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.
\2\ Federal, 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 Ozone-Related 
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

[[Page 25164]]

    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 Cost-Effective 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 Cost-Effective 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 State-by-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 State-by-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

[[Page 25165]]

    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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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 
2015\4\; 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

[[Page 25166]]

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.
---------------------------------------------------------------------------

    \2\ These 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).
    \3\ These 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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \5\ Benefit 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.
---------------------------------------------------------------------------

    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 ozone-related 
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\
---------------------------------------------------------------------------

    \6\ Technical 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.
---------------------------------------------------------------------------

    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

[[Page 25167]]

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).
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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

[[Page 25168]]

the environmental goals of the program.\10\
---------------------------------------------------------------------------

    \10\ Although 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.
---------------------------------------------------------------------------

    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-in-time 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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

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.

[[Page 25169]]

    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 ([mu]g/
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 [mu]g/
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. 
Short-term 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.
---------------------------------------------------------------------------

    \12\ EPA 454/K-04-001, April 2004.
---------------------------------------------------------------------------

    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

[[Page 25170]]

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

[[Page 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-by-source 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).

[[Page 25172]]

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\
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    * * * 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.
---------------------------------------------------------------------------

    \14\ Although 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.
---------------------------------------------------------------------------

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

[[Page 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 Cost-Effective 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 cost-effective 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 
cost-effective 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 SIP-required 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 then-present 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 cost-effective, 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

[[Page 25174]]

regulatory requirements. The EPA further required that the 
NOX SIP Call-required 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 cost-
effective 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\
---------------------------------------------------------------------------

    \15\ By 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).
---------------------------------------------------------------------------

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 [mu]g/m3, so that an upwind State with 
contributions to downwind nonattainment below this level would

[[Page 25175]]

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\
---------------------------------------------------------------------------

    \16\ The 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.
---------------------------------------------------------------------------

    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-of-control (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

[[Page 25176]]

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

[[Page 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 cost-
effective 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

[[Page 25178]]

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

[[Page 25179]]

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\
---------------------------------------------------------------------------

    \17\ More 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).
---------------------------------------------------------------------------

    (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

[[Page 25180]]

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.
---------------------------------------------------------------------------

    \18\ R. J. Klemm, et al., ``Daily Mortality and Air Pollution in 
Atlanta: Two Year of Data from ARIES'' (accepted, Inhalation 
Toxicology).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \19\ USEPA, National Center for Environmental Assessment, Air 
Quality Criteria for Particulate Matter, October 2004.
---------------------------------------------------------------------------

    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

[[Page 25181]]

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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

[[Page 25182]]

be expected to have very little effect on the sulfate concentration.
---------------------------------------------------------------------------

    \22\ Battye, W., V.P. Aneja, and P.A. Roelle, Evaluation and 
improvement of ammonia emissions inventories, Atmospheric 
Environment, 2003, 37: 3873-3883.
    \23\ As 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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \24\ EPA OAQPS CMAQ Evaluation for 2001 Docket  OAR-
2003-0053-1716.
---------------------------------------------------------------------------

    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 
long-range 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\
---------------------------------------------------------------------------

    \25\ NARSTO, Particulate Matter Science for Policy Makers--A 
NARSTO Assessment, February 2003.
---------------------------------------------------------------------------

    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.

[[Page 25183]]

    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 cost-effective 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 cost-effective 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\
---------------------------------------------------------------------------

    \26\ NARSTO, Particulate Matter Science for Policy Makers--A 
NARSTO Assessment, February 2003.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \27\ ``Regulatory Impact Analysis for the Final Clean Air 
Interstate Rule (March 2005).''
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \28\ Blanchard, 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.
    \29\ Blanchard 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.
---------------------------------------------------------------------------

    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

[[Page 25184]]

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.
---------------------------------------------------------------------------

    \30\ NARSTO, Particulate Matter Science for Policy Makers--A 
NARSTO Assessment, February 2003.
    \31\ Ibid.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \32\ For 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.
---------------------------------------------------------------------------

    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 [mu]g/
m\3\ to about 0.9 [mu]g/m\3\, 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.

[[Page 25185]]

B. What Is the Basis for EPA's Decision To Require Reductions in Upwind 
Emissions of NOX To Address Ozone-Related 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 man-made 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 large-scale 
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.
---------------------------------------------------------------------------

    \33\ Ozone Transport Assessment Group, OTAG Final Report, 1997.
    \34\ NARSTO, An Assessment of Tropospheric Ozone Pollution--A 
North American Perspective, July 2000.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \35\ National Research Council, Rethinking the Ozone Problem in 
Urban and Regional Air Pollution, 1991.
    \36\ NARSTO, An Assessment of Tropospheric Ozone Pollution--A 
North American Perspective, July 2000.
---------------------------------------------------------------------------

    Regional 8-hour ozone levels are highest in the Northeast and Mid-
Atlantic 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.
---------------------------------------------------------------------------

    \37\ U.S. EPA, Latest Findings on National Air Quality, August 
2003.
---------------------------------------------------------------------------

    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 mid-1990s. 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.
---------------------------------------------------------------------------

    \38\ Other 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.
---------------------------------------------------------------------------

    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 re-
evaluate 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

[[Page 25186]]

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 cost-effective 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-the-board 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.

[[Page 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 cost-effective'' 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

[[Page 25188]]

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 in-state 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 ([mu]g/m\3\), from Ohio to both 
Allegheny and Beaver counties in Pennsylvania.

[[Page 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 short-term 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 [mu]g/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 [mu]g/m3 (1% of the annual standard) for the 
significance criterion, but also presented analyses based on an 
alternative of 0.10 [mu]g/m3 and called for comment on this 
alternative as well as on ``the use of

[[Page 25190]]

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 cost-effective 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 [mu]g/m3. Some commenters favor the alternative 0.10 
[mu]g/m3 proposed by EPA, citing their agreement with EPA's 
rationale for 0.10 [mu]g/m3 while criticizing as arbitrary 
EPA's rationale for 0.15 [mu]g/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 [mu]g/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 [mu]g/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 
[mu]g/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 [mu]g/m3 annual PM2.5 standard would 
yield a significance threshold of 0.35 [mu]g/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 [mu]g/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 [mu]g/
m3, rounded to the nearest \1/10\ [mu]g, 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 [mu]g/
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 [mu]g/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 [mu]g/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\.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    Many commenters noted that EPA's proposed threshold of 0.15 [mu]g/
m3, or one percent of the annual PM2.5 NAAQS of 
15.0 [mu]g/m3, is lower than the single-source contribution 
thresholds

[[Page 25191]]

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\
---------------------------------------------------------------------------

    \40\ See 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 [mu]g/m3 (3.3 percent) of the 
150 [mu]g/m3 24-hour average PM10 NAAQS , or 1 
[mu]g/m3 (2 percent) of the annual average 
PM10 NAAQS.
    \41\ See 40 CFR 51.166(i)(5)(i). Proposed new sources or 
existing-source modifications that would contribute less than 10 
[mu]g/m3 (or 5.3%) of the 150 [mu]g/m3 
PM10 24-hour average NAAQS, estimated using on a 
screening model, may avoid the requirement of collecting and 
submitting ambient air quality data.
---------------------------------------------------------------------------

    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 [mu]g/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 [mu]g/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\
---------------------------------------------------------------------------

    \42\ This 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.
---------------------------------------------------------------------------

    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 [mu]g/m3 annual average 
PM2.5 contribution threshold. Of these states, only Arkansas 
would exceed the threshold of 0.15 [mu]g/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\
---------------------------------------------------------------------------

    \43\ Today'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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \44\ See the CAIR Air Quality Modeling TSD for description of 
the methodology used to calculate these metrics.
---------------------------------------------------------------------------

    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.

[[Page 25192]]



          Table III-1.--Ozone Contribution Factors and Metrics
------------------------------------------------------------------------
                                          Modeling technique
           Factor            -------------------------------------------
                                    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    Number and percent
                               of exceedances with   of exceedances with
                               contributions in      contributions in
                               various               various
                               concentration         concentration
                               ranges.               ranges.
Relative Amount of            Total contribution    Total average
 Contribution.                 relative to the       contribution to
                               total exceedance      exceedance hours in
                               ozone in the          the downwind area.
                               downwind area; and.
                              Population-weighted
                               total contribution
                               relative to the
                               total population-
                               weighted exceedance
                               ozone 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-apportionment-based 
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.

[[Page 25193]]

    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.
---------------------------------------------------------------------------

    \45\ As 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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \46\ This 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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \47\ Tables describing cost effectiveness of various control 
measures and programs are provided in section IV. These show that 
the cost per ton of non-power-sector control options that states 
might consider for attainment purposes typically is higher than for 
CAIR controls.
---------------------------------------------------------------------------

    Another reason for considering both attainment and maintenance 
needs at this time is EPA's expectation that most nonattainment areas 
will be able to

[[Page 25194]]

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\
---------------------------------------------------------------------------

    \48\ A 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.
---------------------------------------------------------------------------

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 [mu]g/m\3\. 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 [mu]g/m\3\) 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 
[mu]g/m\3\. 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 [mu]g/m\3\). 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

[[Page 25195]]

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.
---------------------------------------------------------------------------

    \49\ Attainment 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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \50\ We 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.
---------------------------------------------------------------------------

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

[[Page 25196]]

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 multi-
regional, 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.
---------------------------------------------------------------------------

    \51\ An 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.
---------------------------------------------------------------------------

    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

[[Page 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.
---------------------------------------------------------------------------

    \52\ The 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
---------------------------------------------------------------------------

    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\
------------------------------------------------------------------------
                                                               2015 and
                   Pollutant                     2010-2014      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 cost-effective 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

[[Page 25198]]

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 cost-effective 
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 cost-effectiveness 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) cost-
effectiveness 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 cost-effective 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 upper-bound 
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

[[Page 25199]]

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 cost-effective.* * *'' (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 cost-effective 
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 non-ozone 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.
---------------------------------------------------------------------------

    \53\ U.S. Environmental Protection Agency, Office of Air and 
Radiation, EPA's Clean Air Power Initiative, October 1996.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \54\ U.S. Environmental Protection Agency, Office of Air and 
Radiation, Analysis of Emission Reduction Options for the Electric 
Power Industry, March 1999.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \55\ EPA's Clear Skies Act analysis is on the web at: http://www.epa.gov/air/clearskies/technical.html.

---------------------------------------------------------------------------

[[Page 25200]]

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-of-
emissions-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-ambient-impact 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-
ambient-impact 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

[[Page 25201]]

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 
coal-fired 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 Cost-Effective 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 cost-effectiveness 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 multi-pollutant 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\
---------------------------------------------------------------------------

    \56\ The 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).
---------------------------------------------------------------------------

    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.

[[Page 25202]]



        Table IV-3.--Average Costs per Ton of Annual SO2 Controls
------------------------------------------------------------------------
                                                        Average cost per
                  SO2 control action                          ton
------------------------------------------------------------------------
Best Available Control Technology (BACT)                 \1\ $400-$2,100
 Determinations......................................
Nonroad Diesel Engines and Fuel......................           \2\ $800
Proposed Best Available Retrofit Technology (BART)     \3\ $2,600-$3,400
 for Electric Power Sector...........................
------------------------------------------------------------------------
\1\ These 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.
\3\ The 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
------------------------------------------------------------------------
                                                       Marginal cost per
                  SO2 control action                          ton
------------------------------------------------------------------------
New Hampshire Rule...................................           \1\ $600
WRAP Regional SO2 Trading Program....................  \2\ $1,100-$2,200
 
------------------------------------------------------------------------
\1\ The EPA IPM base case modeling August 2004, available in the docket.
  (1999$ per ton). We modeled New Hampshire's State Bill ENV-A2900,
  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 cost-effective 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\
---------------------------------------------------------------------------

    \57\ The 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.
---------------------------------------------------------------------------

    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

[[Page 25203]]

 
Sensitivity Analysis: Marginal Cost Using EIA Electric      800   1,200
 Growth and Natural Gas Prices........................
------------------------------------------------------------------------
\1\ The 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.
---------------------------------------------------------------------------

    \58\ The 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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \59\ EPA 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).
---------------------------------------------------------------------------

    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 cost-effectiveness 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

[[Page 25204]]

ranges from $700 to $800. The 2010 costs indicate that the interim 
phase CAIR reductions are also highly cost-effective.
(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:
[GRAPHIC] [TIFF OMITTED] TR12MY05.000

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 cost-effectiveness 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\
---------------------------------------------------------------------------

    \60\ EPA 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.

---------------------------------------------------------------------------

[[Page 25205]]

[GRAPHIC] [TIFF OMITTED] TR12MY05.001

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 two-phased 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. coal-fired 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

[[Page 25206]]

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.
---------------------------------------------------------------------------

    \61\ The 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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 cost-effective, 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

[[Page 25207]]

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 cost-effective 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 cost-effective, 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\
---------------------------------------------------------------------------

    \63\ The 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.
---------------------------------------------------------------------------

    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.

[[Page 25208]]

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 cost-effective 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\
---------------------------------------------------------------------------

    \64\ The 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).

        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-$2,300\2\
Revision of New Source Performance        $1,700 \3\
 Standards for NOX Emissions-EGUs.
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        $2,200 \3\
 Standards for NOX Emissions-Industrial
 Units.
On-board Diagnostics....................  $2,300 \2\
Texas NOX Emission Reduction Grants FY    $300-$12,700 \4\
 2002-2003.
Best Available Retrofit Technology        $800 \5\
 (BART) for Electric Power Sector.
------------------------------------------------------------------------
\1\ Control of Emissions of Air Pollution From Nonroad Diesel Engines
  and Fuel; Final Rule (69 FR 39131; June 29, 2004). The value in this
  table represents the long-term cost per ton of emissions reduced from
  the total fuel and engine program (cost per ton of emissions reduced
  in the year 2030). This value includes the cost for NOX plus NMHC
  reductions. 1999$ 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.

