Document ID: EPA-HQ-OAR-2009-0491-4574
Agency: epa
Document Type: Rule
Title: Federal Implementation Plans: Interstate Transport of Fine Particulate Matter and Ozone and Correction of SIP Approvals
Posted Date: 2011-08-08T04:00Z

[Federal Register Volume 76, Number 152 (Monday, August 8, 2011)]
[Rules and Regulations]
[Pages 48208-48483]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2011-17600]

[[Page 48207]]

Vol. 76

Monday,

No. 152

August 8, 2011

Part II

Environmental Protection Agency

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40 CFR Parts 51, 52, 72 et al.

Federal Implementation Plans: Interstate Transport of Fine Particulate 
Matter and Ozone and Correction of SIP Approvals; Final Rule

  Federal Register / Vol. 76, No. 152 / Monday, August 8, 2011 / Rules 
and Regulations  

[[Page 48208]]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 51, 52, 72, 78, and 97

[EPA-HQ-OAR-2009-0491; FRL-9436-8]
RIN 2060-AP50

Federal Implementation Plans: Interstate Transport of Fine 
Particulate Matter and Ozone and Correction of SIP Approvals

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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SUMMARY: In this action, EPA is limiting the interstate transport of 
emissions of nitrogen oxides (NOX) and sulfur dioxide 
(SO2) that contribute to harmful levels of fine particle 
matter (PM2.5) and ozone in downwind states. EPA is 
identifying emissions within 27 states in the eastern United States 
that significantly affect the ability of downwind states to attain and 
maintain compliance with the 1997 and 2006 fine particulate matter 
national ambient air quality standards (NAAQS) and the 1997 ozone 
NAAQS. Also, EPA is limiting these emissions through Federal 
Implementation Plans (FIPs) that regulate electric generating units 
(EGUs) in the 27 states. This action will substantially reduce adverse 
air quality impacts in downwind states from emissions transported 
across state lines. In conjunction with other federal and state 
actions, it will help assure that all but a handful of areas in the 
eastern part of the country achieve compliance with the current ozone 
and PM2.5 NAAQS by the deadlines established in the Clean 
Air Act (CAA or Act). The FIPs may not fully eliminate the prohibited 
emissions from certain states with respect to the 1997 ozone NAAQS for 
two remaining downwind areas and EPA is committed to identifying any 
additional required upwind emission reductions and taking any necessary 
action in a future rulemaking. In this action, EPA is also modifying 
its prior approvals of certain State Implementation Plan (SIP) 
submissions to rescind any statements that the submissions in question 
satisfy the interstate transport requirements of the CAA or that EPA's 
approval of the SIPs affects our authority to issue interstate 
transport FIPs with respect to the 1997 fine particulate and 1997 ozone 
standards for 22 states. EPA is also issuing a supplemental proposal to 
request comment on its conclusion that six additional states 
significantly affect downwind states' ability to attain and maintain 
compliance with the 1997 ozone NAAQS.

DATES: This final rule is effective on October 7, 2011.

ADDRESSES: EPA has established a docket for this action under Docket ID 
No. EPA-HQ-OAR-2009-0491. All documents in the docket are listed on the 
http://www.regulations.gov Web site. Although listed in the index, some 
information is not publicly available, e.g., 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 through http://www.regulations.gov 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 this 
action, please contact Ms. Meg Victor, Clean Air Markets Division, 
Office of Atmospheric Programs, Mail Code 6204J, Environmental 
Protection Agency, 1200 Pennsylvania Avenue, NW., Washington, DC 20460; 
telephone number: (202) 343-9193; fax number: (202) 343-2359; e-mail 
address: victor.meg@epa.gov. For legal questions, please contact Ms. 
Sonja Rodman, U.S. EPA, Office of General Counsel, Mail Code 2344A, 
1200 Pennsylvania Avenue, NW., Washington, DC 20460, telephone (202) 
564-4079; e-mail address: rodman.sonja@epa.gov.

SUPPLEMENTARY INFORMATION: 

I. Preamble Glossary of Terms and Abbreviations

    The following are abbreviations of terms used in the preamble.

AQAT Air Quality Assessment Tool
ARP Acid Rain Program
BART Best Available Retrofit Technology
BACT Best Available Control Technology
CAA or Act Clean Air Act
CAIR Clean Air Interstate Rule
CAMx Comprehensive Air Quality Model with Extensions
CBI Confidential Business Information
CCR Coal Combustion Residuals
CEM Continuous Emissions Monitoring
CENRAP Central Regional Air Planning Association
CFR Code of Federal Regulations
DEQ Department of Environmental Quality
DSI Dry Sorbent Injection
EGU Electric Generating Unit
FERC Federal Energy Regulatory Commission
FGD Flue Gas Desulfurization
FIP Federal Implementation Plan
FR Federal Register
EPA U.S. Environmental Protection Agency
GHG Greenhouse Gas
GW Gigawatts
Hg Mercury
ICR Information Collection Request
IPM Integrated Planning Model
km Kilometers
lb/mmBtu Pounds Per Million British Thermal Unit
LNB Low-NOX Burners
MACT Maximum Achievable Control Technology
MATS Modeled Attainment Test Software
[mu]g/m \3\ Micrograms Per Cubic Meter
MSAT Mobile Source Air Toxics
MOVES Motor Vehicle Emission Simulator
NAAQS National Ambient Air Quality Standards
NBP NOX Budget Trading Program
NEI National Emission Inventory
NESHAP National Emissions Standards for Hazardous Air Pollutants
NOX Nitrogen Oxides
NODA Notices of Data Availability
NSPS New Source Performance Standard
NSR New Source Review
OFA Overfire Air
OSAT Ozone Source Apportionment Technique
OTAG Ozone Transport Assessment Group
ppb Parts Per Billion
PM2.5 Fine Particulate Matter, Less Than 2.5 Micrometers
PM10 Fine and Coarse Particulate Matter, Less Than 10 
Micrometers
PM Particulate Matter
ppm Parts Per Million
PUC Public Utility Commission
RIA Regulatory Impact Analysis
SCR Selective Catalytic Reduction
SIP State Implementation Plan
SMOKE Sparse Matrix Operator Kernel Emissions
SNCR Selective Non-catalytic Reduction
SO2 Sulfur Dioxide
SOX Sulfur Oxides, Including Sulfur Dioxide 
(SO2) and Sulfur Trioxide (SO3)
TAF Terminal Area Forecast
TCEQ Texas Commission on Environmental Quality
TIP Tribal Implementation Plan
TLN3 Tangential Low NOX
TPY Tons Per Year
TSD Technical Support Document
WRAP Western Regional Air Partnership

II. General Information

A. Does this action apply to me?

    This rule affects EGUs, and regulates the following groups:

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                    Industry group                          NAICS a
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Utilities (electric, natural gas, other systems.)....   2211, 2212, 2213
------------------------------------------------------------------------
a North American Industry Classification System.

    This table is not intended to be exhaustive, but rather provides a 
guide for readers regarding entities likely to be regulated by this 
action. This table lists

[[Page 48209]]

the types of entities that EPA is aware of that could potentially be 
regulated. Other types of entities not listed in the table could also 
be regulated. To determine whether your facility would be regulated by 
the proposed rule, you should carefully examine the applicability 
criteria in proposed Sec. Sec.  97.404, 97.504, and 97,604.

B. How is the preamble organized?

I. Preamble Glossary of Terms and Abbreviations
II. General Information
    A. Does this action apply to me?
    B. How is the preamble organized?
III. Executive Summary
IV. Legal Authority, Environmental Basis, and Correction of CAIR SIP 
Approvals
    A. EPA's Authority for Transport Rule
    B. Rulemaking History
    C. Air Quality Problems and NAAQS Addressed
    1. Air Quality Problems and NAAQS Addressed
    2. FIP Authority for Each State and NAAQS Covered
    3. Additional Information Regarding CAA Section 
110(a)(2)(D)(i)(I) SIPs for States in the Transport Rule Modeling 
Domain
    D. Correction of CAIR SIP Approvals
V. Analysis of Downwind Air Quality and Upwind State Emissions
    A. Pollutants Regulated
    1. Background
    2. Which pollutants did EPA propose to control for purposes of 
PM2.5 and Ozone Transport?
    3. Comments and Responses
    B. Baseline for Pollution Transport Analysis
    C. Air Quality Modeling to Identify Downwind Nonattainment and 
Maintenance Receptors
    1. Emission Inventories
    2. Air Quality Basis for Identifying Receptors
    3. How did EPA project future nonattainment and maintenance for 
annual PM2.5, 24-hour PM2.5, and 8-hour ozone?
    D. Pollution Transport From Upwind States
    1. Choice of Air Quality Thresholds
    2. Approach for Identifying Contributing Upwind States
VI. Quantification of State Emission Reductions Required
    A. Cost and Air Quality Structure for Defining Reductions
    1. Summary
    2. Background
    B. Cost of Available Emission Reductions (Step 1)
    1. Development of Annual NOX and Ozone-Season 
NOX Cost Curves
    2. Development of SO2 Cost Curves
    3. Amount of Reductions That Could Be Achieved by 2012 and 2014
    C. Estimates of Air Quality Impacts (Step 2)
    1. Development of the Air Quality Assessment Tool and Air 
Quality Modeling Strategy
    2. Utilization of AQAT to Evaluate Control Scenarios
    3. Air Quality Assessment Results
    D. Multi-Factor Analysis and Determination of State Emission 
Budgets
    1. Multi-Factor Analysis (Step 3)
    2. State Emission Budgets (Step 4)
    E. Approach to Power Sector Emission Variability
    1. Introduction to Power Sector Variability
    2. Transport Rule Variability Limits
    F. Variability Limits and State Emission Budgets: State 
Assurance Levels
    G. How the State Emission Reduction Requirements Are Consistent 
With Judicial Opinions Interpreting the Clean Air Act
VII. FIP Program Structure to Achieve Reductions
    A. Overview of Air Quality-Assured Trading Programs
    B. Applicability
    C. Compliance Deadlines
    1. Alignment With NAAQS Attainment Deadlines
    2. Compliance and Deployment of Pollution Control Technologies
    D. Allocation of Emission Allowances
    1. Allocations to Existing Units
    2. Allocations to New Units
    E. Assurance Provisions
    F. Penalties
    G. Allowance Management System
    H. Emissions Monitoring and Reporting
    I. Permitting
    1. Title V Permitting
    2. New Source Review
    J. How the Program Structure Is Consistent With Judicial 
Opinions Interpreting the Clean Air Act
VIII. Economic Impacts of the Transport Rule
    A. Emission Reductions
    B. The Impacts on PM2.5 and Ozone of the Final 
SO2 and NOX Strategy
    C. Benefits
    1. Human Health Benefit Analysis
    2. Quantified and Monetized Visibility Benefits
    3. Benefits of Reducing GHG Emissions
    4. Total Monetized Benefits
    5. How do the benefits in 2012 compare to 2014?
    6. How do the benefits compare to the costs of this final rule?
    7. What are the unquantified and non-monetized benefits of the 
Transport Rule emission reductions?
    D. Costs and Employment Impacts
    1. Transport Rule Costs and Employment Impacts
    2. End-Use Energy Efficiency
IX. Related Programs and the Transport Rule
    A. Transition From the Clean Air Interstate Rule
    1. Key Differences Between the Transport Rule and CAIR
    2. Transition From the Clean Air Interstate Rule to the 
Transport Rule
    B. Interactions With NOX SIP Call
    C. Interactions With Title IV Acid Rain Program
    D. Other State Implementation Plan Requirements
X. Transport Rule State Implementation Plans
XI. Structure and Key Elements of Transport Rule Air Quality-Assured 
Trading Program Rules
XII. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review and 
Executive Order 13563: Improving Regulation and Regulatory Review
    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 and Advancement Act
    J. Executive Order 12898: Federal Actions To Address 
Environmental Justice in Minority Populations and Low-Income 
Populations
    1. Consideration of Environmental Justice in the Transport Rule 
Development Process and Response to Comments
    2. Potential Environmental and Public Health Impacts Among 
Populations Susceptible or Vulnerable to Air Pollution
    3. Meaningful Public Participation
    4. Summary
    K. Congressional Review Act
    L. Judicial Review

III. Executive Summary

    The CAA section 110(a)(2)(D)(i)(I) requires states to prohibit 
emissions that contribute significantly to nonattainment in, or 
interfere with maintenance by, any other state with respect to any 
primary or secondary NAAQS. In this final rule, EPA finds that 
emissions of SO2 and NOX in 27 eastern, 
midwestern, and southern states contribute significantly to 
nonattainment or interfere with maintenance in one or more downwind 
states with respect to one or more of three air quality standards--the 
annual PM2.5 NAAQS promulgated in 1997, the 24-hour 
PM2.5 NAAQS promulgated in 2006, and the ozone NAAQS 
promulgated in 1997 (EPA uses the term ``states'' to include the 
District of Columbia in this preamble).
    These emissions are transported downwind either as SO2 
and NOX or, after transformation in the atmosphere, as fine 
particles or ozone. This final rule identifies emission reduction 
responsibilities of upwind states, and also promulgates enforceable 
FIPs to achieve the required emission reductions in each state through 
cost-effective and flexible requirements for power plants. Each state 
has the option of replacing these federal rules with state rules to 
achieve the required amount of emission reductions from sources 
selected by the state.

