[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]]
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Part II
Environmental Protection Agency
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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]]
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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.
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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:
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Examples of
Category \1\ NAICS code potentially
regulated entities
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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.
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\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
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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
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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.
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\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).
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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.
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\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.
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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.
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\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.
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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\
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\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.
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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\
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\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\
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\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.
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\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).
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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.
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\12\ EPA 454/K-04-001, April 2004.
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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\
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\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\
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\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).
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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\
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\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.
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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.
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\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\
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\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\
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\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\
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\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.
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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.
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\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.
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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\.
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\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\
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\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\
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\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\
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\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.
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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\
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\44\ See the CAIR Air Quality Modeling TSD for description of
the methodology used to calculate these metrics.
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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.
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\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.
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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.
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\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.
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\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.
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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\
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\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.
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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.
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\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.
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\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.
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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.
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\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.
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[[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\
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\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\
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\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\
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\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.)
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\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.
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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.
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\111\ The 2010 modeling date is relevant for both SO2
and NOX even though NOX requirements begin in
2009. See Section IV for discussion.
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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\
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\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.
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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\
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\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).
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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.
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\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).
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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\
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\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.
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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.
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\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.
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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\
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\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).
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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\
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\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.
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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\
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\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).
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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.
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\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.
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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.
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\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).
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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.
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\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.
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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.
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\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.
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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.
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\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''?
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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.
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\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.
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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.
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\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.
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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.
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\134\ Auctions could provide States with a non-distortionary
source of revenue.
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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).
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\135\ 5 percent of the allowances would go to a new source set-
aside.
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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.
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\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).
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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\
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\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.
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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\
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\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.
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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.
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\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.
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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.
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\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.
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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.
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\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.
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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.
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\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\
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\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\
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\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.
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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'').
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\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.
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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.
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\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.
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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\
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\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).
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\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:
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\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\
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\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.
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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.
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\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).
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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.
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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