[[Page 25209]]

 
\3\ Proposed 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)
\5\ The 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
------------------------------------------------------------------------
                                                       Marginal cost per
                  NOX control action                          ton
------------------------------------------------------------------------
Texas Rules..........................................     $2,000-$19,600
                                                                    \1\
------------------------------------------------------------------------
\1\The EPA IPM base case modeling August 2004, available in the docket.
  1999$ 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\
------------------------------------------------------------------------
                                                        Average cost per
                   Source category                            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              5,000
 (ozone action days).................................
MWCOG Analysis: Mobile Source, Permit Right Turn on                1,200
 Red.................................................
MWCOG Analysis: Mobile Source, Employer Outreach.....              3,500
MWCOG Analysis: Mobile Source, Mass Marketing                      2,900
 Campaign............................................
MWCOG Analysis: Mobile Source, Transit Prioritization             8,500
------------------------------------------------------------------------
\1\ Washington 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).
---------------------------------------------------------------------------

    \65\ The 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.
---------------------------------------------------------------------------

    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

[[Page 25210]]

 
Marginal Cost--With Compliance Supplement Pool (CSP)..    1,300    1,600
Sensitivity Analysis: Marginal Cost Using Alternate       1,400   1,700
 Electricity Growth and Natural Gas Price Assumptions.
------------------------------------------------------------------------
\1\ The 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    $500
------------------------------------------------------------------------
\1\ The EPA IPM modeling 2004, available in the docket. 1999$ 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, ``Cost-Effective 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 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.\66\
---------------------------------------------------------------------------

    \66\ EPA 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.
---------------------------------------------------------------------------

BILLING CODE 6560-50-P

[[Page 25211]]

[GRAPHIC] [TIFF OMITTED] TR12MY05.002


[[Page 25212]]


(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   $1,800
Marginal Cost.........................................    2,400   3,000
------------------------------------------------------------------------
\1\ The EPA IPM modeling 2004, available in the docket. 1999$ 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 cost-effective.\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).
---------------------------------------------------------------------------

    \67\ For 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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \69\ Estimated 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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \70\ EPA 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.

---------------------------------------------------------------------------

[[Page 25213]]

[GRAPHIC] [TIFF OMITTED] TR12MY05.003

[GRAPHIC] [TIFF OMITTED] TR12MY05.004

B. What Other Sources Did EPA Consider When Determining Emission 
Reduction Requirements?

1. Potential Sources of Highly Cost-Effective 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 
cost-effective 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

[[Page 25214]]

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, non-EGU 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 cost-effective 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 cost-effective 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 non-EGU ``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 non-EGUs 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 non-EGUs 
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 non-EGUs.
    The recent economic circumstances faced by the manufacturing sector 
accentuates EPA's concerns about the lack of reliable emissions data 
and control information regarding non-EGUs. 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

[[Page 25215]]

EPA's concerns about moving forward to consider emission controls on 
non-EGUs 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 non-EGU 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 year-round 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 two-phased 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 cost-effective--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

[[Page 25216]]

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 single-phased 
schedule.\71\
---------------------------------------------------------------------------

    \71\ The NOX SIP Call Rule allowed approximately 3\1/
2\ years for implementation of all NOX Controls.
---------------------------------------------------------------------------

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 two-phased 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.

[[Page 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 3\3/4\ and 4\3/4\ 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 2\1/4\ and 3\1/4\ 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 
2\1/4\ and 3\1/4\ 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 2\1/4\- 
and 3\1/4\-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 2\1/4\ and 3\1/4\ 
years, respectively. The issues related to the availability of 
boilermakers and the ability of the plants requiring multiple-unit 
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 2\1/4\- and 3\1/4\-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

[[Page 25218]]

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.
---------------------------------------------------------------------------

    \72\ Reference: 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)
---------------------------------------------------------------------------

    The EPA also notes that most of the commenters' schedule estimates 
are consistent with the time periods available for completing the CAIR-
related 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.
---------------------------------------------------------------------------

    \73\ Summary of telephone calls with States to discuss landfill 
permit timing (docket no. OAR-2003-0053-1927).
---------------------------------------------------------------------------

    The Kentucky Department of Environmental Protection indicated that, 
based on their historical records, the average permit approval period 
was 3\1/2\ 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 4\3/
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 
3\3/4\ and 4\3/4\ 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.
---------------------------------------------------------------------------

    \74\ Reference: ``NERC, Generating Availability Data System: All 
MW Sizes--Coal-Fired Generation Report,'' http://www.nerc.com/filez/
gar.html, October 17, 2003.
---------------------------------------------------------------------------

(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

[[Page 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
----------------------------------------------------------------------------------------------------------------
                                                                    EIA
               Retrofit type                  EPA base case     projections     EIA projections and higher SCR
                                               assumptions          \1\                    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
----------------------------------------------------------------------------------------------------------------
\1\ The required control retrofits shown are based on using EIA projections for natural gas prices and
  electricity demand rates.
\2\ The 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
Commenter-suggested, boilermaker-year/MW \1\..........    0.269   0.343
------------------------------------------------------------------------
\1\ The 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.


[[Page 25220]]

    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.
---------------------------------------------------------------------------

    \75\ Reference: ``Email from Institute of Clean Air Companies,'' 
September 15, 2004 (See Appendix B, Boilermaker Labor Analysis and 
Installation Timing).
---------------------------------------------------------------------------

    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 gas-fired 
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\
---------------------------------------------------------------------------

    \76\ Reference: ``Annual Energy Outlook 2005 (Early Release), 
Tables A9 and 9,'' December 2004, http://www.eia.doe.gov/oiaf/aeo/index.html.
    \77\ TSD, ``Boilermaker Labor and Installation Timing 
Analysis,'' (Docket no. OAR-2003-0053-2092).
---------------------------------------------------------------------------

    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

[[Page 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 
commenter-suggested 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 3\1/4\ 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 1\1/4\ 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 1\1/4\-
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 2\1/4\ 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-to-back 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 3\1/2\ years. With the 
compliance deadline moved up by one year, the overall implementation 
period would be reduced from 4\3/4\ to 3\3/4\ years. For those plants 
subjected to a 3\1/2\-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 
4\3/4\-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 2\1/4\ 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 3\1/4\ 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 2\1/4\-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.

[[Page 25222]]

    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.
---------------------------------------------------------------------------

    \78\ The 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.
---------------------------------------------------------------------------

    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 2\1/4\-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 difficult-to-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 
harder-to-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

[[Page 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 cost-effective 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-and-trade 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 commenter-suggested 
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

[[Page 25224]]

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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

[[Page 25225]]

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.
---------------------------------------------------------------------------

    \80\ The 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.
---------------------------------------------------------------------------

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 
cost-effective 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 
cost-effective 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 cost-effective, 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.

[[Page 25226]]

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.
---------------------------------------------------------------------------

    \82\ For a discussion of the emission reduction requirements if 
States choose to control sources other than EGUs, see section VII of 
this preamble.
---------------------------------------------------------------------------

    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 cost-
effective levels.
---------------------------------------------------------------------------

    \83\ For a discussion of the emission reduction requirements if 
States choose to control sources other than EGUs, see section VII of 
this preamble.
---------------------------------------------------------------------------

    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\
----------------------------------------------------------------------------------------------------------------
                                                                               CAIR
                                                               Base case    emissions    Emissions    Emissions
                                                               emissions       caps      after CAIR    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

[[Page 25227]]

 
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.

     
---------------------------------------------------------------------------

    \84\ Table 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).
---------------------------------------------------------------------------

     
---------------------------------------------------------------------------

    \85\ Table 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-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
-----------------------------------------------------------------------------------------------------------------
                                                                               CAIR
                            Phase                              Base case    emissions    Emissions    Emissions
                                                               emissions       caps      after CAIR    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

[[Page 25228]]

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\
---------------------------------------------------------------------------

    \86\ For a discussion of the emission reduction requirements if 
States choose to control sources other than EGUs, see section VII of 
this preamble.

     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)
                                                             ---------------------------------------------------
                                                                               CAIR
                                                               Base case    emissions    Emissions    Emissions
                                                               emissions       caps      after CAIR    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       CAIR      Emissions    Emissions
                                                               emissions    emissions    after CAIR    reduced
                                                                               caps
-------------------------------------------------------------
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.
\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-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.
\2\ The 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.
\3\ The 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.
\5\ Over 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-by-State 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.
---------------------------------------------------------------------------

    \87\ Table 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.
---------------------------------------------------------------------------

    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

[[Page 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-by-State 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 ozone-season 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 cost-effective 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

[[Page 25230]]

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 coal- and 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 SO2    State SO2
                     State                         budget       budget
                                                  2010\*\      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
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

[[Page 25231]]

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 fuel-adjusted 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.
---------------------------------------------------------------------------

    \88\ States receiving larger budgets under this approach are 
generally expected to be those having to make the most reductions.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \89\ With 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.
---------------------------------------------------------------------------

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 NOX    State NOX
                     State                         budget       budget
                                                  2009\*\      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 non-EGUs (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

[[Page 25232]]

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]
----------------------------------------------------------------------------------------------------------------
                                                               Base case    2009 State                Compliance
                            State                                 2009      annual NOX   Reduction    supplement
                                                               emissions      budget    requirement    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 fuel-adjusted heat input basis. State budgets would 
be determined by multiplying State-level average historic ozone-season 
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.

[[Page 25233]]



   Table V-4.--Final Seasonal Electricity Generating Unit NOX Budgets
                                 [Tons]
------------------------------------------------------------------------
                                                 State NOX    State NOX
                     State                      budget 2009  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

[[Page 25234]]

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 gas-particle 
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\
---------------------------------------------------------------------------

    \90\ Even so, EPA acknowledges that REMSAD has certain 
limitations not found in CMAQ.
---------------------------------------------------------------------------

    Specifically, REMSAD simulates both gas phase and aerosol 
chemistry. The gas phase chemistry uses a reduced-form 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\
---------------------------------------------------------------------------

    \91\ Whitten, G. memorandum: Comparison of REMSAD Reduced 
Chemistry to Full CB-4. February 19, 2001.
---------------------------------------------------------------------------

    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 gas-particle 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

[[Page 25235]]

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 
EPA-recommended 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.
---------------------------------------------------------------------------

    \92\ The 2001 modeling platform is described in full in the NFR 
EITSD and NFR AQMTSD.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \93\ For 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.
---------------------------------------------------------------------------

    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, non-EPA 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:
---------------------------------------------------------------------------

    \94\ These 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.

--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
----------------------------------------------------------------------------------------------------------------
                                                                      CMAQ 2001                REMSAD 1996
                        Eastern U.S.                         ---------------------------------------------------
                                                                 FB(%)        FE(%)        FB(%)        FE(%)
----------------------------------------------------------------------------------------------------------------
Sulfate (Summer):
    STN.....................................................           14           44  ...........  ...........
    Improve.................................................           10           42          -20           51
    CASTNet.................................................            3           22          -21           59
Nitrate (Winter)
    STN.....................................................           15           73  ...........  ...........

[[Page 25236]]

 
    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 three-dimensional 
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.
---------------------------------------------------------------------------

    \95\ U.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.
    \96\ U.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.
---------------------------------------------------------------------------

    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

[[Page 25237]]

the regional concentration patterns of these pollutants.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \98\ Irwin, J. et al. ``Examination of model predictions at 
different horizontal grid resolutions.'' Submitted for Publication 
to Environmental Fluid Mechanics.
---------------------------------------------------------------------------

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 
future-year 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 non-EGU point 
and stationary-area sources were projected to represent a 2001 
inventory using State/county-specific and sector-specific growth rates. 
The on-road 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 category-specific 
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[reg] model, version 
5.5; and (3) forecasts by

[[Page 25238]]

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.
---------------------------------------------------------------------------

    \99\ Environ, Enhanced Meteorological Modeling and Performance 
Evaluation for Two Texas Ozone Episodes. August 2001.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \100\ Hogrefe, C. et al. ``Evaluating the performance of 
regional-scale photochemical modeling systems: Part 1-meteorological 
predictions.'' Atmospherics Environment, vol. 35 (2001), pp. 4159-
4174.
---------------------------------------------------------------------------

    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

[[Page 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-and-comment 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 un-
attributed 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 
[mu]g/m3 (as rounded up from 15.05 [mu]g/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

[[Page 25240]]

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
------------------------------------------------------------------------
                                                        CMAQ 2001
                 Eastern U.S.                  -------------------------
                                                   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.
---------------------------------------------------------------------------

    \101\ Procedures 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.
---------------------------------------------------------------------------

    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-to-year 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

[[Page 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 [mu]g/m\3\ 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 ([mu]g/m\3\) 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.

[[Page 25242]]

 
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 ([mu]g/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

[[Page 25243]]

 
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

[[Page 25244]]

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

[[Page 25245]]

 
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 State-by-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 [mu]g/m3 
and 0.15 [mu]g/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

[[Page 25246]]

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 zero-out 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.
---------------------------------------------------------------------------

    \102\ The six States are Kansas, Nebraska, North Dakota, 
Oklahoma, South Dakota, and Texas.
---------------------------------------------------------------------------

    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 [mu]g/m\3\ 
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

[[Page 25247]]

the NFR AQMTSD. We performed zero-out 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 State-by-State 
modeling, there are 23 States and the District of Columbia \103\ which 
contribute 0.2 [mu]g/m\3\ 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 [mu]g/m\3\ or more (i.e., the upwind State-to-downwind 
nonattainment ``linkages'').
---------------------------------------------------------------------------

    \103\ As 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-7.--Maximum Downwind PM2.5 Contribution ([mu]g/m\3\) for each
                              of 37 States
------------------------------------------------------------------------
                                                               Maximum
                       Upwind State                           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
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               Total                                    Downwind counties
states.........   linkages
----------------
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.

[[Page 25248]]

 
                            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.

[[Page 25249]]

 
                            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'').
---------------------------------------------------------------------------

    \104\ As 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-9.--Upwind State-to-Downwind Nonattainment County Significant ``Linkages'' for 8-hour Ozone.
----------------------------------------------------------------------------------------------------------------
 
----------------------------------------------------------------------------------------------------------------
Upwind               Total                                    Downwind counties
states.........   linkages
----------------
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.