[[Page 48210]]

    Section 110(a)(2)(D)(i)(I) of the CAA requires the elimination of 
upwind state emissions that significantly contribute to nonattainment 
or interfere with maintenance of a NAAQS in another state. Elimination 
of these upwind state emissions may not necessarily, in itself, fully 
resolve nonattainment or maintenance problems at downwind state 
receptors. Downwind states also have control responsibilities because, 
among other things, the Act requires each state to adopt enforceable 
plans to attain and maintain air quality standards. Indeed, states have 
put in place measures to reduce local emissions that contribute to 
nonattainment within their borders. Section 110(a)(2)(D)(i)(I) only 
requires the elimination of emissions that significantly contribute to 
nonattainment or interfere with maintenance of the NAAQS in other 
states; it does not shift to upwind states the responsibility for 
ensuring that all areas in other states attain the NAAQS.
    The reductions obtained through the Transport Rule will help all 
but a few downwind areas come into attainment with and maintain the 
1997 annual PM2.5 NAAQS, the 2006 24-hour PM2.5 
NAAQS, and the 1997 ozone NAAQS. With respect to the annual 
PM2.5 NAAQS, this rule finds that 18 states have 
SO2 and annual NOX emission reduction 
responsibilities, and this rule quantifies each state's full emission 
reduction responsibility under section 110(a)(2)(D)(i)(I). See Table 
III-1 for the list of these states. With these reductions, EPA projects 
that no areas will have nonattainment or maintenance concerns with 
respect to the annual PM2.5 NAAQS.
    With respect to the 24-hour PM2.5 NAAQS, this rule finds 
that 21 states have SO2 and annual NOX emission 
reduction responsibilities, and this rule quantifies each state's full 
emission reduction responsibility under 110(a)(2)(D)(i)(I). See Table 
III-1 for the list of these states. In all, this rule requires emission 
reductions related to interstate transport of fine particles in 23 
states. With these reductions, as discussed in section VI.D of this 
preamble, only one area (Liberty-Clairton) is projected to remain in 
nonattainment, and three other areas (Chicago,\1\ Detroit, and 
Lancaster) are projected to have remaining maintenance concerns for the 
24-hour PM2.5 NAAQS.
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    \1\ This area is not currently designated as nonattainment for 
the 24-hour PM2.5 standard. EPA is portraying the 
receptors and counties in this area as a single 24-hour maintenance 
area based on the annual PM2.5 nonattainment designation 
of Chicago-Gary-Lake County, IL-IN.
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    With respect to the 1997 ozone NAAQS, this rule finds that 20 
states have ozone-season NOX emission reduction 
responsibilities. For 10 of these states this rule quantifies the 
state's full emission reduction responsibility under section 
110(a)(2)(D)(i)(I).\2\ For 10 additional states, EPA quantifies in this 
rule the ozone-season NOX emission reductions that are 
necessary but may not be sufficient to eliminate all significant 
contribution to nonattainment and interference with maintenance in 
other states.\3\ See Table III-1 for the complete list of 20 states 
required to reduce ozone-season NOX emissions in this rule. 
With the Transport Rule reductions, only one area (Houston) is 
projected to remain in nonattainment, and one area (Baton Rouge) to 
have a remaining maintenance concern with respect to the 1997 ozone 
NAAQS. The 10 states upwind of either of these two areas are the states 
for which additional reductions may be necessary to fully eliminate 
each state's significant contribution to nonattainment and interference 
with maintenance, as discussed in section VI of this preamble.\4\
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    \2\ The 10 states for which this rule quantifies the state's 
full responsibility under section 110(a)(2)(D)(i)(I) with respect to 
the 1997 ozone NAAQS are Florida, Maryland, New Jersey, New York, 
North Carolina, Ohio, Pennsylvania, South Carolina, Virginia, and 
West Virginia.
    \3\ The 10 states for which this rule quantifies reductions that 
are necessary but may not be sufficient to satisfy the requirements 
of 110(a)(2)(D)(i)(I) with respect to the 1997 ozone NAAQS are 
Alabama, Arkansas, Georgia, Illinois, Indiana, Kentucky, Louisiana, 
Mississippi, Tennessee, and Texas.
    \4\ This preamble uses the term ``significant contribution'' 
only in the context of the CAA section 110(a)(2)(D)(i)(I) 
requirement that states prohibit emissions that ``contribute 
significantly to nonattainment'' in any other state with respect to 
any primary or secondary NAAQS. Thus, a significant contribution, as 
used in this preamble, is one that is significant for purposes of 
CAA section 110(a)(2)(D)(i)(I) as coming from a particular state.
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    As discussed further below, EPA's analysis also demonstrates that 
six additional states should be required to reduce ozone-season 
NOX emissions. EPA is issuing a supplemental proposal to 
request comment on requiring ozone-season NOX reductions in 
these six states. For five of these six states, EPA's analysis 
identifies the state's full emission reduction responsibility under 
section 110(a)(2)(D)(i)(I), and for the remaining one state EPA's 
analysis identifies reductions that are necessary but may not be 
sufficient to satisfy the requirements of 110(a)(2)(D)(i)(I).\5\
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    \5\ The five states addressed in the supplemental proposal for 
which EPA's analysis identifies the state's full reduction 
responsibility under section 110(a)(2)(D)(i)(I) with respect to the 
1997 ozone NAAQS are Iowa, Kansas, Michigan, Oklahoma, and 
Wisconsin. The one state addressed in the supplemental proposal for 
which EPA's analysis identifies reductions that are necessary but 
may not be sufficient to satisfy section 110(a)(2)(D)(i)(I) with 
respect to the 1997 ozone NAAQS is Missouri.
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    On January 19, 2010, EPA proposed revisions to the 8-hour ozone 
NAAQS that the Agency had issued March 12, 2008 (75 FR 2938); the 
Agency intends to finalize its reconsideration in the summer of 2011. 
EPA intends to propose a rule to address transport with respect to the 
reconsidered 2008 ozone NAAQS as expeditiously as possible after 
reconsideration is completed. EPA intends to include in that proposed 
rule requirements to address any remaining significant contribution to 
nonattainment and interference with maintenance with respect to the 
1997 ozone NAAQS for the states identified in this final rule, or the 
associated supplemental notice of proposed rulemaking, for which EPA 
was unable to fully quantify the emissions that must be prohibited to 
satisfy the requirements of 110(a)(2)(D)(i)(I) with respect to the 1997 
ozone NAAQS.
    The Act requires EPA to conduct periodic reviews of each of the 
NAAQS. When NAAQS are set or revised, the CAA requires revision of SIPs 
to ensure the standards are met expeditiously and within relevant 
timetables in the Act. If more protective NAAQS are promulgated, in the 
case of pollutants for which interstate transport is important, 
additional emission reductions to address transported pollution may be 
required from the power sector, from other sectors, and from sources in 
additional states. EPA will act promptly to promulgate any future rules 
addressing transport with respect to revised NAAQS.
    The Transport Rule requires substantial near-term emission 
reductions in every covered state to address each state's significant 
contribution to nonattainment and interference with maintenance 
downwind. This rule achieves these reductions through FIPs that 
regulate the power sector using air quality-assured trading programs 
whose assurance provisions ensure that necessary reductions will occur 
within every covered state. This remedy structure is substantially 
similar to the preferred trading remedy structure presented in the 
proposal. The Transport Rule's air quality-assured trading approach 
will assure

[[Page 48211]]

environmental results in each state while providing market-based 
flexibility to covered sources through interstate trading. The final 
rule includes four air quality-assured trading programs: An annual 
NOX trading program, an ozone-season NOX trading 
program, and two separate SO2 trading programs 
(``SO2 Group 1'' and ``SO2 Group 2''), as 
discussed further in sections VI and VII, below.
    The first phase of Transport Rule compliance commences January 1, 
2012, for SO2 and annual NOX reductions and May 
1, 2012, for ozone-season NOX reductions. The second phase 
of Transport Rule reductions, which commences January 1, 2014, 
increases the stringency of SO2 reductions in a number of 
states as discussed further below.
    EPA projects that with the Transport Rule, covered EGU will 
substantially reduce SO2, annual NOX and ozone-
season NOX emissions, as shown in Tables III-2 and III-3, 
below. This rule generally covers electric generating units that are 
fossil fuel-fired boilers and turbines producing electricity for sale, 
as detailed in section VII.B.
    EPA is promulgating the Transport Rule in response to the remand of 
the Clean Air Interstate Rule (CAIR) by the U.S. Court of Appeals for 
the District of Columbia Circuit (``Court'') in 2008. CAIR, promulgated 
May 12, 2005 (70 FR 25162), required 29 states to adopt and submit 
revisions to their State Implementation Plans (SIPs) to eliminate 
SO2 and NOX emissions that contribute 
significantly to downwind nonattainment of the PM2.5 and 
ozone NAAQS promulgated in July 1997. CAIR covered a similar but not 
identical set of states as the Transport Rule. CAIR FIPs were 
promulgated April 26, 2006 (71 FR 25328) to regulate electric 
generating units in the covered states and achieve the emission 
reduction requirements established by CAIR until states could submit 
and obtain approval of SIPs to achieve the reductions.
    In July 2008, the Court found CAIR and the CAIR FIPs unlawful. 
North Carolina v. EPA, 531 F.3d 896 (D.C. Cir. 2008), modified on 
rehearing, North Carolina v. EPA, 550 F.3d 1176, 1178 (D.C. Cir. 2008). 
The Court's original decision vacated CAIR. North Carolina, 531 F.3d at 
929-30. However, the Court subsequently remanded CAIR to EPA without 
vacatur because it found that ``allowing CAIR to remain in effect until 
it is replaced by a rule consistent with our opinion would at least 
temporarily preserve the environmental values covered by CAIR.'' North 
Carolina, 550 F.3d at 1178. The CAIR requirements have remained in 
place while EPA has developed the Transport Rule to replace them.
    EPA's approach in the Transport Rule to measure and address each 
state's significant contribution to downwind nonattainment and 
interference with maintenance is guided by and consistent with the 
Court's opinion in North Carolina and addresses the flaws in CAIR 
identified by the Court therein. This final rule also responds to 
extensive public comments and stakeholder input received during the 
public comment periods in response to the proposal and subsequent 
Notices of Data Availability (NODAs).
    In this action, EPA both identifies and addresses emissions within 
states that significantly contribute to nonattainment or interfere with 
maintenance in other downwind states. In developing this rule, EPA used 
a state-specific methodology to identify emission reductions that must 
be made in covered states to address the CAA section 110(a)(2)(D)(i)(I) 
prohibition on emissions that significantly contribute to nonattainment 
or interfere with maintenance in a downwind state. EPA believes this 
methodology addresses the Court's concern that the approach used in 
CAIR was insufficiently state-specific. EPA used detailed air quality 
analysis to determine whether a state's contribution to downwind air 
quality problems is at or above specific thresholds. A state is covered 
by the Transport Rule if its contribution meets or exceeds one of those 
air quality thresholds and the Agency identifies, using a multi-factor 
analysis that takes into account both air quality and cost 
considerations, emissions within the state that constitute the state's 
significant contribution to nonattainment and interference with 
maintenance with respect to the 1997 ozone or the 1997 annual or 2006 
24-hour PM2.5 NAAQS. Section 110(a)(2)(D)(i)(I) requires 
states to eliminate the emissions that constitute this ``significant 
contribution'' and ``interference with maintenance.'' \6\
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    \6\ In this preamble, EPA uses the terms ``significant 
contribution'' and ``interference with maintenance'' to refer to the 
emissions that must be prohibited pursuant to section 
110(a)(2)(D)(i)(I) because they significantly contribute to 
nonattainment or interfere with maintenance of the NAAQS in another 
state.
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    In this final rule, EPA determined the emission reductions required 
from all upwind states to eliminate significant contribution to 
nonattainment and interference with maintenance with respect to the 
1997 ozone, 1997 annual PM2.5, and 2006 24-hour 
PM2.5 NAAQS, using, in part, an assessment of modeled air 
quality in 2012 and 2014. EPA first identified the following two sets 
of downwind receptors: (1) Receptors that EPA projects will have 
nonattainment problems; and, (2) receptors that EPA projects may have 
difficulty maintaining the NAAQS based on historic variation in air 
quality. To identify areas that may have problems attaining or 
maintaining these air quality standards, EPA projected a suite of 
future air quality design values, based on measured data during the 
period 2003 through 2007. EPA used the average of these future design 
values to assess whether an area will be in nonattainment. EPA used the 
maximum projected future design value to assess whether an area may 
have difficulty maintaining the relevant NAAQS (i.e., whether an area 
has a reasonable possibility of being in nonattainment under adverse 
emission and weather conditions). Section V.C of this preamble details 
the Transport Rule's approach to identify downwind nonattainment and 
maintenance areas.
    After identifying downwind nonattainment and/or maintenance areas, 
EPA next used air quality modeling to determine which upwind states are 
projected to contribute at or above threshold levels to the air quality 
problems in those areas. Section V.D details the choice of air quality 
thresholds and the approach to determine how much each upwind state 
contributes. States whose contributions meet or exceed the threshold 
levels were analyzed further, as detailed in section VI, to determine 
whether they significantly contribute to nonattainment or interfere 
with maintenance of a relevant NAAQS, and if so, the quantity of 
emissions that constitute their significant contribution and 
interference with maintenance.
    When EPA proposed this air-quality and cost-based multi-factor 
approach to identify emissions that constitute significant contribution 
to nonattainment and interference with maintenance from upwind states 
with respect to the 1997 ozone, annual PM2.5, and 2006 24-
hour PM2.5 NAAQS, the Agency indicated that the approach was 
designed to be applicable to both current and potential future ozone 
and PM2.5 NAAQS (75 FR 45214). EPA believes that the 
Transport Rule's approach of using air-quality thresholds to determine 
upwind-to-downwind-state linkages and using the air-quality and cost-
based multi-factor approach to determine the quantity of emissions that 
each upwind state must eliminate, i.e., the state's significant 
contribution to nonattainment and interference with maintenance, could 
serve as a precedent for quantifying upwind state emission reduction 
responsibilities with respect

[[Page 48212]]

to potential future NAAQS, as discussed further in section VI.A of this 
preamble. The Agency further believes that the final Transport Rule 
demonstrates the strong value of this approach for addressing the role 
of interstate transport of air pollution in communities' ability to 
comply with current and future NAAQS.
    EPA thus identified specific emission reduction responsibilities 
for each upwind state found to significantly contribute to 
nonattainment or interfere with maintenance in other states. Using that 
information, EPA developed individual state budgets for emissions from 
covered units under the Transport Rule. The Transport Rule emission 
budgets are based on EPA's state-by-state analysis of each upwind 
state's significant contribution to nonattainment and interference with 
maintenance. Because each state's budget is directly linked to this 
state-specific analysis of the state's obligations pursuant to section 
110(a)(2)(D)(i)(I), this approach addresses the Court's concerns about 
the development of CAIR budgets.
    In this rule, EPA is finalizing SO2 and annual 
NOX budgets for each state covered for the 24-hour and/or 
annual PM2.5 NAAQS and an ozone-season NOX budget 
for each state covered for the ozone NAAQS. A state's emission budget 
is the quantity of emissions that will remain from covered units under 
the Transport Rule after elimination of significant contribution to 
nonattainment and interference with maintenance in an average year 
(i.e., before accounting for the inherent variability in power system 
operations).\7\
---------------------------------------------------------------------------

    \7\ For the states discussed above for which EPA has quantified 
the minimum amount of emission reductions needed to make measurable 
progress toward satisfying the state's section 110(a)(2)(D)(i)(I) 
responsibility, the emission budget is the quantity of emissions 
that will remain from covered units after removal of those 
emissions.
---------------------------------------------------------------------------

    Baseline power sector emissions from a state can be affected by 
changing weather patterns, demand growth, or disruptions in electricity 
supply from other units or from the transmission grid. As a 
consequence, emissions could vary from year to year even in a state 
where covered sources have installed all controls and taken all 
measures necessary to eliminate the state's significant contribution to 
nonattainment and interference with maintenance. As described in detail 
in sections VI and VII of this preamble, the Transport Rule accounts 
for the inherent variability in power system operations through 
``assurance provisions'' based on state-specific variability limits 
which extend above the state budgets to form each state's ``assurance 
level.'' The state assurance levels take into account the inherent 
variability in baseline emissions from year to year. The final 
Transport Rule FIPs will implement assurance provisions starting in 
2012 as discussed in section VII, below.
    The emission reduction requirements (i.e., the ``remedy'') EPA is 
promulgating in this rule respond to the Court's concerns that in CAIR, 
EPA had not shown that the emission reduction requirements would get 
all necessary reductions within the state as required by section 
110(a)(2)(D)(i)(I). The Transport Rule FIPs include assurance 
provisions specifically designed to ensure that no state's emissions 
are allowed to exceed that specific state's budget plus the variability 
limit (i.e., the state's assurance level).
    Each state's Transport Rule SO2, annual NOX, 
or ozone-season NOX emission budget is composed of a number 
of emission allowances (``allowances'') equivalent to the tonnage of 
that specific state budget. Under the Transport Rule FIPs, EPA is 
distributing (``allocating'') allowances under each state's budget to 
covered units in that state. In this rule, EPA analyzed each individual 
state's significant contribution to nonattainment and interference with 
maintenance and calculated budgets that represent each state's 
emissions after the elimination of those prohibited emissions in an 
average year. The methodology used to allocate allowances to individual 
units in a particular state has no impact on that state's budget or on 
the requirement that the state's emissions not exceed that budget plus 
the variability limit; the allocation methodology therefore has no 
impact on the rule's ability to satisfy the statutory mandate of CAA 
section 110(a)(2)(D)(i)(I).
    The Transport Rule's approach to allocate emission allowances to 
existing units is based on historic heat-input data, as detailed in 
section VII.D of this preamble. The Transport Rule SO2, 
annual NOX, and ozone-season NOX emission 
allowances each authorize the emission of one ton of SO2, 
annual NOX, or ozone-season NOX emissions, 
respectively, during a Transport Rule control period, and are the 
currency in the Transport Rule's air quality-assured trading programs. 
As discussed in section IX.A.2 below, EPA is creating these Transport 
Rule allowances as distinct compliance instruments with no relation to 
allowances from the CAIR trading programs. EPA agrees with the general 
principle that it is desirable, where possible, to provide continuity 
under successive regulatory trading programs, for example through the 
carryover of allowances from one program into a subsequent one. 
However, EPA is promulgating the Transport Rule as a court-ordered 
replacement for (not a successor to) CAIR's trading programs. In light 
of the specific circumstances of this case, including legal and 
technical issues discussed in Section IX.A.2 below, the final rule will 
not allow any carryover of banked SO2 or NOX 
allowances from the Title IV or CAIR trading programs. EPA will 
strongly consider administrative continuity of this rule's trading 
programs under any future actions designed to address related problems 
of interstate transport of air pollution. A state may submit a SIP 
revision under which the state (rather than EPA) would determine 
allocations for one or more of the Transport Rule trading programs 
beginning with vintage year 2013 or later allowances.\8\ Section X of 
this preamble discusses the final rule's provisions for SIP submissions 
in detail.
---------------------------------------------------------------------------

    \8\ This final rule allows states to make 2013 allowance 
allocations through the use of a SIP revision that is narrower in 
scope than the other SIP revisions states can use to replace the 
FIPs and/or to make allocation decisions for 2014 and beyond, as 
discussed in section X.
---------------------------------------------------------------------------

    Table III-1 lists states covered by the Transport Rule for 
PM2.5 and ozone. It also, with respect to PM2.5, 
identifies whether EPA determined the state was significantly 
contributing to nonattainment or interfering with maintenance of the 
1997 annual PM2.5 NAAQS, the 2006 24-hour PM2.5 
NAAQS, or both. As discussed below, the Transport Rule sorts the states 
required to reduce SO2 emissions due to their contribution 
to PM2.5 downwind into two groups of varying reduction 
stringency, with ``Group 1'' states subject to greater SO2 
reduction stringency than ``Group 2'' states starting in 2014. Table 
III-1 also lists which SO2 Group each of the states is in.

[[Page 48213]]

   Table III-1--States That Significantly Contribute to Nonattainment or Interfere With Maintenance of a NAAQS
                                      Downwind in the Final Transport Rule
----------------------------------------------------------------------------------------------------------------
                                                         1997 Annual PM2.5     2006 24-Hour
                State                  1997 Ozone NAAQS        NAAQS           PM2.5 NAAQS         SO2 group
----------------------------------------------------------------------------------------------------------------
Alabama.............................                 X                  X                  X                  2
Arkansas............................                 X   .................  .................  .................
Florida.............................                 X   .................  .................  .................
Georgia.............................                 X                  X                  X                  2
Illinois............................                 X                  X                  X                  1
Indiana.............................                 X                  X                  X                  1
Iowa................................  .................                 X                  X                  1
Kansas..............................  .................  .................                 X                  2
Kentucky............................                 X                  X                  X                  1
Louisiana...........................                 X   .................  .................  .................
Maryland............................                 X                  X                  X                  1
Michigan............................  .................                 X                  X                  1
Minnesota...........................  .................  .................                 X                  2
Mississippi.........................                 X   .................  .................  .................
Missouri............................  .................                 X                  X                  1
Nebraska............................  .................  .................                 X                  2
New Jersey..........................                 X   .................                 X                  1
New York............................                 X                  X                  X                  1
North Carolina......................                 X                  X                  X                  1
Ohio................................                 X                  X                  X                  1
Pennsylvania........................                 X                  X                  X                  1
South Carolina......................                 X                  X   .................                 2
Tennessee...........................                 X                  X                  X                  1
Texas...............................                 X                  X   .................                 2
Virginia............................                 X   .................                 X                  1
West Virginia.......................                 X                  X                  X                  1
Wisconsin...........................  .................                 X                  X                  1
Number of States....................                20                 18                 21   .................
----------------------------------------------------------------------------------------------------------------