[[Page 25250]]

 
                            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          Erie NY.
                                                                         Columbia.
                            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

[[Page 25251]]

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.
---------------------------------------------------------------------------

    \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.
    \106\ For the purposes of this discussion, we have calculated 
the percent reduction in total EGU emissions which includes units 
greater than and less than 25 MW.
---------------------------------------------------------------------------

    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 ([mu]g/m\3\) for the 2010 Base Case and CAIR and the Impact of CAIR
                                            Regional Controls in 2010
----------------------------------------------------------------------------------------------------------------
                                                                            2010 Base                 Impact of
                   State                                County                 case      2010 CAIR       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

[[Page 25252]]

 
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 ([mu]g/m3) for the 2015 Base Case and CAIR and the Impact of CAIR
                                            Regional Controls in 2015
----------------------------------------------------------------------------------------------------------------
                                                                            2015 Base                 Impact of
                   State                                County                 case      2015 CAIR       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

[[Page 25253]]

 
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 [mu]g/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 [mu]g/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 [mu]g/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 [mu]g/m3. After 
implementation of the regional controls, we project that 18 of the 28 
residual nonattainment counties in 2010 will be within 1.0 [mu]g/
m3 of the NAAQS and 12 counties will be within 0.5 [mu]g/
m3 of attainment.
    In 2015 we are projecting that PM2.5 in the 74 base case 
nonattainment counties will be reduced by 1.8 [mu]g/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 [mu]g/
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 [mu]g/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

[[Page 25254]]

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 [mu]g/m3 to 2.9 [mu]g/
m3 in these 18 counties. The average reduction across these 
18 residual nonattainment counties is 1.5 [mu]g/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
----------------------------------------------------------------------------------------------------------------
                                                                            2010 Base                 Impact of
                   State                                County                 case      2010 CAIR       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
----------------------------------------------------------------------------------------------------------------
                                                                            2015 Base                 Impact of
                   State                                County                 case      2015 CAIR       CAIR
----------------------------------------------------------------------------------------------------------------
Connecticut...............................  Fairfield Co.................         91.4         90.6         -0.8

[[Page 25255]]

 
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 
``better-than-BART'' analysis. The better-than-BART 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 CAIR \107\ 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.
---------------------------------------------------------------------------

    \107\ The CAIR scenario modeled for the visibility analysis 
included controls in Arkansas, Delaware, and New Jersey.
---------------------------------------------------------------------------

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

[[Page 25256]]

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 cost-effective 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

[[Page 25257]]

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 
EPA-administered 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 Sec. Sec.  96.101-96.176 
(for NOX) and Sec. Sec.  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 EPA-administered program. States for which the finding 
was for ozone only could choose to participate in only the EPA-
administered 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 EPA-administered 
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\
---------------------------------------------------------------------------

    \108\ Title 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.
---------------------------------------------------------------------------

    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 Sec.  96.102, Sec.  96.202, and 
Sec.  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

[[Page 25258]]

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 State-designed 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 cost-effective. 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 cost-
effectiveness 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 EPA-
administered cap and trade program, EPA is finalizing a specific 
mechanism that States must use.
i. States Participating in the EPA-Administered 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 EPA-Administered 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-for-1 
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

[[Page 25259]]

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 non-EGUs, the State must adopt and 
submit SIP revisions and supporting documentation designed to quantify 
the amount of reductions from the non-EGU sources and to assure that 
the controls will achieve that amount. Although EPA did not propose 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 non-EGU 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 non-EGU sources.
---------------------------------------------------------------------------

    \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 (Sec. Sec.  
51.123(e)(2) and 51.124(e)(2)).
---------------------------------------------------------------------------

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 
EPA-administered 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 non-EGUs. 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 non-EGUs. 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

[[Page 25260]]

case equals the amount of emissions reductions that can be claimed from 
application of the controls on non-EGUs. (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 non-EGUs, 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. Non-ozone 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 non-EGU reductions in 
accordance with the requirements discussed here, States must exclude 
credit for ineligible

[[Page 25261]]

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.)
---------------------------------------------------------------------------

    \110\ The 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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \111\ The 2010 modeling date is relevant for both SO2 
and NOX even though NOX requirements begin in 
2009. See Section IV for discussion.
---------------------------------------------------------------------------

    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 non-EGUs 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

[[Page 25262]]

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

[[Page 25263]]

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\
---------------------------------------------------------------------------

    \112\ See ``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.
---------------------------------------------------------------------------

    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 pre-2010 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, pre-2009 
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\
---------------------------------------------------------------------------

    \113\ By 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).
---------------------------------------------------------------------------

    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

[[Page 25264]]

warranted based upon subsequently-available 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

[[Page 25265]]

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.
---------------------------------------------------------------------------

    \114\ Under section 107(d), EPA is required to identify all 
areas of each State as falling into one of these three categories.
    \115\ The 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, 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).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \116\ As 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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \117\ The 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.
---------------------------------------------------------------------------

    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

[[Page 25266]]

such plan must meet the applicable requirements of section 
110(a)(2)(D).\118\
---------------------------------------------------------------------------

    \118\ For 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).
---------------------------------------------------------------------------

    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

[[Page 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

[[Page 25268]]

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

[[Page 25269]]

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\
---------------------------------------------------------------------------

    \119\ See, 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.
---------------------------------------------------------------------------

    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.

[[Page 25270]]

    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\
---------------------------------------------------------------------------

    \120\ Other 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).
---------------------------------------------------------------------------

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 pre-existing 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 Sec.  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

[[Page 25271]]

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 Sec.  51.1 
through 51.45 and an appendix, and to Sec.  51.122. We also proposed to 
add a new Sec.  51.125.
     In Sec.  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, Sec.  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 Sec.  51.125 would have been functionally 
parallel to Sec.  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.
---------------------------------------------------------------------------

    \121\ We 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, Sec.  51.122, and the new Sec.  
51.125 to avoid confusion. We are not finalizing this change in 
terminology in today's rule.
---------------------------------------------------------------------------

    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

[[Page 25272]]

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.

[[Page 25273]]

    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 ozone-season 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 EPA-administered 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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

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 ozone-season 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 ozone-season 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 EPA-
administered, 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

[[Page 25274]]

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 EPA-managed 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.
---------------------------------------------------------------------------

    \123\ Rhode 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.
---------------------------------------------------------------------------

     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 EPA-managed 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. Pre-2010 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.
---------------------------------------------------------------------------

    \124\ The 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.
---------------------------------------------------------------------------

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 ozone-season 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\
---------------------------------------------------------------------------

    \125\ Compliance with the title IV Acid Rain Program will be 
determined separately from CAIR compliance.
---------------------------------------------------------------------------

     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

[[Page 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 cost-effective 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 ozone-season 
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 EPA-managed 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 EPA-administered annual NOX CAIR cap and 
trade program is independent of ozone-season 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 multi-State 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 ozone-season 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 EPA-managed 
cap and trade programs, does not preclude a State from participating

[[Page 25276]]

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, non-cogeneration 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 cut-off 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 plant-wide 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 fuel-fired 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 fuel-fired 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.
---------------------------------------------------------------------------

    \126\ For example, certain cogeneration units and new units 25 
MW or less that burn only clean fuel are exempt from the Acid Rain 
Program.
---------------------------------------------------------------------------

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 non-
cogeneration 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

[[Page 25277]]

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 coal-fired 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 fuel-fired 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.
---------------------------------------------------------------------------

    \127\ The range included solid fuel-fired cogeneration units 
from 25 MW to 250 MW.
---------------------------------------------------------------------------

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,

[[Page 25278]]

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 electricity-consuming 
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 multi-State 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 EPA-administered 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-by-unit 
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,

[[Page 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 set-asides 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 input-based allocations for existing 
fossil units, with updating to take into account new generation on a 
modified-output 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 heat-input 
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

[[Page 25280]]

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 least-cost 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 less-efficient 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 fuel-type will create consistent and level incentives for 
efficient generation, rather than favoring new units with higher heat-
rates.
---------------------------------------------------------------------------

    \129\ Energy 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.
---------------------------------------------------------------------------

    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 coal-fired 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

[[Page 25281]]

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 set-aside 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.
---------------------------------------------------------------------------

    \130\ Some commenters stated that, if allocations were provided 
for non-emitting new generation, they also should be provided to all 
such generation, including nuclear units.
    \131\ For instance, would the addition of a single new wind 
turbine at a wind-farm constitute a ``new unit''?
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \132\ As noted earlier in this section, EPA is now considering 
new units to be those that went online after January 1, 2001 rather 
than 1998.
---------------------------------------------------------------------------

    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 on-line 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 set-aside, 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.
---------------------------------------------------------------------------

    \133\ With 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.
---------------------------------------------------------------------------

    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 output-based 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.
---------------------------------------------------------------------------

    \134\ Auctions could provide States with a non-distortionary 
source of revenue.
---------------------------------------------------------------------------

    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

[[Page 25282]]

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).
---------------------------------------------------------------------------

    \135\ 5 percent of the allowances would go to a new source set-
aside.
---------------------------------------------------------------------------

    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 multiple-round 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 EPA-administered 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

[[Page 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 one-
directional, 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

[[Page 25284]]

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 one-to-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

[[Page 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 ozone-season 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 ozone-season 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

[[Page 25286]]

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.
---------------------------------------------------------------------------

    \136\ The 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.
---------------------------------------------------------------------------

    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 year-round 
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 ozone-season 
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 cost-effective 
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

[[Page 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 opt-
in 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 opt-in 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 opt-in 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

[[Page 25288]]

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, non-CAIR 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 Ozone-Season 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

[[Page 25289]]

will benefit from complying with a single, regionwide cap and trade 
program.
Differences Between the CAIR Ozone-Season 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 
ozone-season 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 rounding-up 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 Sec.  96.106(f)(1) and (2) and Sec.  
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 Sec.  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 non-EGUs 
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.,

[[Page 25290]]

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 non-EGUs 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 non-EGUs 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

[[Page 25291]]

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\

[[Page 25292]]

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.
---------------------------------------------------------------------------

    \137\ The 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) 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).
---------------------------------------------------------------------------

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 Sec.  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-ton-of-emissions 
requirement in the Acid Rain Program as provided in Sec.  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 allowance-holding 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 Sec. Sec.  73.35(d) and 
77.4. See final Sec.  96.254(b)(1) adopted in today's action. Thus, the 
Acid Rain allowance-holding requirement continues as a separate 
requirement and reflects the one-allowance-per-ton-of-emissions 
authorization under section 402(3).\139\
---------------------------------------------------------------------------

    \138\ As 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.
    \139\ The 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 
Sec.  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.
---------------------------------------------------------------------------

    In contrast with the one-allowance-per-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\
---------------------------------------------------------------------------

    \140\ The 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-ton-of-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.
---------------------------------------------------------------------------

    Once a title IV allowance is used to meet the more stringent 
allowance-holding 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

[[Page 25293]]

Rain Program.\141\ The commenters claim that such a reduction in the 
8.95 million ton cap is contrary to title IV.
---------------------------------------------------------------------------

    \141\ Similarly, 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.
---------------------------------------------------------------------------

    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 one-allowance-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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \143\ While 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.
---------------------------------------------------------------------------

    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

[[Page 25294]]

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.
---------------------------------------------------------------------------

    \144\ The 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).
    \145\ The 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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \146\ See 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).
---------------------------------------------------------------------------

    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.,

[[Page 25295]]

incentives for innovation) for avoidance or reduction of SO2 
emissions.\147\
---------------------------------------------------------------------------

    \147\ While 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.
---------------------------------------------------------------------------

    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'').
---------------------------------------------------------------------------

    \148\ The 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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \149\ While 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.
---------------------------------------------------------------------------

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

[[Page 25296]]

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 Sec. Sec.  51.124(p) and 96.254(b)) and 
in the final rules adopted by today's action (i.e., in final Sec. Sec.  
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 Sec.  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 Sec.  96.254(b) or otherwise retired 
in accordance with Sec.  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 unit-by-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-by-source compliance 
with the allowance-holding requirement. As explained in detail in the 
SNPR (69 FR 32698-32701), EPA finds that: Title IV is ambiguous with 
regard to whether unit-by-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-by-unit 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-by-unit orientation in the non-allowance-
holding 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 unit-level 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 source-level 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 source-level 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 allowance-holding 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-by-source, 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 allowance-holding 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 unit-level 
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

[[Page 25297]]

compliance with the allowance-holding requirements are analogous under 
unit-by-unit and source-by-source compliance, except that, under 
source-by-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-by-unit 
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 market-price 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 allowance-holding 
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 over-draft 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 source-level 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 
source-level 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 source-level 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 in-depth 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 source-level 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\
---------------------------------------------------------------------------

    \150\ This 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).
---------------------------------------------------------------------------

    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, source-level compliance will: Make it 
harder to determine which unit caused excess emissions; make the 
existing Acid Rain

[[Page 25298]]

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-allowance-holding 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 
unit-level 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-by-source 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 
source-level 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-by-unit allocations (set forth in 
Table 2 of Sec.  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 allowance-holding 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 Sec.  72.2 in June 2002 (67 FR 
40394, 40420; June 12, 2002). The original definition in Sec.  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 Sec.  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).

[[Page 25299]]

    Other proposed Acid Rain Program rule revisions on which EPA 
received adverse comment are the removal of Sec.  73.32 (prescribing 
the contents of an allowance account) and Sec.  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 out-of-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 
Sec.  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 Sec.  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 Sec.  
73.32, EPA is removing Sec.  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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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 Sec.  
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 source-specific 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 BART-alternative program. The DC Circuit in CEED held 
otherwise, stating: ``EPA cannot under Sec.  309 require states to 
exceed invalid emission reductions (or, to put it more exactly, limit 
them to a Sec.  309 alternative defined by an unlawful methodology).'' 
(Id. at 14).
---------------------------------------------------------------------------

    \152\ Arizona, California, Colorado, Oregon, Idaho, Nevada, New 
Mexico, Utah, and Wyoming.
    \153\ The 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.
    \154\ The methodology is prescribed in 40 CFR 51.308(e)(2) and 
incorporated into Sec.  309 by reference at 40 CFR 51.309(f).
---------------------------------------------------------------------------

    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 BART-alternative. The first principle validates EPA's 
proposal to allow the CAIR to substitute for BART. The second

[[Page 25300]]

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 BART-alternative 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:
---------------------------------------------------------------------------

    \155\ The 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.