    As explained in this preamble, EPA has improved and updated both 
steps of its significant contribution analysis. It updated and improved 
the modeling platforms and modeling inputs used to identify states with 
contributions to certain downwind receptors that meet or exceed 
specified thresholds. It also updated and improved its analysis for 
identifying any emissions within such states that constitute the 
state's significant contribution to nonattainment or interference with 
maintenance. Therefore, the results of the analysis conducted for the 
final rule differ somewhat from the results of the analysis conducted 
for the proposal.\9\
---------------------------------------------------------------------------

    \9\ EPA updated its modeling platforms and modeling inputs in 
response to public comments received on the proposed Transport Rule 
and subsequent NODAs and performed other standard updates.
---------------------------------------------------------------------------

    With respect to the 1997 ozone NAAQS, the analysis EPA conducted 
for the proposal did not identify Wisconsin, Iowa and Missouri as 
states that significantly contribute to nonattainment or interfere with 
maintenance of the ozone NAAQS in another state. However, the analysis 
conducted for the final rule shows that emissions from these states do 
significantly contribute to nonattainment or interfere with maintenance 
of the ozone NAAQS in another state. EPA is not issuing FIPs with 
respect to the 1997 ozone NAAQS or finalizing ozone season 
NOX budgets for these states in this rule. EPA is publishing 
a supplemental notice of proposed rulemaking that will provide an 
opportunity for public comment on our conclusion that these states 
significantly contribute to nonattainment or interfere with maintenance 
of the 1997 ozone NAAQS.
    In the other direction, the analysis conducted for the proposal 
supported EPA's conclusion at the time that Connecticut, Delaware, and 
the District of Columbia significantly contributed to nonattainment or 
interfered with maintenance with respect to the 1997 ozone NAAQS, 
whereas the modeling for the final rule no longer supports that 
conclusion for those states.
    Additionally, the modeling conducted for the final rule identified 
two ozone maintenance receptors that were not identified in the 
modeling conducted for the proposal--Allegan County (MI) and Harford 
County (MD). Five states that EPA identified as significantly 
contributing to maintenance problems at the Allegan and/or Harford 
County receptors in the modeling for the final rule uniquely contribute 
to these receptors, i.e., absent these receptors the states would not 
be covered by the Transport Rule ozone-season program. The five states 
that uniquely contribute to these receptors are Iowa, Kansas, Michigan, 
Oklahoma, and Wisconsin. EPA is not issuing FIPs with respect to the 
1997 ozone NAAQS or finalizing ozone-season NOX budgets for 
these states in this rule. EPA is publishing a supplemental notice of 
proposed rulemaking that will provide an opportunity for public comment 
on our conclusion that these states significantly contribute to 
nonattainment or interfere with maintenance of the 1997 ozone NAAQS.
    EPA did not change its methodology between the proposed Transport 
Rule and the final Transport Rule for identifying upwind states that 
significantly contribute to nonattainment or interfere with maintenance 
in other states; nor did EPA change its methodology for identifying 
receptors of concern with respect to maintenance of the 1997 ozone 
NAAQS. The final rule's air quality modeling identifies the new states 
and new receptors described above based on updated input information 
(including emission inventories), much of which was provided to EPA 
through public comment on the proposal and subsequent NODAs. Section V 
of this preamble details the approach EPA used

[[Page 48214]]

to identify contributing states and receptors of concern.
    With respect to the annual PM2.5 NAAQS, the analysis EPA 
conducted for the proposal supported EPA's conclusion that the states 
of Delaware, the District of Columbia, Florida, Louisiana, Minnesota, 
New Jersey, and Virginia were significantly contributing to 
nonattainment and interfering with maintenance of the annual 
PM2.5 NAAQS while the final rule's analysis does not. Also, 
with respect to the 24-hour PM2.5 NAAQS, the analysis 
conducted for the proposal supported EPA's conclusion that the states 
of Connecticut, Delaware, the District of Columbia, and Massachusetts 
were significantly contributing to nonattainment or interfering with 
maintenance in other states while the analysis conducted for the final 
rule did not.
    In the proposal EPA also requested comment on whether Texas should 
be included in the Transport Rule for annual PM2.5. EPA's 
analysis for the proposal showed that emissions in Texas would 
significantly contribute to nonattainment or interfere with maintenance 
of the annual PM2.5 NAAQS if Texas were not included in the 
rule for PM2.5. The proposal did not include an illustrative 
budget for Texas or illustrative allowance allocations. However, the 
budgets and allowance allocations provided for other states in the 
proposal were included solely to illustrate the result of applying 
EPA's proposed methodology for quantifying significant contribution to 
the data EPA proposed to use. EPA provided an ample opportunity for 
comment on this methodology and on the data, including data regarding 
emissions from Texas sources, used in the significant contribution 
analysis. EPA received numerous comments on and corrections to Texas-
specific data. The modeling conducted for the final rule demonstrates 
that Texas significantly contributes to nonattainment or interferes 
with maintenance of the annual PM2.5 NAAQS in another state. 
EPA provided a full opportunity for comment on whether Texas should be 
included in the rule for annual PM2.5, as well as on the 
methodology and data used for the significant contribution analysis for 
the final rule. EPA therefore believes its determination that Texas 
must be included in the rule for annual PM2.5 is a logical 
outgrowth of its proposal.
    With respect to the 24-hour PM2.5 NAAQS, the analysis 
EPA conducted for the proposal did not identify Texas as a state that 
significantly contributes to nonattainment or interferes with 
maintenance of 24-hour PM2.5 in another state. However, the 
analysis conducted for the final rule shows that emissions from Texas 
do significantly contribute to nonattainment of the 24-hour 
PM2.5 NAAQS in another state. EPA is not issuing a FIP for 
Texas with respect to the 24-hour PM2.5 NAAQS in this rule. 
However, EPA believes that the FIP for Texas with respect to the 1997 
annual PM2.5 NAAQS also addresses the emissions in Texas 
that significantly contribute to nonattainment and interference with 
maintenance of the 2006 24-hour PM2.5 NAAQS in another 
state.
    The final rule, however, does not cover the states of Connecticut, 
Delaware, the District of Columbia, Florida, Louisiana, or 
Massachusetts for annual or 24-hour PM2.5 as the analysis 
for the final rule does not support their inclusion.
    The Transport Rule FIPs require the 23 states covered for purposes 
of the 24-hour and/or annual PM2.5 NAAQS to reduce 
SO2 and annual NOX emissions by specified 
amounts. The FIPs require the 20 states covered for purposes of the 
ozone NAAQS to reduce ozone-season NOX emissions by 
specified amounts. As discussed in detail in section VI, below, the 23 
states covered for the 24-hour and/or annual PM2.5 NAAQS are 
grouped in two tiers reflecting the stringency of SO2 
reductions required to eliminate that state's significant contribution 
to nonattainment and interference with maintenance downwind. The more-
stringent SO2 tier (``Group 1'') is comprised of the 16 
states indicated in Table III-1, above, and the less-stringent 
SO2 tier (``Group 2'') is comprised of the 7 states 
identified in the table. The two SO2 trading programs are 
exclusive, i.e., a covered source in a Group 1 state may use only a 
Group 1 allowance for compliance, and likewise a source in a Group 2 
state may use only a Group 2 allowance for compliance. In Group 1 
states, the SO2 reduction requirements become more stringent 
in the second phase, which starts in 2014.
    In response to the Court's opinion in North Carolina, EPA has 
coordinated the Transport Rule's compliance deadlines with the NAAQS 
attainment deadlines that apply to the downwind nonattainment and 
maintenance areas. The Transport Rule requires that all significant 
contribution to nonattainment and interference with maintenance 
identified in this action with respect to the 1997 annual 
PM2.5 NAAQS and the 2006 24-hour PM2.5 NAAQS be 
eliminated by no later than 2014, with an initial phase of reductions 
starting in 2012 to ensure that reductions are made as expeditiously as 
practicable and, consistent with the Court's remand, to ``preserve the 
environmental values covered by CAIR.'' Sources must comply by January 
1, 2012 and January 1, 2014 for the first and second phases, 
respectively.
    With respect to the 1997 ozone NAAQS, the Transport Rule requires 
NOX reductions starting in 2012 to ensure that reductions 
are made as expeditiously as practicable to assist downwind state 
attainment and maintenance of the standard. Sources must comply by May 
1, 2012. The Transport Rule's compliance schedule and alignment with 
downwind NAAQS attainment deadlines are discussed in detail in section 
VII below.
    Table III-2 shows projected Transport Rule emissions compared to 
projected base case emissions, and Table III-3 shows projected 
Transport Rule emissions compared to historical emissions (i.e., 2005 
emissions), for the power sector in all Transport Rule states. The 
ozone-season NOX results shown in Tables III-2 and III-3 are 
based on analysis of the group of 26 states that would be covered for 
the ozone-season program if EPA finalizes the supplemental proposal 
regarding ozone-season requirements for Iowa, Kansas, Michigan, 
Missouri, Oklahoma, and Wisconsin.

 Table III-2--Projected SO2 and NOX Electric Generating Unit Emission Reductions in Covered States With the Transport Rule Compared to Base Case Without
                                                                Transport Rule or CAIR **
                                                                     [Million tons]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                          2012 Base case  2012 Transport   2012 Emission  2014 Base case  2014 Transport   2014 Emission
                                                             emissions    rule emissions    reductions       emissions    rule emissions    reductions
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO2.....................................................             7.0             3.0             4.0             6.2             2.4             3.9
Annual NOX..............................................             1.4             1.3             0.1             1.4             1.2             0.2

[[Page 48215]]

 
Ozone-Season NOX........................................             0.7             0.6             0.1             0.7             0.6             0.1
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Note that numbers may not sum exactly due to rounding.
** As explained in section V.B, EPA's base case projections for the Transport Rule assume that CAIR is not in place.

    Notes: The SO2 and annual NOX emissions in 
this table reflect EGUs in the 23 states covered by this rule for 
purposes of the 24-hour and/or annual PM2.5 NAAQS 
(Alabama, Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky, 
Maryland, Michigan, Minnesota, Missouri, Nebraska, New Jersey, New 
York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, 
Texas, Virginia, West Virginia, and Wisconsin). The ozone-season 
NOX emissions reflect EGUs in the 20 states covered by 
this rule for purposes of the ozone NAAQS (Alabama, Arkansas, 
Florida, Georgia, Illinois, Indiana, Kentucky, Louisiana, Maryland, 
Mississippi, New Jersey, New York, North Carolina, Ohio, 
Pennsylvania, South Carolina, Tennessee, Texas, Virginia, and West 
Virginia) and the six states that would be covered for the ozone 
NAAQS if EPA finalizes its supplemental proposal (Iowa, Kansas, 
Michigan, Missouri, Oklahoma, and Wisconsin).

   Table III-3--Projected SO2 and NOX Electric Generating Unit Emission Reductions in Covered States With the
                                Transport Rule Compared to 2005 Actual Emissions
                                                 [Million tons]
----------------------------------------------------------------------------------------------------------------
                                                                   2012 Emission                   2014 Emission
                                    2005 Actual   2012 Transport    reductions    2014 Transport    reductions
                                     emissions    rule emissions     from 2005    rule emissions     from 2005
----------------------------------------------------------------------------------------------------------------
SO2.............................             8.8             3.0             5.8             2.4             6.4
Annual NOX......................             2.6             1.3             1.3             1.2             1.4
Ozone-Season NOX................             0.9             0.6             0.3             0.6             0.3
----------------------------------------------------------------------------------------------------------------

    Notes: The SO2 and annual NOX emissions in 
this table reflect EGUs in the 23 states covered by this rule for 
purposes of the 24-hour and/or annual PM2.5 NAAQS 
(Alabama, Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky, 
Maryland, Michigan, Minnesota, Missouri, Nebraska, New Jersey, New 
York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, 
Texas, Virginia, West Virginia, and Wisconsin). The ozone-season 
NOX emissions reflect EGUs in the 20 states covered by 
this rule for purposes of the ozone NAAQS (Alabama, Arkansas, 
Florida, Georgia, Illinois, Indiana, Kentucky, Louisiana, Maryland, 
Mississippi, New Jersey, New York, North Carolina, Ohio, 
Pennsylvania, South Carolina, Tennessee, Texas, Virginia, and West 
Virginia) and the six states that would be covered for the ozone 
NAAQS if EPA finalizes its supplemental proposal (Iowa, Kansas, 
Michigan, Missouri, Oklahoma, and Wisconsin).