    (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 Sec.  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

[[Page 25301]]

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 BART-eligible 
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.
---------------------------------------------------------------------------

    \156\ CAIR 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.
---------------------------------------------------------------------------

    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 non-EGUs--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\
---------------------------------------------------------------------------

    \157\ See ``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.
    \158\ The 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.
---------------------------------------------------------------------------

    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

[[Page 25302]]

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).
---------------------------------------------------------------------------

    \159\ The 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.
---------------------------------------------------------------------------

    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 source-specific 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 two-pronged 
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

[[Page 25303]]

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 BART-reductions 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\
---------------------------------------------------------------------------

    \160\ Because 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.
    \161\ See ``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.
---------------------------------------------------------------------------

    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-than-BART 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.
---------------------------------------------------------------------------

    \162\ Some Class I areas do not have IMPROVE monitors and are 
represented by nearby IMPROVE sites.
    \163\ This 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.
    \164\ There 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.
---------------------------------------------------------------------------

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 
better-than-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. Twenty-nine 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 better-than-BART proposed two-pronged test 
are summarized below.
---------------------------------------------------------------------------

    \165\ ``Demonstration that CAIR Satisfies the `Better-than-BART' 
Test As Proposed in the Guidelines for Making BART Determinations,'' 
March, 2005.
---------------------------------------------------------------------------

    The updated visibility analysis reaffirms that under the proposed 
two-pronged 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\
---------------------------------------------------------------------------

    \166\ See Better-than-BART TSD for results at each Class I Area.
---------------------------------------------------------------------------

    With respect to the greater-average-improvement 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

[[Page 25304]]

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)
----------------------------------------------------------------------------------------------------------------
                                                                 CAIR + BART in West         Nationwide BART
                        Class I Areas                        ---------------------------------------------------
                                                               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-than-BART 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 BART-alternative programs are finalized.
---------------------------------------------------------------------------

    \167\ Eastern 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.
---------------------------------------------------------------------------

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.

[[Page 25305]]

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.
---------------------------------------------------------------------------

    \168\ See 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).
---------------------------------------------------------------------------

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 cost-effective 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.

[[Page 25306]]

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/epa-ipm.
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 
PM- and 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 ozone-related 
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 
short-term 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 meta-
analyses 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.
---------------------------------------------------------------------------

    \169\ Thurston, G.D. and K. Ito. 2001. ``Epidemiological Studies 
of Acute Ozone Exposures and Mortality''. J. Expo Anal Environ 
Epidemiology 11 (4) :286-294.
    \170\ Bell, 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.
---------------------------------------------------------------------------

    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

[[Page 25307]]

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.
---------------------------------------------------------------------------

    \171\ Pope, 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.
    \172\ Woodruff, 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.
    \173\ U.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.

Table X-1.--Estimated Annual Reductions in Incidence of Health Effects a
------------------------------------------------------------------------
                                            2010 annual     2015 annual
              Health Effect                  incidence       incidence
                                             reduction       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              6,900           8,700
 over)..................................
Non-fatal myocardial infarction (adult,           17,000          22,000
 age 18 and over).......................
Hospital admissions--respiratory (all              4,300           5,500
 ages) d................................
Hospital admissions--cardiovascular                3,800           5,000
 (adults, age >18) e....................
Emergency room visits for asthma (age 18          10,000          13,000
 years and younger).....................
Acute bronchitis, (children, age 8-12)..          16,000          19,000
Lower respiratory symptoms (children,            190,000         230,000
 age 7-14)..............................
Upper respiratory symptoms (asthmatic            150,000         180,000
 children, age 9-18)....................
Asthma exacerbation (asthmatic children,         240,000         290,000
 age 6-18)..............................
Work Loss Days..........................       1,400,000       1,700,000
Minor restricted activity days (adults         8,100,000       9,900,000
 age 18-65).............................
-----------------------------------------
                         Ozone-Related endpoints
------------------------------------------------------------------------
Hospital admissions--respiratory causes              610           1,700
 (adult, 65 and older) f................
Hospital admissions--respiratory causes              380           1,100
 (children, under 2)....................
Emergency room visit for asthma (all                 100             280
 ages)..................................
Minor restricted activity days (adults,          280,000         690,000
 age 18-65).............................
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.
b Premature mortality benefits associated with ozone are not analyzed in
  the primary analysis.
c Adult 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
------------------------------------------------------------------------
                                                    2010         2015
                                                 estimated    estimated
         Health effect             Pollutant      value of     value of
                                                 reductions   reductions
------------------------------------------------------------------------
Premature mortality c, d
    Adult >30 years             ..............  ...........  ...........
        3 percent discount      PM2.5.........      $67,300      $92,800
         rate.
        7 percent discount      ..............       56,600       78,100
         rate.
    Child <1 year.............  ..............          168          222
Chronic bronchitis (adults, 26  PM2.5.........        2,520        3,340
 and over).
Non-fatal acute myocardial
 infarctions
    3 percent discount rate...  PM2.5.........        1,420        1,850
    7 percent discount rate...  ..............        1,370        1,790

[[Page 25308]]

 
Hospital admissions for         PM2.5, O3.....         45.2         78.9
 respiratory causes.
Hospital admissions for         PM2.5.........         80.7          105
 cardiovascular causes.
Emergency room visits for       PM2.5, O3.....         2.84         3.56
 asthma.
Acute bronchitis (children,     PM2.5.........         5.63         7.06
 age 8-12).
Lower respiratory symptoms      PM2.5.........         2.98         3.74
 (children, age 7-14).
Upper respiratory symptoms      PM2.5.........         3.80         4.77
 (asthma, age 9-11).
Asthma exacerbations..........  PM2.5.........         10.3         12.7
Work loss days................  PM2.5,........          180          219
Minor restricted activity days  PM2.5, O3.....          422          543
 (MRADs).
School absence days...........  O3............         12.9         36.4
Worker productivity (outdoor    O3............         7.66         19.9
 workers, age 18-65).
Recreational visibility, 81     PM2.5.........        1,140        1,780
 Class I areas.
                                               --------------
Monetized Total e
    Base estimate               ..............  ...........  ...........
        3 percent discount      PM2.5, O3.....   73,300 + B  101,000 + B
         rate.
        7 percent discount      ..............   62,600 + B  86,300 + B
         rate.
------------------------------------------------------------------------
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).
c Valuation 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\
d Adult mortality based upon studies by Pope et al. 2002. Infant
  mortality based upon studies by Woodruff, Grillo, and Schoendorf,
  1997.
e B 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 cost-effectiveness 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)].

[[Page 25309]]

    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\
---------------------------------------------------------------------------

    \174\ United 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.

 Table X-3.--Summary of Annual Benefits, Costs, and Net Benefits of the
                       Clean Air Interstate Rule a
                       [Billions of 1999 dollars]
------------------------------------------------------------------------
                                  2010 (Billions of    2015 (Billions of
          Description               1999 dollars)        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
------------------------------------------------------------------------
\a\ All 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.
\c\ As 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.
\e\ Valuation 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\
---------------------------------------------------------------------------

    \175\ Mrozek, 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 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

[[Page 25310]]

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.
---------------------------------------------------------------------------

    \176\ U.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.

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 mid-Appalachian 
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

[[Page 25311]]

comparison to the estimated premature mortality benefits estimates).
---------------------------------------------------------------------------

    \177\ Banzhaf, Spencer, Dallas Burtraw, David Evans, and Alan 
Krupnick. ``Valuation of Natural Resource Improvements in the 
Adirondacks,'' Resources for the Future (RFF), September 2004.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \178\ Sweeney, Jeff. ``EPA's Chesapeake Bay Program Air 
Strategy.'' October 26, 2004.
---------------------------------------------------------------------------

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

[[Page 25312]]

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 climate-related 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
------------------------------------------------------------------------
                                    Effects not included in primary
      Pollutant/effects                  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           Commercial forests due to acidic sulfate
 Deposition Welfare.            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.
\b\ Premature 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.
\d\ While 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.
\f\ These are potential effects as the literature is insufficient.


[[Page 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. Sec.  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-for-profit 
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
------------------------------------------------------------------------
                                    \1\ NAICS   Examples of potentially
             Category                  code        regulated entities
------------------------------------------------------------------------
Industry..........................     221112  Fossil fuel-fired
                                                electric utility steam
                                                generating units.
Federal government................        \2\  Fossil fuel-fired
                                       221112   electric utility steam
                                                generating units owned
                                                by the Federal
                                                government.
State/local/Tribal government.....        \2\  Fossil fuel-fired
                                       221112   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.
\2\ Federal, 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

[[Page 25314]]

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 rate-payers. 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-and-
control 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

[[Page 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

[[Page 25316]]

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 cost-effective for the 
regulated community; it is also intended to encourage innovation in 
analytical technology and improved data quality. At this time, EPA is 
not 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)
---------------------------------------------------------------------------

    \179\ U.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.
---------------------------------------------------------------------------

    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 sub-populations 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

[[Page 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.

0
Title 40, chapter I, of the Code of Federal Regulations is amended as 
follows:

PART 51--[AMENDED]

0
1. The authority citation for Part 51 continues to read as follows:

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


Sec.  51.121  [Amended]

0
2. Section 51.121 is amended by adding a new paragraph (r) to read as 
follows:


Sec.  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 Sec.  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.

0
3. Revise Sec.  51.122 of subpart G to read as follows:


Sec.  51.122  Emissions reporting requirements for SIP revisions 
relating to budgets for NOX emissions.

    (a) For its transport SIP revision under Sec.  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 Sec.  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 
Sec.  51.121(g).
    (ii) If sources report NOX emissions data to EPA 
annually pursuant to a trading program approved under Sec.  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 Sec.  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.

[[Page 25318]]

    (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 
[email protected]. 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 
Sec.  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 self-propelled 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.

[[Page 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 non-mobile 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.

0
4. Part 51 is amended by adding Sec.  51.123 to Subpart G to read as 
follows:


Sec.  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

[[Page 25320]]

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:

------------------------------------------------------------------------
                                                          Annual EGU NOX
                                          Annual EGU NOX    budget for
                  State                     budget for       2015 and
                                             2009-2014      thereafter
                                              (tons)          (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 interstaterule).
    (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:

------------------------------------------------------------------------
                                                            Compliance
                          State                             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
------------------------------------------------------------------------

    (iii) The SIP revision may provide for the distribution of credits 
from the compliance supplement pool to sources

[[Page 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-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

[[Page 25322]]

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 Sec.  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 Sec.  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 Sec.  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 non-EGUs 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.

[[Page 25323]]

    (l)(1) A SIP revision may assign legal authority to local agencies 
in accordance with Sec.  51.232.
    (2) Each SIP revision must comply with Sec.  51.240 (regarding 
general plan requirements).
    (m) Each SIP revision must comply with Sec.  51.280 (regarding 
resources).
    (n) Each SIP revision must provide for State compliance with the 
reporting requirements in Sec.  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 opt-in units 
under Sec.  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 opt-in units 
under Sec.  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 Sec.  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 Non-EGU 
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:

------------------------------------------------------------------------
                                                           Ozone season
                                           Ozone season   EGU NOX budget
                  State                   EGU NOX budget   for 2015 and
                                           for 2009-2014    thereafter
                                              (tons)          (tons)
------------------------------------------------------------------------
Alabama.................................          32,182          26,818

[[Page 25324]]

 
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

[[Page 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-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 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 Non-EGU 
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 Sec.  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 Sec.  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 Sec.  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 non-EGUs 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;

[[Page 25326]]

    (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 Sec.  51.232.
    (2) Each SIP revision must comply with Sec.  51.240 (regarding 
general plan requirements).
    (y) Each SIP revision must comply with Sec.  51.280 (regarding 
resources).
    (z) Each SIP revision must provide for State compliance with the 
reporting requirements in Sec.  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 Sec.  
96.304 to include all non-EGUs subject to the State's emissions trading 
program approved under Sec.  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 Sec.  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 Sec.  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 non-EGUs that the applicability provisions in 
Sec.  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 Sec.  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 non-EGUs shall 
not be subject to the requirements of the State's SIP meeting the 
requirements of Sec.  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 non-EGUs through an emissions trading program adopted in 
regulations that differ substantively from subparts AAAA through IIII 
of part 96 of this

[[Page 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 Sec.  51.121.
    (i) Rhode Island must expand the applicability provisions in Sec.  
96.304 to include all non-EGUs subject to Rhode Island's emissions 
trading program approved under Sec.  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 Sec.  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 Sec.  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 Sec.  51.121 is determined by the Administrator to meet the 
requirements of Sec.  51.121, such SIP shall be deemed to continue to 
meet the requirements of Sec.  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, fossil-fuel-fired boiler or stationary, fossil-fuel-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

[[Page 25328]]

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 Sec.  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 Sec.  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-fuel-fired 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 on-site emission controls).
    Useful thermal energy means, with regard to a cogeneration unit, 
thermal energy that is:
    (1) Made available to an industrial or commercial process, 
excluding any heat contained in condensate return or makeup water;
    (2) Used in a heat application (e.g., space heating or domestic hot 
water heating); or
    (3) Used in a space cooling application (i.e., thermal energy used 
by an absorption chiller).
    Utility power distribution system means the portion of an 
electricity grid owned or operated by a 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 Sec.  
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 opt-in 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 Sec.  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 Sec.  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.

0
5. Part 51 is amended by adding Sec.  51.124 to Subpart G to read as 
follows:


Sec.  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

[[Page 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:

----------------------------------------------------------------------------------------------------------------
                                                                         Annual EGU SO2        Annual EGU SO2
                                State                                 budget for 2010-2014   budget for 2015 and
                                                                             (tons)           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
----------------------------------------------------------------------------------------------------------------


[[Page 25330]]

    (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,

[[Page 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 Sec.  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 Sec.  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 Sec.  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 non-EGUs 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 Sec.  51.232.
    (2) Each SIP revision must comply with Sec.  51.240 (regarding 
general plan requirements).
    (m) Each SIP revision must comply with Sec.  51.280 (regarding 
resources).
    (n) Each SIP revision must provide for State compliance with the 
reporting requirements in Sec.  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 Sec.  96.288(b) of this chapter and the provisions of 
subpart III of this part applicable only to CAIR SO2 opt-in 
units under Sec.  96.288(b).
    (iii) The State may decline to adopt the CAIR SO2 opt-in 
provisions of Sec.  96.288(c) of this chapter and the provisions of 
subpart II of this part applicable only to CAIR SO2 opt-in 
units under Sec.  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 Sec.  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

[[Page 25332]]

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 multi-State sulfur dioxide and nitrogen 
oxides air pollution control and emissions reduction program 
established by the Administrator under title IV of the CAA and parts 72 
through 78 of this chapter.
    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, fossil-fuel-fired boiler or stationary, fossil-fuel-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

[[Page 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-fuel-fired 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 on-site emission controls).
    Useful thermal energy means, with regard to a cogeneration unit, 
thermal energy that is:
    (1) Made available to an industrial or commercial process, 
excluding any heat contained in condensate return or makeup water;
    (2) Used in a heat application (e.g., space heating or domestic hot 
water heating); or
    (3) Used in a space cooling application (i.e., thermal energy used 
by an absorption chiller).
    Utility power distribution system means the portion of an 
electricity grid owned or operated by a utility and dedicated to 
delivering electricity to customers.

0
6. Part 51 is amended by adding Sec.  51.125 to Subpart G to read as 
follows:


Sec.  51.125  Emissions reporting requirements for SIP revisions 
relating to budgets for SO2 and NOX emissions.

    (a) For its transport SIP revision under Sec.  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 Sec. Sec.  
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 Sec.  51.123.
    (iii) If sources report SO2 and NOX emissions 
data to EPA in a given year pursuant to a trading program approved 
under Sec.  51.123(o) or Sec.  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 Sec.  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

0
1. The authority citation for part 72 continues to read as follows:

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


Sec.  72.2  [Amended]

0
2. Section 72.2 is amended by:
0
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

[[Page 25334]]

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'';
0
b. Amend the definition of ``Advance allowance'' by replacing the word 
``unit's'' with the word ``source'';
0
c. Amend the definition of ``Allocate or allocation'' by replacing the 
words ``unit account'' with the words ``compliance account'';
0
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'';
0
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'';
0
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'';
0
g. Amend the definition of ``Compliance use date'' by replacing the 
word ``unit's'' with the word ``source's'';
0
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'';
0
i. Amend the definition of ``General account'' by replacing the words 
``unit account'' with the words ``compliance account'';
0
j. Amend the definition of ``Offset Plan'' by replacing the word 
``unit'' with the word ``source'';
0
k. Amend the definition of ``Recordation, record, or recorded'' by 
removing the words ``or subaccount'';
0
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 Sec.  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.''
0
m. Amend the definition of ``Spot allowance'' by replacing the word 
``unit's'' with the word ``source's''; and
0
n. Revise the definition of ``Cogeneration unit'';
0
o. Add a new definition of ``Compliance account''; and
0
p. Remove the definitions of ``Compliance subaccount'', ``Current year 
subaccount'', ``Direct Sale Subaccount'', ``Future year subaccount'', 
and ``Unit account''.


Sec.  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 Sec.  73.31(a) or (b) of this 
chapter or Sec.  74.40(a) of this chapter for an affected source and 
for each affected unit at the source.
* * * * *


Sec.  72.7  [Amended]

0
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).


Sec.  72.9  [Amended]

0
4. Section 72.9 is amended by:
0
a. In paragraph (b)(2), replace the word ``unit'' with the words 
``source or unit, as appropriate,'';
0
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'';
0
c. In paragraphs (e)(1) and (e)(2) introductory text, replace the words 
``an affected unit'' with the words ``an affected source'';
0
d. In paragraph (g)(6), remove the second sentence; and
0
e. In paragraph (h)(2), replace the word ``unit'' with the word 
``source'' wherever it appears.


Sec.  72.21  [Amended]

0
5. Section 72.21 is amended by:
0
a. In paragraph (b)(1), remove the word ``affected'' wherever it 
appears; and
0
b. In paragraph (e)(2), replace the words ``unit account'' with the 
words ``compliance account''.


Sec.  72.24  [Amended]

0
6. Section 72.24 is amended by removing and reserving paragraphs 
(a)(5), (a)(7), and (a)(10).


Sec.  72.40  [Amended]

0
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 Sec.  73.35(b)(3),''; and replace the words ``from 
the unit'' with the words ``from the affected units at the source''.


Sec.  72.72  [Amended]

0
9. Section 72.72 is amended by:
0
a. In paragraph (a)(1), add the words ``or affected source'' after the 
words ``affected unit'';
0
b. In paragraph (a)(2), add the words ``or an affected source's'' after 
the words ``affected unit's''; and
0
c. In paragraph (a)(3), add the words ``or affected source'' after the 
words ``affected unit'' whenever they appear.


Sec.  72.73  [Amended]

0
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''.


Sec.  72.90  [Amended]

0
11. Section 72.90 is amended by, in paragraph (a), add, after the words 
``each calendar year'', the words ``during 1995 through 2005''.


Sec.  72.95  [Amended]

0
12. Section 72.95 is amended by:
0
a. In the introductory text, replace the words ``an affected unit's 
compliance subaccount'' with the words ``an affected source's 
compliance account''; and
0
b. In paragraph (a), replace the words ``by the unit'' with the words 
``by the affected units at the source''.


Sec.  72.96  [Amended]

0
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

0
1. The authority citation for part 73 continues to read as follows:

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

[[Page 25335]]

Sec.  73.10  [Amended]

0
2. Section 73.10 is amended by:
0
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
0
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''.


Sec.  73.27  [Amended]

0
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''.


Sec.  73.30  [Amended]

0
4. Section 73.30 is amended by:
0
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
0
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''.


Sec.  73.31  [Amended]

0
5. Section 73.31 is amended by:
0
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'';
0
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
0
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.''.


Sec.  73.32  [Removed and Reserved]

0
6. Section 73.32 is removed and reserved.


Sec.  73.33  [Amended]

0
7. Section 73.33 is amended by removing and reserving paragraphs (b) 
and (c).


Sec.  73.34  [Amended]

0
8. Section 73.34 is amended by:
0
a. Revise paragraphs (a) and (b) to read as set forth below;
0
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''.


Sec.  73.34  Recordation in accounts.

    (a) After a compliance account is established under Sec.  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 Sec.  73.50. In 1996 and each year 
thereafter, after Administrator has completed the deductions pursuant 
to Sec.  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 Sec.  73.50.
    (b) After a general account is established under Sec.  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 Sec.  73.50. In 
1996 and each year thereafter, after the Administrator has completed 
the deductions pursuant to Sec.  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 Sec.  73.50.
* * * * *


Sec.  73.35  [Amended]

0
9. Section 73.35 is amended by:
0
a. In paragraph (a) introductory text and paragraph (a)(1), replace the 
words ``unit's'' with the word ``source's'';
0
b. In paragraph (a)(2), replace the word ``Such'' with the word 
``The'';
0
c. In paragraph (a)(2)(i), replace the words ``the unit's compliance 
subaccount'' with the words ``the source's compliance account'';
0
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'';
0
e. Remove paragraph (a)(2)(iii);
0
f. Add a new paragraph (a)(3);
0
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'';
0
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'';
0
i. Remove paragraph (b)(3);
0
j. Revise paragraph (c)(1) to read as set forth below;
0
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'';
0
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
0
m. Remove paragraph (e).


Sec.  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 Sec.  51.124(o) of this chapter or otherwise permanently 
retired in accordance with Sec.  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

[[Page 25336]]

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.
* * * * *


Sec.  73.36  [Amended]

0
10. Section 73.36 is amended by:
0
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
0
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''.

0
11. Section 73.37 is revised to read as follows:


Sec.  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.


Sec.  73.38  [Amended]

0
12. Section 73.38 is amended by:
0
a. In paragraph (a), replace the words ``delete the general account 
from the Allowance Tracking System.'' with the words ``close the 
general account.''; and
0
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.


Sec.  73.50  [Amended]

0
13. Section 73.50 is amended by:
0
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'';
0
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'';
0
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
0
d. Remove paragraph (b)(3).


Sec.  73.51  [Removed and Reserved]

0
14. Section 73.51 is removed and reserved.


Sec.  73.52  [Amended]

0
15. Section 73.52 is amended by:
0
a. In paragraph (a) introductory text, remove the words ``Sec.  73.50, 
Sec.  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'';
0
b. Revise paragraphs (a)(1), (a)(2) and (a)(3);
0
c. Remove paragraph (a)(4);
0
d. Revise paragraph (b); and
0
e. Add a new paragraph (c) to read as follows:


Sec.  73.52  EPA recordation.

    (a) * * *
    (1) The transfer is correctly submitted under Sec.  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 Sec.  73.50(b)(1)(ii) are subject to the limitation on 
transfer imposed pursuant to Sec.  72.44(h)(1)(i) of this chapter, 
Sec.  74.42 of this chapter, or Sec.  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 Sec.  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.


Sec.  73.70  [Amended]

0
16. Section 73.70 is amended by:
0
a. In paragraph (e), remove the last two sentences.
0
b. In paragraph (f), replace the words ``the subaccount'' by the words 
``the Allowance Tracking System account''; and
0
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

0
1. The authority citation for part 74 continues to read as follows:

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


Sec.  74.4  [Amended]

0
2. Section 74.4 is amended by:
0
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
0
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.


Sec.  74.18  [Amended]

0
3. Section 74.18 is amended in paragraph (d) by removing the last 
sentence.


Sec.  74.40  [Amended]

0
4. Section 74.40 is amended by:
0
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 Sec.  74.4(c), a different designated representative than 
the designated representative for the source)'', and remove the last 
sentence.
0
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 Sec.  74.4(c), a different 
designated representative than the designated representative for the 
source)''.

0
5. Section 74.42 is revised to read as follows:


Sec.  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

[[Page 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.


Sec.  74.43  [Amended]

0
6. Section 74.43 is amended by:
0
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'';
0
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
0
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''.


Sec.  74.44  [Amended]

0
7. Section 74.44 is amended by:
0
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'';
0
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
0
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''.


Sec.  74.46  [Amended]

0
8. Section 74.46 is amended by removing and reserving paragraph (b)(2).


Sec.  74.47  [Amended]

0
9. Section 74.47 is amended by:
0
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'';
0
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'';
0
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'';
0
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'';
0
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'';
0
f. In paragraph (d)(1)(ii)(D), replace the words ``(ATS) for each'' 
with the words ``of each source that includes a'';
0
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'';
0
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
0
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''.


Sec.  74.49  [Amended]

0
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''.


Sec.  74.50  [Amended]

0
11. Section 74.50 is amended by:
0
a. In paragraph (a)(2) introductory text, add the words ``source that 
includes'' after the words ``the account of the'';
0
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
0
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
0
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

0
1. The authority citation for part 77 continues to read as follows:

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


Sec.  77.3  [Amended]

0
2. Section 77.3 is amended by:
0
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'';
0
b. In paragraphs (b) and (c), replace the word ``unit'' with the word 
``source'' wherever it appears; and
0
c. In paragraph (d) introductory text and paragraphs (d)(1) and (d)(2), 
replace the word ``unit'' with the word ``source'' whenever it appears;
0
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
0
e. In paragraph (d)(5), replace the words ``unit's compliance 
subaccount'' with the words ``source's compliance account''.


Sec.  77.4  [Amended]

0
3. Section 77.4 is amended by:
0
a. In paragraph (b)(1), replace the words ``unit's compliance 
subaccount'' with the words ``source's compliance account''; and
0
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
0
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''.


Sec.  77.5  [Amended]

0
4. Section 77.5 is amended by:
0
a. In paragraph (b), replace the words ``compliance subaccount'' with 
the words ``compliance account'';
0
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
0
c. Remove paragraph (d).


Sec.  77.6  [Amended]

0
5. Section 77.6 is amended by:
0
a. In paragraph (a)(1), add the words ``occur at the affected source'' 
after the

[[Page 25338]]

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'';
0
b. In paragraph (b)(1)(i)(A), replace the word ``unit'' with the words 
``source or unit as appropriate''; and
0
c. In paragraphs (b)(3),(c), and (f), replace the word ``unit'' with 
the words ``source or unit as appropriate''.

PART 78--APPEAL PROCEDURES

0
1. The title of part 78 is revised to read as set forth above.

0
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.


Sec.  78.1  [Amended]

0
3. Section 78.1 is amended by:
0
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'';
0
b. Revise paragraph (b)(2)(i);
0
c. Add new paragraphs (b)(7), (b)(8), and (b)(9) to read as follows:


Sec.  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 Sec.  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 Sec.  96.154 of 
this chapter;
    (iii) The correction of an error in a CAIR NOX Allowance 
Tracking System account under Sec.  96.156 of this chapter;
    (iv) The decision on the transfer of CAIR NOX allowances 
under Sec.  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 Sec.  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 Sec.  96.254 of 
this chapter;
    (ii) The correction of an error in a CAIR SO2 Allowance 
Tracking System account under Sec.  97.256 of this chapter;
    (iii) The decision on the transfer of CAIR SO2 
allowances under Sec.  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 Sec.  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 Sec.  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 Sec.  96.354 of this chapter;
    (iii) The correction of an error in a CAIR NOX Ozone 
Season Allowance Tracking System account under Sec.  96.356 of this 
chapter;
    (iv) The decision on the transfer of CAIR NOX Ozone 
Season allowances under Sec.  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 Sec.  96.375 
of this chapter.
* * * * *


Sec.  78.3  [Amended]

0
4. Section 78.3 is amended by:
0
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)'';
0
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'';
0
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'';
0
d. Add new paragraphs (a)(4), (a)(5), (a)(6), (d)(5), (d)(6), and 
(d)(7) to read as follows:


Sec.  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 Sec.  
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 Sec.  
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 
Sec.  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 Sec.  
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 
Sec.  96.206 of this

[[Page 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 
Sec.  96.306 of this chapter and any emission monitoring or reporting 
requirements.