    In addition to the emission reductions shown above, EPA projects 
other substantial benefits of the Transport Rule, as described in 
section VIII in this preamble. EPA used air quality modeling to 
quantify the improvements in PM2.5 and ozone concentrations 
that are expected to result from the Transport Rule emission reductions 
in 2014. The Agency used the results of this modeling to calculate the 
average and peak reduction in annual PM2.5, 24-hour 
PM2.5, and 8-hour ozone concentrations for monitoring sites 
in the Transport Rule covered states (including the six states for 
which EPA issued a supplemental proposal for ozone-season 
NOX requirements) in 2014.
    For annual PM2.5, the average reduction across all 
monitoring sites in covered states in 2014 is 1.41 microgram per meter 
cubed ([micro]g/m\3\) and the greatest reduction at a single site is 
3.60 [micro]g/m\3\. For 24-hour PM2.5, the average reduction 
across all monitoring sites in covered states in 2014 is 4.3 [micro]g/
m\3\ and the greatest reduction at a single site is 11.6 [micro]g/m\3\. 
And finally, for 8-hour ozone, the average reduction across all 
monitoring sites in covered states in 2014 is 0.3 parts per billion 
(ppb) and the greatest is 3.9 ppb. See section VIII for further 
information on air quality improvements.
    EPA estimated the Transport Rule's costs and benefits, including 
effects on sensitive and vulnerable and environmental justice 
communities. Table III-4, below, summarizes some of these results. 
Further discussion of the results is provided in preamble section VIII, 
below, and in the Regulatory Impact Analysis (RIA). Estimates here are 
subject to uncertainties discussed further in the RIA.

      Table III-4.--Summary of Annual Benefits, Costs, and Net Benefits of the Final Transport Rule in 2014
                                             [Billions of 2007$] \a\
----------------------------------------------------------------------------------------------------------------
                                                       Transport rule remedy (billions of 2007 $)
              Description              -------------------------------------------------------------------------
                                                  3% discount rate                     7% discount rate
----------------------------------------------------------------------------------------------------------------
Social costs..........................  $0.81..............................  $0.81.
Total monetized benefits \b\..........  $120 to $280.......................  $110 to $250.
Net benefits (benefits-costs).........  $120 to $280.......................  $110 to $250.
----------------------------------------------------------------------------------------------------------------
\a\ All estimates are for 2014, and are rounded to two significant figures.

[[Page 48216]]

 
\b\ The total monetized benefits reflect the human health benefits associated with reducing exposure to PM2.5
  and ozone and the welfare benefits associated with improved visibility in Class I areas. The reduction in
  premature mortalities account for over 90 percent of total monetized PM2.5 and ozone benefits.

    As a result of updated analyses and in response to public comments, 
the final Transport Rule differs from the proposal in a number of ways. 
The differences between proposal and final rule are discussed 
throughout this preamble. Some key changes between proposal and final 
rule are that EPA:
     Updated emission inventories (resulting in generally lower 
base case emissions). See section V.C.
     Updated modeling and analysis tools (including improved 
alignment between air quality estimates and air quality modeling 
results). See sections V and VI.
     Updated conclusions regarding which states significantly 
contribute to nonattainment or interfere with maintenance of the NAAQS 
in other states. See Table III-1 and sections V.D and VI.
     Recalculated state budgets and variability limits, i.e., 
state assurance levels, based on updated modeling. See section VI.
     Simplified variability limits for one-year application 
only. See section VI.E.
     Revised allocation methodology for existing and new units 
and revised new unit set-asides for new units in Transport Rule states 
and new units potentially locating in Indian country. See section 
VII.D.
     Changed start of assurance provisions to 2012 and 
increased assurance provision penalties. See section VII.E.
     Removed opt-in provisions. See section VII.B
     Added provisions for full and abbreviated Transport Rule 
SIP revisions. See section X.
    EPA conducted substantial stakeholder outreach in developing the 
Transport Rule, starting with a series of ``listening sessions'' in the 
spring of 2009 with states, nongovernmental organizations, and 
industry. EPA docketed stakeholder-related materials in the Transport 
Rule docket (Docket ID No. EPA-HQ-OAR-2009-0491). The Agency conducted 
general teleconferences on the rule with tribal environmental 
professionals, conducted consultation with tribal governments, and 
hosted a webinar for communities and tribal governments. EPA continued 
to provide updates to regulatory partners and stakeholders through 
several conference calls with states as well as at conferences where 
EPA officials often made presentations. The Agency conducted additional 
stakeholder outreach during the public comment period. EPA responded to 
extensive public comments received during the public comment periods on 
the proposed rule and associated NODAs.
    This Transport Rule is one of a series of regulatory actions to 
reduce the adverse health and environmental impacts of the power 
sector. EPA is developing these rules to address judicial review of 
previous rulemakings and to issue rules required by environmental laws. 
Finalizing these rules will effectuate health and environmental 
protection mandated by Congress while substantially reducing 
uncertainty over the future regulatory obligations of power plants, 
which will assist the power sector in planning for compliance more cost 
effectively. The Agency is providing full opportunity for notice and 
comment for each rule.
    As discussed above, rules to address transport under revised NAAQS, 
including the reconsidered 2008 ozone NAAQS, may result in additional 
emission reduction requirements for the power sector. In addition, 
existing Clean Air Act rules establishing best available retrofit 
technology (BART) requirements and other requirements for addressing 
visibility and regional haze may also result in future state 
requirements for certain power plant emission reductions where needed.
    On May 3, 2011 (76 FR 24976), EPA proposed national emission 
standards for hazardous air pollutants from coal- and oil-fired 
electric utility steam generating units under CAA section 112(d), also 
called Mercury and Air Toxics Standards (MATS), and proposed revised 
new source performance standards for fossil fuel-fired EGUs under 
section 111(b). As discussed in the EPA-led public listening sessions 
during February and March 2011, EPA is preparing to propose innovative, 
cost-effective and flexible greenhouse gas (GHG) emissions performance 
standards under section 111 for steam electric generating units, the 
largest U.S. source of greenhouse gas emissions. On April 20, 2011 (76 
FR 22174), EPA proposed requirements under section 316(b) of the Clean 
Water Act for existing power generating facilities, manufacturing and 
industrial facilities that withdraw more than two million gallons per 
day of water from waters of the U.S. and use at least twenty-five 
percent of that water exclusively for cooling purposes. On June 21, 
2010 (75 FR 35128), the Agency proposed to regulate coal combustion 
residuals (CCRs) under the Resource Conservation and Recovery Act to 
address the risks from the disposal of CCRs generated from the 
combustion of coal at electric utilities and independent power 
producers.
    EPA will coordinate utility-related air pollution rules with each 
other and with other actions affecting the power sector including these 
rules from EPA's Office of Water and its Office of Resource 
Conservation and Recovery to the extent consistent with legal authority 
in order to provide timely information needed to support regulated 
sources in making informed decisions. Use of a small number of air 
pollution control technologies, widely deployed, can assist with 
compliance for multiple rules. EPA also notes that the flexibility 
inherent in the allowance-trading mechanism included in the Transport 
Rule affords utilities themselves a degree of latitude to determine how 
best to integrate compliance with the emission reduction requirements 
of this rule and those of the other rules. EPA will pursue energy 
efficiency improvements in the use of electricity throughout the 
economy, along with other federal agencies, states and other groups, 
which will contribute to additional environmental and public health 
improvements while lowering the costs of realizing those improvements.

IV. Legal Authority, Environmental Basis, and Correction of CAIR SIP 
Approvals

A. EPA's Authority for Transport Rule

    The statutory authority for this action is provided by the CAA, as 
amended, 42 U.S.C. 7401 et seq. Section 110(a)(2)(D) of the CAA, often 
referred to as the ``good neighbor'' provision of the Act, and requires 
states to prohibit certain emissions because of their impact on air 
quality in downwind states. Specifically, it requires all states, 
within 3 years of promulgation of a new or revised NAAQS, to submit 
SIPs that prohibit certain emissions of air pollutants because of the 
impact they would have on air quality in other states. 42 U.S.C. 
7410(a)(2)(D). This action addresses the requirement in section 
110(a)(2)(D)(i)(I) regarding the prohibition of emissions within a 
state that will significantly contribute to nonattainment or interfere 
with maintenance of the NAAQS in any other

[[Page 48217]]

state. EPA has previously issued two rules interpreting and clarifying 
the requirements of section 110(a)(2)(D)(i)(I). The NOX SIP 
Call, promulgated in 1998, was largely upheld by the U.S. Court of 
Appeals for the DC Circuit in Michigan, 213 F.3d 663. CAIR, promulgated 
in 2005, was remanded by the DC Circuit in North Carolina, 531 F.3d 
896, modified on reh'g, 550 F.3d. 1176. These decisions provide 
additional guidance regarding the requirements of section 
110(a)(2)(D)(i)(I) and are discussed later in this notice.
    Section 301(a)(1) of the CAA also gives the Administrator of EPA 
general authority to prescribe such regulations as are necessary to 
carry out her functions under the Act. 42 U.S.C. 7601(a)(1). Pursuant 
to this section, EPA has authority to clarify the applicability of CAA 
requirements. In this action, among other things, EPA is clarifying the 
applicability of section 110(a)(2)(D)(i)(I) by identifying 
SO2 and NOX emissions that must be prohibited 
pursuant to this section with respect to the PM2.5 NAAQS 
promulgated in 1997 and 2006 and the 8-hour ozone NAAQS promulgated in 
1997.
    Section 110(c)(1) requires the Administrator to promulgate a FIP at 
any time within 2 years after the Administrator finds that a state has 
failed to make a required SIP submission, finds a SIP submission to be 
incomplete or disapproves a SIP submission unless the state corrects 
the deficiency, and the Administrator approves the SIP revision, before 
the Administrator promulgates a FIP. 42 U.S.C. 7410(c)(1).
    Tribes are not required to submit state implementation plans. 
However, as explained in EPA's regulations outlining Tribal Clean Air 
Act authority, EPA is authorized to promulgate FIPs for Indian country 
as necessary or appropriate to protect air quality if a tribe does not 
submit and get EPA approval of an implementation plan. See 40 CFR 
49.11(a); see also 42 U.S.C. section 7601(d)(4).
    Section 110(k)(6) of the CAA gives the Administrator authority, 
without any further submission from a state, to revise certain prior 
actions, including actions to approve SIPs, upon determining that those 
actions were in error.