Sec.  78.4  [Amended]

0
5. Section 78.4 is amended by adding two new sentences after the fifth 
sentence in paragraph (a) to read as follows:


Sec.  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. * * *
* * * * *


Sec.  78.5  [Amended]

0
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''.


Sec.  78.12  [Amended]

0
7. Section 78.12 is amended by:
0
a. In paragraph (a) introductory text, remove the words ``, or to 
submit a claim of error notification''; and
0
b. In paragraph (a)(2), replace the words ``NOX Budget 
permit'' with the words ``, NOX Budget permit, CAIR 
permit,''.


Sec.  78.13  [Amended]

0
8. Section 78.13 is amended by, in paragraph (b), removing the word 
``also''.

PART 96--[AMENDED]

0
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.

0
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


Sec.  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 Sec.  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 Sec.  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 Sec.  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.


Sec.  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 multi-state sulfur dioxide and nitrogen 
oxides air pollution control and emission reduction program established 
by the Administrator under title IV of the CAA and parts 72 through 78 
of this chapter.
    Administrator means the Administrator of the United States 
Environmental Protection Agency or the Administrator's duly authorized 
representative.

[[Page 25340]]

    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 Sec.  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 Sec.  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 Sec.  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 Sec.  
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 Sec.  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 
Sec.  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 Sec.  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 Sec.  
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 Sec.  96.104 and, except 
for purposes of Sec.  96.105 and

[[Page 25341]]

subpart EE of this part, 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 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 Sec.  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 Sec.  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 Sec.  96.105.
    (i) For a unit that is a CAIR NOX unit under Sec.  
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 Sec.  
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 Sec.  96.105, for a unit that is not a CAIR NOX 
unit under Sec.  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 Sec.  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 Sec.  96.184(h) or Sec.  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 
Sec.  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 Sec.  96.105.
    (i) For a unit that is a CAIR NOX unit under Sec.  
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

[[Page 25342]]

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 Sec.  
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 Sec.  96.105, for a unit that is not a CAIR NOX 
unit under Sec.  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 Sec.  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 Sec.  96.184(h) or Sec.  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 
Sec.  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 Sec.  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 Sec.  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 on-site 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

[[Page 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 Sec.  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

[[Page 25344]]

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 Sec.  
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-fuel-fired 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 on-site emission controls).
    Useful thermal energy means, with regard to a cogeneration unit, 
thermal energy that is:
    (1) Made available to an industrial or commercial process (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.


Sec.  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.


Sec.  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, fossil-fuel-fired boiler or stationary, fossil-fuel-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.


Sec.  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, Sec.  96.102, Sec.  96.103, 
Sec.  96.104, Sec.  96.106(c)(4) through (8), Sec.  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.

[[Page 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 Sec.  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.


Sec.  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 Sec.  96.122 in accordance with the deadlines 
specified in Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  
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

[[Page 25346]]

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 Sec.  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 Sec.  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 Sec.  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.


Sec.  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.


Sec.  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


Sec.  96.110  Authorization and responsibilities of CAIR designated 
representative.

    (a) Except as provided under Sec.  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 Sec.  
96.113(a)(4)(iv).
    (c) Upon receipt by the Administrator of a complete certificate of 
representation under Sec.  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 Sec.  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.


Sec.  96.111  Alternate CAIR designated representative.

    (a) A certificate of representation under Sec.  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.

[[Page 25347]]

    (b) Upon receipt by the Administrator of a complete certificate of 
representation under Sec.  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 Sec. Sec.  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.


Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  
96.113 amending the list of owners and operators to include the change.


Sec.  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-of-the-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.


Sec.  96.114  Objections concerning CAIR designated representative.

    (a) Once a complete certificate of representation under Sec.  
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 
Sec.  96.113 is received by the Administrator.
    (b) Except as provided in Sec.  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

[[Page 25348]]

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


Sec.  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.


Sec.  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 Sec.  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 Sec.  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.


Sec.  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 Sec.  96.106.


Sec.  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 Sec.  96.122.
    (b) Each CAIR permit is deemed to incorporate automatically the 
definitions of terms under Sec.  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.


Sec.  96.124  CAIR permit revisions.

    Except as provided in Sec.  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


Sec.  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 trading budget
            State             State trading budget      for 2015 and
                              for 2009-2014 (tons)    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

[[Page 25349]]

 
Virginia....................                36,074                30,062
West Virginia...............                74,220                61,850
Wisconsin...................                40,759                33,966
------------------------------------------------------------------------

Sec.  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 Sec.  
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 Sec.  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 Sec.  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 Sec.  96.142(a) and (b), 
as well as under Sec.  96.142(a), (c), and (d), for the applicable 
control period will be assumed to be allocated no CAIR NOX 
allowances under Sec.  96.142(a), (c), and (d) for the applicable 
control period.


Sec.  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 Sec.  96.140 (except as provided in paragraph (d) of this 
section).

[[Page 25350]]

    (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 Sec.  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 Sec.  96.140, and rounded 
to the nearest whole allowance as appropriate.


Sec.  96.143  Compliance supplement pool.

    (a) In addition to the CAIR NOX allowances allocated 
under Sec.  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:

------------------------------------------------------------------------
                                                              Compliance
                           State                              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

[[Page 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 x (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


Sec.  96.150  [Reserved]


Sec.  96.151  Establishment of accounts.

    (a) Compliance accounts. Except as provided in Sec.  96.184(e), 
upon receipt of a complete certificate of representation under Sec.  
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.

[[Page 25352]]

    (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.

[[Page 25353]]

Sec.  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.


Sec.  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 Sec.  
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 Sec.  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 Sec.  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 Sec.  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 Sec.  
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.


Sec.  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 Sec.  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 Sec.  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.


Sec.  96.155  Banking.

    (a) CAIR NOX allowances may be banked for future use or 
transfer in a compliance account or a general

[[Page 25354]]

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 Sec.  96.154, Sec.  96.156, or subpart GG of this part.


Sec.  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.


Sec.  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 Sec.  
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 Sec.  
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


Sec.  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.


Sec.  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 Sec.  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 
Sec.  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.


Sec.  96.162  Notification.

    (a) Notification of recordation. Within 5 business days of 
recordation of a CAIR NOX allowance transfer under Sec.  
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 Sec.  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 non-recordation.
    (c) Nothing in this section shall preclude the submission of a CAIR 
NOX allowance transfer for recordation following 
notification of non-recordation.

Subpart HH--Monitoring and Reporting


Sec.  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 
Sec.  96.102 and in Sec.  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 Sec.  96.102. The owner or operator of a unit that is not 
a CAIR NOX unit but that is monitored under Sec.  
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 Sec. Sec.  75.71 and 75.72 
of this chapter);
    (2) Successfully complete all certification tests required under 
Sec.  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,

[[Page 25355]]

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 Sec.  96.184(b).
    (5) Notwithstanding the dates in paragraphs (b)(1), (2), and (4) of 
this section and solely for purposes of Sec.  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 
Sec.  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 Sec.  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 Sec.  
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 Sec.  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 
Sec.  96.171(d)(3)(i).


Sec.  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 Sec.  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 Sec.  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 Sec.  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 
Sec.  75.17(a) or (b) of this chapter for apportioning the 
NOX emission rate measured in a common stack or a petition 
under Sec.  75.66 of this chapter for an alternative to a requirement 
in Sec.  75.12, Sec.  75.17, or subpart H of part 75 of this chapter, 
the CAIR designated representative shall resubmit the petition to the 
Administrator under Sec.  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 Sec.  96.170(a)(1). The owner or 
operator of a unit that qualifies to use the low mass emissions 
excepted monitoring methodology under Sec.  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 Sec.  
96.170(a)(1)(including the automated data acquisition and handling 
system) successfully completes all of the initial certification testing 
required under Sec.  75.20 of this chapter by the applicable deadline 
in Sec.  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 Sec.  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

[[Page 25356]]

monitoring system under Sec.  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 
quality-assurance and quality-control requirements of Sec.  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 Sec.  
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 Sec.  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 Sec.  96.170(a)(1) are subject to the recertification 
requirements in Sec.  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 Sec.  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 Sec. Sec.  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 Sec.  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 Sec.  75.63 of this chapter.
    (iii) Provisional certification date. The provisional certification 
date for a monitoring system shall be determined in accordance with 
Sec.  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 quality-assured data beginning 
with the date and hour of provisional certification (as defined under 
Sec.  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 Sec.  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 Sec.  
75.20(a)(4)(iii), Sec.  75.20(g)(7), or Sec.  75.21(e) of this chapter 
and continuing until the applicable date and hour specified under Sec.  
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 Sec.  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

[[Page 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 Sec.  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 Sec.  75.19 of 
this chapter. The owner or operator of a unit qualified to use the low 
mass emissions (LME) excepted methodology under Sec.  75.19 of this 
chapter shall meet the applicable certification and recertification 
requirements in Sec. Sec.  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 Sec.  
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 Sec.  
75.20(f) of this chapter.


Sec.  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 Sec.  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 Sec.  
96.171 for each disapproved monitoring system.


Sec.  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 Sec.  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.


Sec.  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 
Sec.  75.73 of this chapter, and the requirements of Sec.  
96.110(e)(1).
    (b) Monitoring Plans. The owner or operator of a CAIR 
NOX unit shall comply with requirements of Sec.  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, Sec. Sec.  
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 Sec.  96.171, including the information required under 
Sec.  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 Sec.  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 Sec.  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

[[Page 25358]]

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 
Sec.  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.


Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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.


Sec.  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


Sec.  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 Sec.  96.104 and is not 
covered by a retired unit exemption under Sec.  96.105 that is in 
effect;
    (c) Is not covered by a retired unit exemption under Sec.  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.


Sec.  96.181  General.

    (a) Except as otherwise provided in Sec. Sec.  96.101 through 
96.104, Sec. Sec.  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.


Sec.  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.


Sec.  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 Sec.  96.180 may apply for an initial 
CAIR opt-in permit at any time, except as provided under Sec.  
96.186(f) and (g), and, in order to apply, must submit the following:
    (1) A complete CAIR permit application under Sec.  96.122;
    (2) A certification, in a format specified by the permitting 
authority, that the unit:
    (i) Is not a CAIR NOX unit under Sec.  96.104 and is not 
covered by a retired unit exemption under Sec.  96.105 that is in 
effect;
    (ii) Is not covered by a retired unit exemption under Sec.  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 Sec.  96.122;
    (3) A monitoring plan in accordance with subpart HH of this part;
    (4) A complete certificate of representation under Sec.  96.113 
consistent with Sec.  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 Sec.  96.188(c) (subject 
to the conditions in Sec. Sec.  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 Sec.  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 Sec.  96.186 
or the unit becomes a CAIR NOX unit under Sec.  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.


Sec.  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

[[Page 25359]]

opt-in permit under Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 emissions-
related requirements and which control periods begin not more than 3 
years before the unit enters the CAIR NOX Annual Trading 
Program under Sec.  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 Sec.  96.180 and meets the elements certified in Sec.  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 Sec.  96.180 or meets the elements certified in Sec.  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 Sec.  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.


Sec.  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 Sec.  96.122;
    (2) The certification in Sec.  96.183(a)(2);
    (3) The unit's baseline heat input under Sec.  96.184(c);
    (4) The unit's baseline NOX emission rate under Sec.  
96.184(d);
    (5) A statement whether the unit is to be allocated CAIR 
NOX allowances under Sec.  96.188(c) (subject to the

[[Page 25360]]

conditions in Sec. Sec.  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 Sec.  
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 Sec.  
96.187.
    (b) Each CAIR opt-in permit is deemed to incorporate automatically 
the definitions of terms under Sec.  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.


Sec.  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 Sec.  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 Sec.  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 Sec.  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 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 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 Sec.  
96.183 for such CAIR NOX 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 Sec.  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 Sec.  96.188(c).


Sec.  96.187  Change in regulatory status.

    (a) Notification. If a CAIR NOX opt-in unit becomes a 
CAIR NOX unit under Sec.  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 Sec.  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 Sec.  96.123 as of the date on 
which the CAIR NOX opt-in unit becomes a CAIR NOX 
unit under Sec.  96.104.
    (2)(i) The Administrator will deduct from the compliance account of 
the source that includes the CAIR NOX opt-in unit that 
becomes a CAIR NOX unit under Sec.  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 Sec.  96.188 for any control period 
after the date on which the CAIR NOX opt-in unit becomes a 
CAIR NOX unit under Sec.  96.104; and
    (B) If the date on which the CAIR NOX opt-in unit 
becomes a CAIR NOX unit under Sec.  96.104 is not December 
31, the CAIR NOX allowances allocated to the CAIR 
NOX opt-in unit under Sec.  96.188 for the control period 
that includes the date on which the CAIR NOX opt-in unit 
becomes a CAIR NOX unit under

[[Page 25361]]

Sec.  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 Sec.  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 Sec.  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 opt-in unit becomes a CAIR NOX unit under 
Sec.  96.104, the CAIR NOX opt-in unit will be treated, 
solely for purposes of CAIR NOX allowance allocations under 
Sec.  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 Sec.  96.104 and will be allocated CAIR NOX allowances 
under Sec.  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 Sec.  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 Sec.  
96.142 for the control period that includes the date on which the CAIR 
NOX opt-in unit becomes a CAIR NOX unit under 
Sec.  96.104:
    (A) The number of CAIR NOX allowances otherwise 
allocated to the CAIR NOX opt-in unit (as a CAIR 
NOX unit) under Sec.  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 Sec.  96.104, divided by the 
total number of days in the control period; and
    (C) Rounded to the nearest whole allowance as appropriate.