B. Rulemaking History

    The Transport Rule FIPs will limit the interstate transport of 
emissions of NOX and SO2 within 27 states in the 
eastern, midwestern, and southern United States that affect the ability 
of downwind states to attain and maintain compliance with the 1997 and 
2006 PM2.5 NAAQS and the 1997 ozone NAAQS.\10\ Prior to this 
Transport Rule, CAIR was EPA's most recent regulatory action in a 
longstanding series of regulatory initiatives to address interstate 
transport of air pollution. The proposed Transport Rule preamble 
provides more information on EPA actions prior to CAIR (75 FR 45221-
45225).
---------------------------------------------------------------------------

    \10\ As discussed in section III of this preamble, EPA is 
proposing to apply ozone-season NOX requirements to 
additional states. If EPA finalizes that action as proposed, the 
total number of states covered by the Transport Rule FIPs would be 
28.
---------------------------------------------------------------------------

    CAIR, promulgated May 12, 2005 (70 FR 25162), required 29 states to 
adopt and submit revisions to their SIPs to eliminate SO2 
and NOX emissions that contribute significantly to downwind 
nonattainment of the PM2.5 and ozone NAAQS promulgated in 
1997. The states covered by CAIR were similar but not identical to the 
states covered by the Transport Rule. The CAIR FIPs, promulgated April 
26, 2006 (71 FR 25328), regulated electric generating units in the 
covered states and achieved CAIR's emission reduction requirements 
unless or until states had approved SIPs to achieve the required 
reductions.
    In July 2008, the DC Circuit Court found CAIR and the CAIR FIPs 
unlawful and vacated CAIR. North Carolina, 531 F.3d at 929-30. However, 
the Court subsequently remanded CAIR to EPA without vacatur in order to 
``at least temporarily preserve the environmental values covered by 
CAIR.'' North Carolina, 550 F.3d at 1178. CAIR requirements have 
remained in place and CAIR's emission trading programs have operated 
while EPA developed replacement rules in response to the remand.
    By promulgating the Transport Rule FIPs, EPA is responding to the 
Court's remand of CAIR and the CAIR FIPs and replacing those rules. The 
approaches EPA used in the Transport Rule to measure and address each 
state's significant contribution to downwind nonattainment and 
interference with maintenance are guided by and consistent with the 
Court's opinion in North Carolina and address the flaws in CAIR 
identified by the Court therein.
    By notice of proposed rulemaking (Federal Implementation Plans To 
Reduce Interstate Transport of Fine Particulate Matter and Ozone, 75 FR 
45210; August 2, 2010), EPA proposed the Transport Rule to identify and 
limit NOX and SO2 emissions within 32 states in 
the eastern, midwestern, and southern United States that affect the 
ability of downwind states to attain and maintain compliance with the 
1997 and 2006 PM2.5 NAAQS and the 1997 ozone NAAQS. EPA 
proposed to achieve the emission reductions under FIPs, which states 
may choose to replace by submitting SIPs for EPA approval. EPA proposed 
to limit emissions by regulating electric generating units in the 32 
states with interstate emission trading programs and assurance 
provisions to ensure the required reductions occur in each covered 
state. EPA also requested comment on two alternative FIP remedies.
    EPA supplemented the Transport Rule record with additional 
information relevant to the rulemaking in three NODAs for which EPA 
requested comments:
     Notice of Data Availability Supporting Federal 
Implementation Plans to Reduce Interstate Transport of Fine Particulate 
Matter and Ozone (75 FR 53613; September 1, 2010). This NODA provided 
an updated database of unit-level characteristics of EGUs included in 
EPA modeling, an updated version of the power sector modeling platform 
EPA used to support the final rule, and other input assumptions and 
data EPA provided for public review and comment.
     Notice of Data Availability Supporting Federal 
Implementation Plans To Reduce Interstate Transport of Fine Particulate 
Matter and Ozone: Revisions to Emission Inventories (75 FR 66055; 
October 27, 2010). This NODA provided additional information relevant 
to the rulemaking, including updated emission inventory data for 2005, 
2012 and 2014 for several stationary and mobile source inventory 
components.
     Notice of Data Availability for Federal Implementation 
Plans To Reduce Interstate Transport of Fine Particulate Matter and 
Ozone: Request for Comment on Alternative Allocations, Calculation of 
Assurance Provision Allowance Surrender Requirements, New-Unit 
Allocations in Indian Country, and Allocations by States (76 FR 1109; 
January 7, 2011). This NODA provided additional information relevant to 
the rulemaking, including emissions allowance allocations for existing 
units calculated using two alternative methodologies, data supporting 
those calculations, information about an alternative approach to 
calculation of assurance provision allowance surrender requirements, 
allocations for new units locating in Indian country in Transport Rule 
states in the future, and provisions for states to submit SIPs 
providing for state allocation of allowances in the Transport Rule 
trading programs.

[[Page 48218]]

C. Air Quality Problems and NAAQS Addressed

1. Air Quality Problems and NAAQS Addressed
a. Fine Particles
    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, health-related absences from school or work, and 
restricted activity days), lung disease, decreased lung function, 
asthma attacks, and certain cardiovascular problems. In addition to 
effects on public health, fine particles are linked to a number of 
public welfare effects, including (1) Reduced visibility (haze) in 
scenic areas, (2) effects caused by particles settling on ground or 
water, such as: making lakes and streams acidic, changing the nutrient 
balance in coastal waters and large river basins, depleting the 
nutrients in soil, damaging sensitive forests and farm crops, and 
affecting the diversity of ecosystems, and (3) staining and damaging of 
stone and other materials, including culturally important objects such 
as statues and monuments.
    In 1997, EPA revised the NAAQS for PM to add new annual and 24-hour 
standards for fine particles, using PM2.5 as the indicator 
(62 FR 38652). These revisions established an annual standard of 15 
[mu]g/m\3\ and a 24-hour standard of 65 [mu]g/m\3\. During 2006, EPA 
revised the air quality standards for PM2.5. The 2006 
standards decreased the level of the 24-hour fine particle standard 
from 65 [mu]g/m\3\ to 35 [mu]g/m\3\, and retained the annual fine 
particle standard at 15 [mu]g/m\3\.
b. Ozone
    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. 
At sufficient concentrations, 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 may 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, or a 
lifetime). There is also epidemiological evidence indicating a 
correlation between short-term ozone exposure and premature mortality.
    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. In 1997, at the same time we 
revised the PM2.5 standards, EPA issued its final action to 
revise the NAAQS for ozone (62 FR 38856) to establish new 8-hour 
standards. In this action published on 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, 
the standards require that the 3-year average of the fourth highest 24-
hour maximum 8-hour average ozone concentration may not exceed 0.08 
ppm. In general, the 8-hour standards are more protective of public 
health and the environment and more stringent than the pre-existing 1-
hour ozone standards.
    On March 12, 2008, EPA published a revision to the 8-hour ozone 
standard, lowering the level from 0.08 ppm to 0.075 ppm. On September 
16, 2009, EPA announced it would reconsider these 2008 ozone standards. 
The purpose of the reconsideration is to ensure that the ozone 
standards are clearly grounded in science, protect public health with 
an adequate margin of safety, and are sufficient to protect the 
environment. EPA proposed revisions to the standards on January 19, 
2010 (75 FR 2938) and anticipates issuing final standards soon.
c. Which NAAQS does this rule address?
    This action addresses the requirements of CAA section 
110(a)(2)(D)(i)(I) as they relate to:
    (1) The 1997 annual PM2.5 standard,
    (2) The 2006 24-hour PM2.5 standard, and
    (3) The 1997 ozone standard.
    The original CAIR and CAIR FIP rules, which pre-dated the 2006 
PM2.5 standards, addressed the 1997 ozone and 1997 
PM2.5 standards only.
    In this action, EPA fully addresses, for the states covered by this 
rule, the requirements of CAA section 110(a)(2)(D)(i)(I) for the annual 
PM2.5 standard of 15 [mu]g/m\3\ and the 24-hour standard of 
35 [mu]g/m\3\. For the 1997 8-hour ozone standard of 0.08 ppm, EPA 
fully addresses the CAA section 110(a)(2)(D)(i)(I) requirements for 
some states covered by this rule, but for the remaining states EPA is 
conducting further analysis to determine whether further requirements 
are needed, as discussed in section III of this preamble.
    This action does not address the CAA section 110(a)(2)(D)(i)(I) 
requirements for the revised ozone standards promulgated in 2008. These 
standards are currently under reconsideration. We are, however, 
actively conducting the technical analyses and other work needed to 
address interstate transport for the reconsidered ozone standard as 
soon as possible. We intend to issue as soon as possible a proposal to 
address the transport requirements with respect to the reconsidered 
standard.
    This action addresses these CAA transport requirements through 
reductions in annual emissions of SO2 and NOX, 
and through reductions in ozone-season NOX. The rationale 
for these reductions is discussed in detail later in the preamble.
d. Public Comments
    EPA received comments on two issues related to the NAAQS regulated 
under the proposed FIPs.
    A number of commenters believed that EPA's approach to ozone was 
inadequate, and that EPA should not have based the proposed 
requirements on the 1997 ozone NAAQS. These commenters cited EPA's 2008 
revision to the standard which lowered the standard to 75 ppb, and 
noted that EPA's January 2010 proposal for reconsidered ozone NAAQS 
would, if finalized, further lower the primary NAAQS from 75 ppb to a 
value between 60 and 70 ppb. Accordingly, many of the commenters 
believed that EPA should have considered the 75 ppb level to be the 
maximum possible value moving forward, and that EPA should have used a 
value no greater than 75 ppb in its analysis.
    EPA agrees with commenters that EPA and states should address 
interstate transport with respect to the tighter

[[Page 48219]]

ozone NAAQS as quickly as possible. EPA, as commenters noted, intends 
to propose a second rule to address interstate transport of ozone that 
will be appropriately configured for the revised level of the ozone 
NAAQS after reconsideration of the 2008 standard is finalized. EPA is 
mindful of the need for SIPs to provide for continuing ozone progress 
to meet the 75 ppb level of the 2008 NAAQS, or possibly lower levels 
based on the reconsideration. EPA believes that the ozone-season 
NOX requirements of this rule will provide important initial 
assistance to states in this regard.
    Some commenters questioned whether EPA had given states the 
opportunity to provide SIPs addressing transport under the 2006 
PM2.5 NAAQS, and thus questioned the appropriateness of the 
issuance of FIPs addressing those NAAQS. Those comments, and EPA's 
response, are discussed in detail in section IV.C.2.
2. FIP Authority for Each State and NAAQS Covered
    The CAA requires and authorizes EPA to promulgate each of the 
Federal Implementation Plans in this final rule. Section 110(c)(1) of 
the CAA requires the Administrator to promulgate a FIP at any time 
within 2 years after the Administrator takes one of three distinct 
actions: (1) She finds that a state has failed to make a required SIP 
submission; (2) she finds a SIP submission to be incomplete; or (3) she 
disapproves a SIP submission. Once the Administrator has taken one of 
these actions with respect to a specific state's 110(a)(2)(D)(i)(I) 
obligation for a specific NAAQS, she has a legal obligation to 
promulgate a FIP to correct the SIP deficiency within 2 years. EPA is 
relieved of the obligation to promulgate a FIP only if two events occur 
before the FIP is promulgated: (1) The state submits a SIP correcting 
the deficiency; and (2) the Administrator approves the SIP revision. 42 
U.S.C. 7410(c)(1).\11\
---------------------------------------------------------------------------

    \11\ The CAA provides that EPA is not relieved of its obligation 
to promulgate FIPs unless the state submits a SIP that corrects the 
deficiency and EPA approves the SIP. Nonetheless, in the preamble to 
the proposed rule, EPA indicated that for states not covered by CAIR 
which had 110(a)(2)(D)(i)(I) SIPs pending at the time of proposal, 
EPA would finalize the FIP only if EPA determined the submission was 
incomplete or disapproved the SIP submission. The only two states 
covered by this rule but not covered by CAIR are Kansas and 
Nebraska. Both Kansas and Nebraska are covered by this rule based 
only on their significant contribution to nonattainment or 
interference with maintenance of the 2006 PM2.5 NAAQS. 
EPA has not received a 110(a)(2)(D)(i)(I) submission from Nebraska 
with respect to the requirements of the 2006 PM2.5 NAAQS. 
EPA disapproved a SIP submission from Kansas with respect to the 
requirements of 110(a)(2)(D)(i)(I) for the 2006 PM2.5 
NAAQS.
---------------------------------------------------------------------------