Sec.  96.188  NOX allowance allocations to CAIR 
NOX opt-in units.

    (a) Timing requirements. (1) When the CAIR opt-in permit is issued 
under Sec.  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 Sec.  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 Sec.  96.184(g) and October 31 of each year thereafter, 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 that includes such submission 
deadline and in which the unit is a CAIR NOX 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 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 Sec.  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 
Sec.  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 Sec.  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 opt-in permit providing for, allocation to a CAIR NOX 
opt-in unit of CAIR NOX allowances under this paragraph 
(subject to the conditions in Sec. Sec.  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 Sec.  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 Sec.  
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 Sec.  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

[[Page 25362]]

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 Sec.  
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.

0
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


Sec.  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 Sec.  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 
Sec.  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 Sec.  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.


Sec.  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 multi-state sulfur dioxide and nitrogen 
oxides air pollution control and emission reduction program established 
by the Administrator under title IV of the CAA and parts 72 through 78 
of this chapter.
    Administrator means the Administrator of the United States 
Environmental Protection Agency or the Administrator's duly authorized 
representative.
    Allocate or allocation means, with regard to CAIR 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 Sec.  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 Sec.  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

[[Page 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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 
Sec.  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 Sec.  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 Sec.  51.124 of this chapter, as a means 
of mitigating interstate transport of fine particulates and sulfur 
dioxide.

[[Page 25364]]

    CAIR SO2 unit means a unit that is subject to the CAIR 
SO2 Trading Program under Sec.  96.204 and, except for 
purposes of Sec.  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 Sec.  96.205.
    (i) For a unit that is a CAIR SO2 unit under Sec.  
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 Sec.  
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 Sec.  96.205, for a unit that is not a CAIR SO2 
unit under Sec.  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 Sec.  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 Sec.  96.284(h) or Sec.  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 Sec.  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 Sec.  96.205.
    (i) For a unit that is a CAIR SO2 unit under Sec.  
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 Sec.  
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 Sec.  96.205, for a unit that is not a CAIR SO2 
unit under Sec.  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 Sec.  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

[[Page 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 Sec.  96.284(h) or Sec.  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 
Sec.  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 Sec.  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 Sec.  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 Sec.  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

[[Page 25366]]

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 Sec.  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 Sec.  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

[[Page 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-fuel-fired 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 on-site emission controls).
    Useful thermal energy means, with regard to a cogeneration unit, 
thermal energy that is:
    (1) Made available to an industrial or commercial process (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.


Sec.  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.


Sec.  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, fossil-fuel-fired boiler or stationary, fossil-fuel-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.


Sec.  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, Sec.  96.202, Sec.  96.203, Sec.  
96.204, Sec.  96.206(c)(4) through (8), Sec.  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 Sec.  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

[[Page 25368]]

    (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.


Sec.  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 Sec.  96.222 in accordance with the deadlines 
specified in Sec.  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 
Sec.  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 Sec.  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 Sec.  
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 Sec.  
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 Sec.  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 Sec.  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.

[[Page 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 Sec.  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.


Sec.  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.


Sec.  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


Sec.  96.210  Authorization and responsibilities of CAIR designated 
representative.

    (a) Except as provided under Sec.  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 Sec.  
96.213(a)(4)(iv).
    (c) Upon receipt by the Administrator of a complete certificate of 
representation under Sec.  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 Sec.  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.


Sec.  96.211  Alternate CAIR designated representative.

    (a) A certificate of representation under Sec.  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 Sec.  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 Sec. Sec.  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.


Sec.  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 Sec.  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 Sec.  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

[[Page 25370]]

is not included in the list of owners and operators in the certificate 
of representation under Sec.  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 Sec.  
96.213 amending the list of owners and operators to include the change.


Sec.  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-of-the-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.


Sec.  96.214  Objections concerning CAIR designated representative.

    (a) Once a complete certificate of representation under Sec.  
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 
Sec.  96.213 is received by the Administrator.
    (b) Except as provided in Sec.  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


Sec.  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.


Sec.  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 Sec.  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

[[Page 25371]]

representative shall submit a complete CAIR permit application under 
Sec.  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.


Sec.  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 Sec.  96.206.


Sec.  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 Sec.  96.222.
    (b) Each CAIR permit is deemed to incorporate automatically the 
definitions of terms under Sec.  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.


Sec.  96.224  CAIR permit revisions.

    Except as provided in Sec.  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


Sec.  96.250  [Reserved]


Sec.  96.251  Establishment of accounts.

    (a) Compliance accounts. Except as provided in Sec.  96.284(e), 
upon receipt of a complete certificate of representation under Sec.  
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

[[Page 25372]]

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.


Sec.  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.


Sec.  96.253  Recordation of CAIR SO2 allowances.

    (a)(1) After a compliance account is established under Sec.  
96.251(a) or Sec.  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 Sec.  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 Sec.  96.251(b) 
or Sec.  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 Sec.  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

[[Page 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 Sec.  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.


Sec.  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 Sec.  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 Sec.  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 Sec.  96.288, that is required under Sec. Sec.  
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 Sec. Sec.  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 Sec.  96.288, that is required under Sec. Sec.  
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 Sec. Sec.  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 Sec.  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 Sec.  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 Sec.  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 
Sec.  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 Sec.  96.288), equal to, or exceeding in

[[Page 25374]]

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.


Sec.  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 Sec.  96.254, Sec.  96.256, or subpart GGG of this part.


Sec.  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.


Sec.  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 Sec.  
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 Sec.  
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


Sec.  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.''


Sec.  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 Sec.  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 
Sec.  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.


Sec.  96.262  Notification.

    (a) Notification of recordation. Within 5 business days of 
recordation of a CAIR SO2 allowance transfer under Sec.  
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 Sec.  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 non-recordation.
    (c) Nothing in this section shall preclude the submission of a CAIR 
SO2 allowance transfer for recordation

[[Page 25375]]

following notification of non-recordation.

Subpart HHH--Monitoring and Reporting


Sec.  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 Sec.  96.202 and in Sec.  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 Sec.  96.202. The owner or operator of a unit that is not 
a CAIR SO2 unit but that is monitored under Sec.  
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 Sec. Sec.  75.11 and 75.16 of this 
chapter);
    (2) Successfully complete all certification tests required under 
Sec.  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 Sec.  96.284(b).
    (5) Notwithstanding the dates in paragraphs (b)(1) and (2) of this 
section and solely for purposes of Sec.  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 opt-in unit enters 
the CAIR SO2 Trading Program as provided in Sec.  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 Sec.  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 Sec.  
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 Sec.  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 
Sec.  96.271(d)(3)(i).

[[Page 25376]]

Sec.  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 Sec.  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 Sec.  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 Sec.  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 
Sec.  Sec.  75.16(b)(2)(ii) of this chapter for apportioning the 
SO2 mass emissions measured in a common stack or a petition 
under Sec.  75.66 of this chapter for an alternative to a requirement 
in Sec.  75.11 or Sec.  75.16 of this chapter, the CAIR designated 
representative shall resubmit the petition to the Administrator under 
Sec.  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 Sec.  96.270(a)(1). The owner or operator of a unit 
that qualifies to use the low mass emissions excepted monitoring 
methodology under Sec.  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 Sec.  
96.270(a)(1) (including the automated data acquisition and handling 
system) successfully completes all of the initial certification testing 
required under Sec.  75.20 of this chapter by the applicable deadline 
in Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  
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 Sec.  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 Sec.  96.270(a)(1) is 
subject to the recertification requirements in Sec.  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 Sec.  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 Sec. Sec.  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 Sec.  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 Sec.  75.63 of this chapter.
    (iii) Provisional certification date. The provisional certification 
date for a monitoring system shall be determined in accordance with 
Sec.  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.

[[Page 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 quality-assured data beginning 
with the date and hour of provisional certification (as defined under 
Sec.  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 Sec.  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 Sec.  
75.20(a)(4)(iii), Sec.  75.20(g)(7), or Sec.  75.21(e) of this chapter 
and continuing until the applicable date and hour specified under Sec.  
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 Sec.  75.19 of 
this chapter. The owner or operator of a unit qualified to use the low 
mass emissions (LME) excepted methodology under Sec.  75.19 of this 
chapter shall meet the applicable certification and recertification 
requirements in Sec. Sec.  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 Sec.  
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 Sec.  
75.20(f) of this chapter.


Sec.  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 Sec.  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 Sec.  
96.271 for each disapproved monitoring system.


Sec.  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 Sec.  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.


Sec.  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 
Sec.  96.210(e)(1).
    (b) Monitoring plans. The owner or operator of a CAIR 
SO2 unit shall comply with requirements of Sec.  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, Sec. Sec.  96.283 and 
96.284(a).

[[Page 25378]]

    (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 Sec.  96.271, including the information required under 
Sec.  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 Sec.  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 Sec.  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 
Sec.  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.


Sec.  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 Sec.  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 Sec.  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.


Sec.  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


Sec.  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 Sec.  96.204 and is not 
covered by a retired unit exemption under Sec.  96.205 that is in 
effect;
    (c) Is not covered by a retired unit exemption under Sec.  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.


Sec.  96.281  General.

    (a) Except as otherwise provided in Sec. Sec.  96.201 through 
96.204, Sec. Sec.  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.


Sec.  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.


Sec.  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 Sec.  96.280 may apply for an initial 
CAIR opt-in permit at any time, except as provided under Sec.  
96.286(f) and (g), and, in order to apply, must submit the following:
    (1) A complete CAIR permit application under Sec.  96.222;
    (2) A certification, in a format specified by the permitting 
authority, that the unit:
    (i) Is not a CAIR SO2 unit under Sec.  96.204 and is not 
covered by a retired unit exemption under Sec.  96.205 that is in 
effect;
    (ii) Is not covered by a retired unit exemption under Sec.  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

[[Page 25379]]

    (v) Has documented heat input for more than 876 hours during the 6 
months immediately preceding submission of the CAIR permit application 
under Sec.  96.222;
    (3) A monitoring plan in accordance with subpart HHH of this part;
    (4) A complete certificate of representation under Sec.  96.213 
consistent with Sec.  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 Sec.  96.288(c) (subject 
to the conditions in Sec. Sec.  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 Sec.  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 Sec.  96.286 or the 
unit becomes a CAIR SO2 unit under Sec.  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.


Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 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 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 Sec.  96.280 and meets the elements certified in Sec.  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 Sec.  96.280 or meets the elements certified in Sec.  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

[[Page 25380]]

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 Sec.  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.


Sec.  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 Sec.  96.222;
    (2) The certification in Sec.  96.283(a)(2);
    (3) The unit's baseline heat input under Sec.  96.284(c);
    (4) The unit's baseline SO2 emission rate under Sec.  
96.284(d);
    (5) A statement whether the unit is to be allocated CAIR 
SO2 allowances under Sec.  96.288(c) (subject to the 
conditions in Sec. Sec.  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 Sec.  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 Sec.  
96.287.
    (b) Each CAIR opt-in permit is deemed to incorporate automatically 
the definitions of terms under Sec.  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.


Sec.  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 Sec.  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 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 
SO2 opt-in unit must meet the requirement to hold CAIR 
SO2 allowances under Sec.  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 Sec.  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 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 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 opt-in permit is terminated 
under this section, the CAIR designated representative may not submit 
another application for a CAIR opt-in permit under Sec.  96.283 for 
such CAIR SO2 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 Sec.  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 Sec.  96.288(c).

[[Page 25381]]

Sec.  96.287  Change in regulatory status.

    (a) Notification. If a CAIR SO2 opt-in unit becomes a 
CAIR SO2 unit under Sec.  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 Sec.  96.204, the permitting authority will revise the CAIR 
SO2 opt-in unit's CAIR opt-in permit to meet the 
requirements of a CAIR permit under Sec.  96.223 as of the date on 
which the CAIR SO2 opt-in unit becomes a CAIR SO2 
unit under Sec.  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 Sec.  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 Sec.  96.288 for any control period 
after the date on which the CAIR SO2 opt-in unit becomes a 
CAIR SO2 unit under Sec.  96.204; and
    (B) If the date on which the CAIR SO2 opt-in unit 
becomes a CAIR SO2 unit under Sec.  96.204 is not December 
31, the CAIR SO2 allowances allocated to the CAIR 
SO2 opt-in unit under Sec.  96.288 for the control period 
that includes the date on which the CAIR SO2 opt-in unit 
becomes a CAIR SO2 unit under Sec.  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 Sec.  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 Sec.  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 
Sec.  96.204, the CAIR SO2 opt-in unit will be treated, 
solely for purposes of CAIR SO2 allowance allocations under 
Sec.  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 Sec.  96.204 and will be allocated CAIR SO2 allowances 
under Sec.  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 Sec.  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 Sec.  
96.242 for the control period that includes the date on which the CAIR 
SO2 opt-in unit becomes a CAIR SO2 unit under 
Sec.  96.204:
    (A) The number of CAIR SO2 allowances otherwise 
allocated to the CAIR SO2 opt-in unit (as a CAIR 
SO2 unit) under Sec.  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 Sec.  96.204, divided by the 
total number of days in the control period; and
    (C) Rounded to the nearest whole allowance as appropriate.


Sec.  96.288  SO2 allowance allocations to CAIR 
SO2 opt-in units.

    (a) Timing requirements. (1) When the CAIR opt-in permit is issued 
under Sec.  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 opt-in unit enters the CAIR SO2 
Trading Program under Sec.  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 
Sec.  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 Sec.  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 Sec.  
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 Sec.  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 opt-in permit providing for, allocation to a CAIR SO2 
opt-in unit of CAIR SO2 allowances under this paragraph 
(subject to the conditions in Sec. Sec.  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 Sec.  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 Sec.  
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

[[Page 25382]]

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 Sec.  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 Sec.  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.

0
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


Sec.  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 Sec.  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 
Sec.  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 Sec.  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.


Sec.  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.

[[Page 25383]]

    Acid Rain Program means a multi-state sulfur dioxide and nitrogen 
oxides air pollution control and emission reduction program established 
by the Administrator under title IV of the CAA and parts 72 through 78 
of this chapter.
    Administrator means the Administrator of the United States 
Environmental Protection Agency or the Administrator's duly authorized 
representative.
    Allocate or allocation means, with regard to CAIR NOX 
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 
Sec.  96.388 or Sec.  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 Sec.  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 Sec.  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, 
Sec.  96.388, or Sec.  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 Sec.  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 Sec.  51.121(p) of 
this chapter or Sec.  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,

[[Page 25384]]

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 Sec.  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 Sec.  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 Sec.  96.304 and, 
except for purposes of Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  96.305.
    (i) For a unit that is a CAIR NOX Ozone Season unit 
under Sec.  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 Sec.  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 Sec.  96.305, for a unit that is not a CAIR NOX 
Ozone Season unit under Sec.  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 Sec.  
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 Sec.  96.384(h) or Sec.  96.387(b)(3), for a CAIR 
NOX Ozone Season opt-in unit or

[[Page 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 Sec.  
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 Sec.  96.305.
    (i) For a unit that is a CAIR NOX Ozone Season unit 
under Sec.  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 Sec.  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 Sec.  96.305, for a unit that is not a CAIR NOX 
Ozone Season unit under Sec.  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 Sec.  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 Sec.  96.384(h) or Sec.  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 
Sec.  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 Sec.  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 Sec.  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

[[Page 25386]]

    (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 on-site 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

[[Page 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 Sec.  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 
Sec.  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-fuel-fired 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 on-site emission controls).
    Useful thermal energy means, with regard to a cogeneration unit, 
thermal energy that is:
    (1) Made available to an industrial or commercial process (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.


Sec.  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.


Sec.  96.304  Applicability.

    The following units in a State shall be CAIR NOX Ozone 
Season units, and any

[[Page 25388]]

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, fossil-fuel-fired boiler or stationary, fossil-fuel-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.


Sec.  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, Sec.  
96.302, Sec.  96.303, Sec.  96.304, Sec.  96.306(c)(4) through (8), 
Sec.  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 Sec.  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.


Sec.  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 Sec.  96.322 in accordance with the deadlines 
specified in Sec.  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

[[Page 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 Sec.  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 Sec.  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 Sec.  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 
Sec.  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 Sec.  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 Sec.  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 Sec.  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.


Sec.  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.


Sec.  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.

[[Page 25390]]

Subpart BBBB--CAIR Designated Representative for CAIR 
NOX Ozone Season Sources


Sec.  96.310  Authorization and responsibilities of CAIR designated 
representative.

    (a) Except as provided under Sec.  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 Sec.  96.313(a)(4)(iv).
    (c) Upon receipt by the Administrator of a complete certificate of 
representation under Sec.  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 Sec.  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.


Sec.  96.311  Alternate CAIR designated representative.

    (a) A certificate of representation under Sec.  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 Sec.  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 Sec. Sec.  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.


Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  96.313 amending the list of owners and 
operators to include the change.


Sec.  96.313  Certificate of representation.

    (a) A complete certificate of representation for a CAIR designated 
representative or an alternate CAIR designated representative shall 
include

[[Page 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-the-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 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.


Sec.  96.314  Objections concerning CAIR designated representative.

    (a) Once a complete certificate of representation under Sec.  
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 
Sec.  96.313 is received by the Administrator.
    (b) Except as provided in Sec.  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


Sec.  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.


Sec.  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 Sec.  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 
Sec.  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.


Sec.  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;

[[Page 25392]]

    (b) Identification of each CAIR NOX Ozone Season unit at 
the CAIR NOX Ozone Season source; and
    (c) The standard requirements under Sec.  96.306.


Sec.  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 Sec.  96.322.
    (b) Each CAIR permit is deemed to incorporate automatically the 
definitions of terms under Sec.  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.


Sec.  96.324  CAIR permit revisions.

    Except as provided in Sec.  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


Sec.  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 trading budget
            State             State trading budget      for 2015 and
                              for 2009-2014 (tons)    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 Sec.  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 Sec.  51.123(aa)(2)(iii)(A) of this chapter 
for the year.


Sec.  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 Sec.  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 Sec.  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 Sec.  96.342(c), 
(a), and (d), for the control period in the

[[Page 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 Sec.  96.342(a) and (b), 
as well as under Sec.  96.342(a), (c), and (d), for the applicable 
control period will be assumed to be allocated no CAIR NOX 
Ozone Season allowances under Sec.  96.342(a), (c), and (d) for the 
applicable control period.


Sec.  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 Sec.  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 Sec.  
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.

[[Page 25394]]

    (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 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 
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 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 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 set-aside 
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 Sec.  96.340, and rounded 
to the nearest whole allowance as appropriate.

Subpart FFFF--CAIR NOX Ozone Season Allowance Tracking 
System


Sec.  96.350  [Reserved]


Sec.  96.351  Establishment of accounts.

    (a) Compliance accounts. Except as provided in Sec.  96.384(e), 
upon receipt of a complete certificate of representation under Sec.  
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

[[Page 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.


Sec.  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.


Sec.  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 Sec.  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

[[Page 25396]]

accordance with Sec.  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 Sec.  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 Sec.  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 Sec.  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.


Sec.  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 Sec.  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 Sec.  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.


Sec.  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 Sec.  96.354, Sec.  96.356, or subpart GG 
of this part.


Sec.  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

[[Page 25397]]

days of making such correction, the Administrator will notify the CAIR 
authorized account representative for the account.


Sec.  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 Sec.  
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 Sec.  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


Sec.  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.


Sec.  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 Sec.  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 Sec.  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.


Sec.  96.362  Notification.

    (a) Notification of recordation. Within 5 business days of 
recordation of a CAIR NOX Ozone Season allowance transfer 
under Sec.  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 Sec.  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 non-recordation.
    (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


Sec.  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 Sec.  96.302 and in Sec.  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 Sec.  96.302. The owner or operator of a 
unit that is not a CAIR NOX Ozone Season unit but that is 
monitored under Sec.  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 Sec. Sec.  75.71 and 75.72 
of this chapter);
    (2) Successfully complete all certification tests required under 
Sec.  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 Sec.  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.

[[Page 25398]]

    (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 Sec.  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 Sec.  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 Sec.  
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 Sec.  
96.384(b).
    (7) Notwithstanding the dates in paragraphs (b)(1), (2), and (3) of 
this section and solely for purposes of Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 
Sec.  96.371(d)(3)(i).


Sec.  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 Sec.  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 Sec.  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 Sec.  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 
Sec.  75.17(a) or (b) of this chapter for apportioning the 
NOX emission rate measured in a common stack or a petition 
under Sec.  75.66 of this chapter for an alternative to a requirement 
in Sec.  75.12, Sec.  75.17, or subpart H of part 75 of this chapter, 
the CAIR designated representative shall resubmit the petition to the 
Administrator under Sec.  96.375(a) to determine whether the approval 
applies

[[Page 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 Sec.  96.370(a)(1). The owner 
or operator of a unit that qualifies to use the low mass emissions 
excepted monitoring methodology under Sec.  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 Sec.  
96.370(a)(1)(including the automated data acquisition and handling 
system) successfully completes all of the initial certification testing 
required under Sec.  75.20 of this chapter by the applicable deadline 
in Sec.  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 Sec.  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 Sec.  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 
quality-assurance and quality-control requirements of Sec.  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 Sec.  
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 Sec.  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 Sec.  96.370(a)(1) are subject to the recertification 
requirements in Sec.  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 Sec.  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 Sec. Sec.  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 Sec.  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 Sec.  75.63 of this chapter.
    (iii) Provisional certification date. The provisional certification 
date for a monitoring system shall be determined in accordance with 
Sec.  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 quality-assured data beginning 
with the date and hour of provisional certification (as defined under 
Sec.  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

[[Page 25400]]

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 Sec.  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 Sec.  
75.20(a)(4)(iii), Sec.  75.20(g)(7), or Sec.  75.21(e) of this chapter 
and continuing until the applicable date and hour specified under Sec.  
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 Sec.  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 Sec.  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 Sec.  75.19 of 
this chapter. The owner or operator of a unit qualified to use the low 
mass emissions (LME) excepted methodology under Sec.  75.19 of this 
chapter shall meet the applicable certification and recertification 
requirements in Sec. Sec.  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 Sec.  
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 Sec.  
75.20(f) of this chapter.


Sec.  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 Sec.  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 Sec.  
96.371 for each disapproved monitoring system.


Sec.  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 Sec.  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.


Sec.  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 
Sec.  75.73 of this chapter, and the requirements of Sec.  
96.310(e)(1).
    (b) Monitoring plans. The owner or operator of a CAIR 
NOX Ozone Season unit shall comply with requirements of 
Sec.  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, Sec. Sec.  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 Sec.  96.371, including the information required under 
Sec.  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

[[Page 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 Sec.  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 Sec.  75.74(c) of this chapter) 
and report NOX mass emissions data and heat input data 
(including the data described in Sec.  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 Sec.  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 Sec.  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 
Sec.  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.


Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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.


Sec.  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


Sec.  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 Sec.  
96.304 and is not covered by a retired unit exemption under Sec.  
96.305 that is in effect;
    (c) Is not covered by a retired unit exemption under Sec.  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.


Sec.  96.381  General.

    (a) Except as otherwise provided in Sec. Sec.  96.301 through 
96.304, Sec. Sec.  96.306

[[Page 25402]]

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.


Sec.  96.382  CAIR designated representative.

    Any CAIR NOX Ozone Season 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 
Ozone Season units shall have the same CAIR designated representative 
and alternate CAIR designated representative as such CAIR 
NOX Ozone Season units.


Sec.  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 Sec.  96.380 may apply for 
an initial CAIR opt-in permit at any time, except as provided under 
Sec.  96.386 (f) and (g), and, in order to apply, must submit the 
following:
    (1) A complete CAIR permit application under Sec.  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 Sec.  
96.304 and is not covered by a retired unit exemption under Sec.  
96.305 that is in effect;
    (ii) Is not covered by a retired unit exemption under Sec.  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 Sec.  96.322;
    (3) A monitoring plan in accordance with subpart HHHH of this part;
    (4) A complete certificate of representation under Sec.  96.313 
consistent with Sec.  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 Sec.  
96.388(c) (subject to the conditions in Sec. Sec.  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 Sec.  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 Sec.  96.186 
or the unit becomes a CAIR NOX unit under Sec.  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.


Sec.  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 Sec.  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 Sec.  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 Sec.  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 
Sec.  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 Sec.  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 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 
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 Sec.  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

[[Page 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 Sec.  96.380 and meets the elements certified in Sec.  
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 Sec.  96.380 or meets the elements certified in Sec.  
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 Sec.  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.


Sec.  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 Sec.  96.322;
    (2) The certification in Sec.  96.383(a)(2);
    (3) The unit's baseline heat input under Sec.  96.384(c);
    (4) The unit's baseline NOX emission rate under Sec.  
96.384(d);
    (5) A statement whether the unit is to be allocated CAIR 
NOX Ozone Season allowances under Sec.  96.388(c) (subject 
to the conditions in Sec. Sec.  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 
Sec.  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 Sec.  
96.387.
    (b) Each CAIR opt-in permit is deemed to incorporate automatically 
the definitions of terms under Sec.  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 
opt-in unit covered by the CAIR opt-in permit.


Sec.  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 
Sec.  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 Sec.  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 Sec.  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.

[[Page 25404]]

    (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 opt-in 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 Sec.  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 Sec.  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 opt-in permit providing for, allocation to the CAIR 
NOX Ozone Season opt-in unit of CAIR NOX Ozone 
Season allowances under Sec.  96.388(c).


Sec.  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 Sec.  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 Sec.  96.304, the permitting 
authority will revise the CAIR NOX Ozone Season opt-in 
unit's CAIR opt-in permit to meet the requirements of a CAIR permit 
under Sec.  96.323 as of the date on which the CAIR NOX 
Ozone Season opt-in unit becomes a CAIR NOX Ozone Season 
unit under Sec.  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 Sec.  
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 Sec.  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 Sec.  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 Sec.  
96.304 is not September 30, the CAIR NOX Ozone Season 
allowances allocated to the CAIR NOX Ozone Season opt-in 
unit under Sec.  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 Sec.  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 opt-in unit 
becomes a CAIR NOX Ozone Season unit under Sec.  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 Sec.  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 Sec.  96.304, the CAIR NOX Ozone 
Season opt-in unit will be treated, solely for purposes of CAIR 
NOX Ozone Season allowance allocations under Sec.  96.342, 
as a unit that commences operation on the date on which the CAIR 
NOX Ozone Season opt-in unit becomes a CAIR NOX 
Ozone Season unit under Sec.  96.304 and will be allocated CAIR 
NOX Ozone Season allowances under Sec.  96.342.
    (ii) Notwithstanding paragraph (b)(3)(i) of this section, if the 
date on which the CAIR NOX Ozone Season opt-in unit becomes 
a CAIR NOX Ozone Season unit under Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  
96.304, divided by the total number of days in the control period; and
    (C) Rounded to the nearest whole allowance as appropriate.


Sec.  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 Sec.  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

[[Page 25405]]

CAIR NOX Ozone Season Trading Program under Sec.  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 Sec.  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 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 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 opt-in unit's baseline 
heat input determined under Sec.  96.384(c); or
    (ii) The CAIR NOX Ozone Season opt-in 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 Sec.  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 opt-in unit's baseline 
NOX emissions rate (in lb/mmBtu) determined under Sec.  
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 opt-in 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 Sec. Sec.  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 opt-in unit's baseline 
NOX emissions rate (in lb/mmBtu) determined under Sec.  
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 Sec.  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 opt-in unit's baseline 
NOX emissions rate (in lb/mmBtu) determined under Sec.  
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 
Sec.  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