    For each FIP in this rule,\12\ EPA either has found that the state 
has failed to make a required 110(a)(2)(D)(i)(I) SIP submission, or has 
disapproved a SIP submission.\13\ In addition, EPA has determined, in 
each case, that there has been no approval by the Administrator of a 
SIP submission correcting the deficiency prior to promulgation of the 
FIP. EPA's obligation to promulgate a FIP arose when the finding of 
failure to submit or disapproval was made, and in no case has it been 
relieved of that obligation.
---------------------------------------------------------------------------

    \12\ In this action, EPA is issuing 59 FIPs. EPA is issuing 20 
FIPs to remedy SIP deficiencies relating to the 110(a)(2)(D)(i)(I) 
requirements for the 1997 ozone NAAQS. EPA is also issuing 18 FIPs 
to remedy SIP deficiencies relating to the 1997 PM2.5 
NAAQS. Finally, EPA is issuing 21 FIPs to remedy SIP deficiencies 
relating to the 2006 PM2.5 NAAQS.
    \13\ The specific findings made and actions taken by EPA are 
described in greater detail in the TSD entitled ``Status of CAA 
110(a)(2)(D)(i)(I) SIPs.''
---------------------------------------------------------------------------

    Some commenters argued that EPA was relieved of its obligation to 
promulgate FIPs when it approved the CAIR SIPs for certain states. As 
an initial matter, EPA notes that this argument applies only to EPA's 
authority to promulgate FIPs with respect to the 1997 PM2.5 
and/or 1997 ozone NAAQS for a subset of states covered by the CAIR. It 
does not apply to EPA's authority to promulgate FIPs for the 2006 
PM2.5 NAAQS which was not addressed in CAIR. It also does 
not apply to EPA's authority to promulgate FIPs for the 1997 ozone and 
1997 PM2.5 NAAQS for states that remain subject to the CAIR 
FIPs, including the states that received EPA approval of abbreviated 
CAIR SIPs which allowed the states to allocate allowances while 
remaining subject to the CAIR FIPs.\14\
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    \14\ States may also have received approval to expand the 
applicability of the CAIR NOX ozone season program to 
include all units subject to the NOX Budget Program, 
allow opt-ins, or provide for distribution of a Compliance 
Supplement Pool under the CAIR NOX (annual) program.
---------------------------------------------------------------------------

    Further, the CAIR SIP approvals do not eliminate EPA's obligation 
and authority to promulgate a FIP to address the requirements of 
110(a)(2)(D)(i)(I) because the Court in North Carolina v. EPA, 531 F.3d 
896 (D.C. Cir. 2008) found that compliance with CAIR does not satisfy 
the requirement that each state prohibit all emissions within the state 
that significantly contribute to nonattainment or interfere with 
maintenance in another state. The Court's finding that CAIR was 
unlawful because it did not make measureable progress towards the 
statutory mandate of section 110(a)(2)(D)(i)(I) meant that the CAIR 
SIPs were not adequate to satisfy that mandate. The CAIR SIPs thus do 
not correct the SIP deficiencies identified in the 2005 findings of 
failure to submit. The SIPs remained in force for the limited purpose 
allowed by the Court--that is, to achieve interim reductions until EPA 
promulgated a rule to replace CAIR. Given the flaws the court 
identified with CAIR, EPA's approval of a CAIR SIP does not relieve it 
of the obligation to promulgate FIPs created under section 110(c)(1) of 
the CAA.
    Further, to avoid any confusion, EPA has decided to correct, in 
this notice, the full CAIR SIP approvals for states covered by this 
rule and the CAA 110(a)(2)(D)(i) SIP approvals for states covered by 
CAIR to rescind any statements suggesting that the SIP submissions 
satisfied or relieved states of the obligation to submit SIPs to 
satisfy the requirements of section 110(a)(2)(D)(i)(I) or that EPA was 
relieved of its obligation and authority to promulgate FIPs under 
110(a)(2)(D)(I)(i).
    Some commenters further argued that states should be given 
additional time, following promulgation of the Transport Rule, to 
submit a SIP to meet the requirements of section 110(a)(2)(D)(i)(I) and 
that CAIR should remain in place in the meantime. Some commenters 
specifically suggested that EPA restart the ``FIP clock'' \15\ to give 
states this additional time. EPA does not interpret the CAA as giving 
it authority to extend the deadline for SIP submissions or restart the 
FIP clock. And nothing in the Act requires EPA to give the states 
another opportunity, following promulgation of the Transport Rule, to 
promulgate a SIP before EPA promulgates a FIP. The plain language of 
section 110(a)(1) of the Act requires the submission of SIPs that meet 
the requirements of 110(a)(2)(D)(i)(I) within 3 years after the 
promulgation of or revision of a primary NAAQS. See 42 U.S.C. 
7410(a)(1). Section 110(a)(2)(D)(i)(I) SIPs for the 1997 ozone and 
PM2.5 NAAQS were due in 2000 and 110(a)(2)(D)(i)(I) SIPs for 
the 2006 PM2.5 NAAQS were due in 2009. While the statute 
gives EPA authority to prescribe a shorter period of time for states to 
make these SIP submissions, it does not give EPA authority to extend 
the 3-year deadline established by the Act. See 42 U.S.C. 7410(a)(1). 
The plain language of section 110(c)(1) of the Act, in turn, provides 
that EPA shall promulgate a FIP at any time within 2 years after the 
Administrator makes a finding of failure to make a required SIP

[[Page 48220]]

submission of disapproves, in whole or in part, a SIP submission. See 
42 U.S.C. 7410(c)(1). EPA does not have authority to set aside the 
specific deadlines established in the statute, and neither provision 
allows for the deadlines to be extended or to run from promulgation by 
EPA of a rule to quantify the state's specific obligations pursuant to 
section 110(a)(2)(D)(i)(I). The Act does not require EPA to promulgate 
a rule or issue guidance regarding the specific requirements of section 
110(a)(2)(D)(i)(I) in advance of the SIP submittal deadline, much less 
require EPA to promulgate such a rule a specific amount of time before 
the SIP submittal deadline. For these reasons, EPA has neither 
authority to alter the SIP submittal deadline nor authority to alter 
the statute provision regarding when EPA's obligation to promulgate a 
FIP is triggered.
---------------------------------------------------------------------------

    \15\ ``FIP clock'' is a term used to describe EPA's 
responsibility found in CAA Section 110(c)(1) to promulgate a FIP 
within 2 years after either: Finding that a state has not submitted 
a required SIP revision or that a submitted SIP revision is 
incomplete; or disapproving a SIP revision.
---------------------------------------------------------------------------

    Finally, EPA does not believe it would be appropriate, in light of 
the Court's decision in North Carolina, to establish a lengthy 
transition period to the rule that will replace CAIR. The Court 
decision remanding CAIR without vacatur stressed the court's conclusion 
that CAIR was deeply flawed and emphasized EPA's obligation to remedy 
those flaws expeditiously. North Carolina, 550 F.3d 1176. Although the 
Court did not set a specific deadline for corrective action, the Court 
took care to note that the effect of its opinion would not be delayed 
``indefinitely'' and that petitioners could bring a mandamus petition 
if EPA were to fail to modify CAIR in a manner consistent with its 
prior opinion. Id. Given the Court's emphasis on remedying CAIR's flaws 
expeditiously, EPA does not believe it would be appropriate to 
establish a lengthy transition period to the rule which is to replace 
CAIR.
3. Additional Information Regarding CAA Section 110(a)(2)(D)(i)(I) SIPs 
for States in the Transport Rule Modeling Domain
    This final rule quantifies out-of-state contributions for the 38 
states that are fully contained within the 12 kilometers (km) eastern 
U.S. modeling domain. EPA is making no specific finding for states that 
are not fully contained within the eastern 12 km modeling domain. EPA 
did not conduct a contribution analysis or make any specific finding 
for New Mexico, Colorado, Wyoming, and Montana since they are only 
partially contained within the 12 km modeling domain. With regard to 
the 1997 PM2.5 NAAQS and 2006 PM2.5 NAAQS, EPA 
believes that states that are included in this 38 state modeling domain 
will meet their section 110(a)(2)(D)(i)(I) obligations to address the 
``significant contribution'' and ``interference with maintenance'' 
requirements by complying with the requirements in this rule. With 
regard to the 1997 ozone NAAQS, EPA believes that states that are 
included in this 38 state modeling domain will meet their section 
110(a)(2)(D)(i)(I) obligations to address the ``significant 
contribution'' and ``interference with maintenance'' requirements by 
complying with the requirements in this rule, except for the 10 states 
found to significantly contribute to nonattainment or interference of 
maintenance in either Houston or Baton Rouge (i.e., Alabama, Arkansas, 
Georgia, Illinois, Indiana, Kentucky, Louisiana, Mississippi, 
Tennessee, and Texas). States that are in the 38 state modeling domain, 
and that are not found to be contributing significantly to 
nonattainment or interfering with maintenance for any NAAQS evaluated 
in the modeling for the final rule, could rely on this analysis as 
technical support that their existing or future interstate transport 
SIP submittals are adequate to address the transport requirements of 
110(a)(2)(D)(i)(I). For example, this rule finds that South Carolina 
significantly contributes to nonattainment and interferes with 
maintenance of the 1997 ozone NAAQS and the 1997 PM2.5 NAAQS 
in downwind states. The technical support for the rule does not show 
that South Carolina significantly contributes to nonattainment or 
interferes with maintenance of the 2006 PM2.5 NAAQS in 
downwind states. EPA believes that South Carolina can make a negative 
declaration concluding that the state does not significantly contribute 
to nonattainment or interfere with maintenance in other states with 
regard to the 2006 PM2.5 NAAQS.

D. Correction of CAIR SIP Approvals

    In this action, EPA is also correcting its prior approvals of CAIR 
related SIP submissions and CAA 110(a)(2)(D)(i) SIP submissions from 
Alabama, Arkansas, Connecticut, Florida, Georgia, Illinois, Indiana, 
Iowa, Kentucky, Louisiana, Maryland, Massachusetts, Minnesota, 
Mississippi, Missouri, New York, North Carolina, Ohio, Pennsylvania, 
South Carolina, Virginia and West Virginia to rescind any statements 
that the SIP submissions either satisfy or relieve the state of the 
obligation to submit a SIP to satisfy the requirements of section 
110(a)(2)(D)(i)(I) with respect to the 1997 ozone and/or 1997 
PM2.5 NAAQS or any statements that EPA's approval of the SIP 
submissions either relieve EPA of the obligation to promulgate a FIP or 
remove EPA's authority to promulgate a FIP. This action is based on 
EPA's determination that those SIP approvals were in error to the 
extent they provided explicitly or implicitly that compliance with CAIR 
satisfies the requirements of 110(a)(2)(D)(i)(I) with respect to the 
1997 ozone and 1997 PM2.5 NAAQS. The July 2008 decision of 
the DC Circuit held, among other things, that the CAIR rule did not 
``achieve[] something measureable toward the goal of prohibiting 
sources `within the State' from contributing to nonattainment or 
interfering with maintenance in `any other State.''' North Carolina, 
531 F.3d 908; see also, e.g., id. at 916 (EPA not exercising its 
authority to make measureable progress towards the goals of section 
110(a)(2)(D)(i)(I) because the emission budgets were insufficiently 
related to the statutory mandate). EPA's actions to approve CAIR SIP 
submittals as satisfying the requirements of section 
110(a)(2)(D)(i)(I), based on the flawed determination in CAIR that 
compliance with CAIR satisfied those statutory requirements, were thus 
in error as were the separate actions taken to approve section 
110(a)(2)(D)(i)(I) submissions that relied wholly or in part on CAIR.
    The approval for Alabama titled ``Approval and Promulgation of 
Implementation Plans; Alabama; Clean Air Interstate Rule'' which is 
hereby corrected was originally published in the Federal Register on 
October 1, 2007 (72 FR 55659).
    The approval for Arkansas titled ``Approval and Promulgation of 
Implementation Plans; Arkansas; Clean Air Interstate Rule Nitrogen 
Oxides Ozone Season Trading Program'' which is hereby corrected was 
originally published in the Federal Register on September 26, 2007 (72 
FR 54556).
    The approval for Connecticut titled ``Approval and Promulgation of 
Air Quality Implementation Plans; Connecticut; State Implementation 
Plan Revision to Implement the Clean Air Interstate Rule'' which is 
hereby corrected was originally published in the Federal Register on 
January 24, 2008 (73 FR 4105) and the approval for Connecticut titled 
``Approval and Promulgation of Air Quality Implementation Plans; 
Connecticut; Interstate Transport of Pollution'' which is hereby 
corrected was originally published in the Federal Register on May 7, 
2008 (73 FR 25516).
    The approval for Florida titled ``Approval and Promulgation of 
Implementation Plans; Florida; Clean Air Interstate Rule'' which is 
hereby corrected was originally published in the Federal Register on 
October 12, 2007 (72 FR 58016).

[[Page 48221]]

    The approval for Georgia titled ``Approval and Promulgation of 
Implementation Plans; Georgia; Clean Air Interstate Rule'' which is 
hereby corrected was originally published in the Federal Register on 
October 9, 2007 (72 FR 57202).
    The approval for Illinois titled ``Approval of Implementation Plans 
of Illinois: Clean Air Interstate Rule'' which is hereby corrected was 
originally published in the Federal Register on October 16, 2007 (72 FR 
58528).
    The approval for Indiana titled ``Limited Approval of 
Implementation Plans of Indiana: Clean Air Interstate Rule'' which is 
hereby corrected was originally published in the Federal Register on 
October 22, 2007 (72 FR 59480) and the approval for Indiana titled 
``Approval and Promulgation of Air Quality Implementation Plans; 
Indiana; Clean Air Interstate Rule'' which is hereby corrected was 
originally published in the Federal Register on November 29, 2010 (75 
FR 72956).
    The approval for Iowa titled ``Approval and Promulgation of 
Implementation Plans; Iowa; Clean Air Interstate Rule'' which is hereby 
corrected was originally published in the Federal Register on August 6, 
2007 (72 FR 43539) and the approval for Iowa titled ``Approval and 
Promulgation of Implementation Plans; Iowa; Interstate Transport of 
Pollution'' which is hereby corrected was originally published in the 
Federal Register on March 8, 2007 (72 FR 10380).
    The approval for Kentucky titled ``Approval of Implementation Plans 
of Kentucky: Clean Air Interstate Rule'' which is hereby corrected was 
originally published in the Federal Register on October 4, 2007 (72 FR 
56623).
    The approval for Louisiana titled ``Approval and Promulgation of 
Implementation Plans; Louisiana; Clean Air Interstate Rule Sulfur 
Dioxide Trading Program'' which is hereby corrected was originally 
published in the Federal Register on July 20, 2007 (72 FR 39741) and 
the approval for Louisiana titled ``Approval and Promulgation of 
Implementation Plans; Louisiana; Clean Air Interstate Rule Nitrogen 
Oxides Trading Program'' which is hereby corrected was originally 
published in the Federal Register on September 28, 2007 (72 FR 55064).
    The approval for Maryland titled ``Approval and Promulgation of Air 
Quality Implementation Plans; Maryland; Clean Air Interstate Rule'' 
which is hereby corrected was originally published in the Federal 
Register on October 30, 2009 (74 FR 56117).
    The approval for Massachusetts titled ``Approval and Promulgation 
of Air Quality Implementation Plans; Massachusetts; State 
Implementation Plan Revision to Implement the Clean Air Interstate 
Rule'' which is hereby corrected was originally published in the 
Federal Register on December 3, 2007 (72 FR 67854).
    The approval for Minnesota titled ``Approval and Promulgation of 
Air Quality Implementation Plans; Minnesota; Interstate Transport of 
Pollution'' which is hereby corrected was originally published in the 
Federal Register on June 2, 2008 (73 FR 31366).
    The approval for Mississippi titled ``Approval and Promulgation of 
Implementation Plans; Mississippi: Clean Air Interstate Rule'' which is 
hereby corrected was originally published in the Federal Register on 
October 3, 2007 (72 FR 56268).
    The approval for Missouri titled ``Approval and Promulgation of 
Implementation Plans; Missouri; Clean Air Interstate Rule'' which is 
hereby corrected was originally published in the Federal Register on 
December 14, 2007 (72 FR 71073) and the approval of Missouri titled 
``Approval and Promulgation of Implementation Plans; Missouri; 
Interstate Transport of Pollution'' which is hereby corrected was 
originally published in the Federal Register on May 8, 2007 (75 FR 
25975).
    The approval for New York titled ``Approval and Promulgation of 
Implementation Plans; New York: Clean Air Interstate Rule'' which is 
hereby corrected was originally published in the Federal Register on 
January 24, 2008 (73 FR 4109).
    The approval for North Carolina titled ``Approval of Implementation 
Plans; North Carolina: Clean Air Interstate Rule'' which is hereby 
corrected was originally published in the Federal Register on October 
5, 2007 (72 FR 56914) and the approval for North Carolina titled 
``Approval and Promulgation of Air Quality Implementation Plans; North 
Carolina; Clean Air Interstate Rule'' which is hereby corrected was 
originally published in the Federal Register on November 30, 2009 (74 
FR 62496).
    The approval for Ohio titled ``Approval and Promulgation of Air 
Quality Implementation Plans; Ohio; Clean Air Interstate Rule'' which 
is hereby corrected was originally published in the Federal Register on 
February 1, 2008 (73 FR 6034) and the approval for Ohio titled 
``Approval and Promulgation of Air Quality Implementation Plans; Ohio; 
Clean Air Interstate Rule'' which is hereby corrected was originally 
published in the Federal Register on September 25, 2009 (74 FR 48857).
    The approval for Pennsylvania titled ``Approval and Promulgation of 
Air Quality Implementation Plans; Pennsylvania; Clean Air Interstate 
Rule; NOX SIP Call Rule; Amendments to NOX 
Control Rules'' which is hereby corrected was originally published in 
the Federal Register on December 10, 2009 (74 FR 65446).
    The approval for South Carolina titled ``Approval of Implementation 
Plans of South Carolina: Clean Air Interstate Rule'' which is hereby 
corrected was originally published in the Federal Register on October 
9, 2007 (72 FR 57209) and the approval for South Carolina titled 
``Approval and Promulgation of Air Quality Implementation Plans; South 
Carolina; Clean Air Interstate Rule'' which is hereby corrected was 
originally published in the Federal Register on October 16, 2009 (74 FR 
53167).
    The approval for Virginia titled ``Approval and Promulgation of Air 
Quality Implementation Plans; Virginia; Clean Air Interstate Rule 
Budget Trading Programs'' which is hereby corrected was originally 
published in the Federal Register on December 28, 2007 (72 FR 73602).
    The approval for West Virginia titled ``Approval and Promulgation 
of Air Quality Implementation Plans; West Virginia; Clean Air 
Interstate Rule'' which is hereby corrected was originally published in 
the Federal Register on December 18, 2007 (72 FR 71576) and the 
approval for West Virginia titled ``Approval and Promulgation of Air 
Quality Implementation Plans; West Virginia; Clean Air Interstate 
Rule'' which is hereby corrected was originally published in the 
Federal Register on August 4, 2009 (74 FR 38536).
    EPA is taking this final action without prior opportunity for 
notice and comment because EPA finds, for good cause, that notice and 
public procedure thereon are unnecessary and not in the public 
interest. Section 553(b)(B) of the Administrative Procedure Act 
provides that the notice and comment requirements in section 553 do not 
apply when the agency for good cause finds that notice and public 
procedure there on are impracticable, unnecessary, or contrary to the 
public interest. 5 U.S.C. 553(b)(B). Section 307(d)(1) of the CAA in 
turn provides that the requirements of section 307(d) do not apply in 
the case of a rule or circumstance referred to in section 553(b)(A) or 
section 553(b)(B) of the Administrative Procedure Act in Title 5. 42 
U.S.C. 7607(1).
    EPA finds that notice and public procedure are unnecessary because 
EPA has no discretion given the specific

[[Page 48222]]

circumstances presented in this case. EPA is bound by the decisions of 
the courts and must act in accordance with those decisions. EPA must 
accept the Court's conclusion that compliance with CAIR does not 
satisfy the requirements of CAA section 110(a)(2)(D)(i)(I) and lacks 
discretion to reach a different conclusion. This correction is a 
ministerial matter consistent with the decisions of the courts. For 
these reasons, it is unnecessary to provide an opportunity for notice 
and comment.

V. Analysis of Downwind Air Quality and Upwind State Emissions

A. Pollutants Regulated

    To address interstate transport of air pollution, EPA must choose 
which pollutants to regulate relevant to significant contribution to 
nonattainment or interference with maintenance of the NAAQS of concern 
downwind. This section of the preamble discusses the pollutants 
regulated under the final Transport Rule.
1. Background
    Based on scientific and technical information, as well as EPA's air 
quality modeling, EPA concluded for CAIR that the most effective 
approach to reducing the contribution of interstate transport to 
PM2.5 was to control SO2 and NOX 
emissions. For CAIR, EPA did not limit emissions of other components of 
PM2.5, noting that ``current information relating to sources 
and controls for other components identified 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).
    With respect to ozone transport, EPA has previously concluded that 
it is proper to control ozone-season NOX emissions. For CAIR 
and the NOX SIP Call programs, EPA based this conclusion on 
the assessment of ozone transport conducted by the Ozone Transport 
Assessment Group (OTAG) in the mid-1990s. The OTAG Regional and Urban 
Scale Modeling and Air Quality Analysis Work Groups concluded that 
regional NOX emission reductions are effective in producing 
ozone benefits that grow with increasing regional NOX 
abatement.
    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 and many urban 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 also 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 of 
air masses, which promote the build-up of direct emissions and 
pollutants formed through atmospheric reactions over large regions. 
Authoritative assessments of ozone control approaches have concluded 
that, for reducing regional scale ozone transport, a NOX 
control strategy is most effective, whereas VOC reductions are 
generally most effective locally, in more dense urbanized areas.
    Studies conducted since the 1970s established that ozone occurs on 
a regional scale (i.e., thousands of kilometers) over much of the 
eastern U.S., with elevated concentrations occurring in rural as well 
as metropolitan areas. While substantial progress has been made in 
reducing ozone in many urban areas, regional-scale ozone transport is 
still an important component of high ozone concentrations during the 
extended summer ozone season. A series of more recent progress reports 
discussing the effect of the NOX SIP Call reductions can be 
found on EPA's Web site at: http://www.epa.gov/airmarkets/progress/progress-reports.html.
    More recent assessments of ozone (including those conducted for the 
Regulatory Impact Analysis for the ozone standards in 2008) continue to 
show the importance of NOX transport as a factor in ozone 
formation. For addressing interstate ozone transport in CAIR, EPA 
required NOX emission reductions but did not include 
requirements for VOCs. EPA believes that VOCs from some upwind states 
do indeed have an impact in some nearby downwind states, particularly 
over short transport distances. EPA expects that states, typically in 
local nonattainment planning, would benefit from examining the extent 
to which VOC emissions affect ozone pollution levels within and near 
urban nonattainment areas, and states may identify areas where multi-
state VOC strategies might assist in attainment planning for meeting 
the 8-hour standard. However, EPA continues to believe that the most 
effective regional pollution control strategy for mitigation of 
interstate transport of ozone remains NOX emission 
reductions.
2. Which pollutants did EPA propose to control for purposes of 
PM2.5 and ozone transport?
    For the proposed rule, EPA concluded that its findings in CAIR 
regarding the nature of pollutant contributions are still appropriate. 
EPA proposed to require SO2 and annual NOX 
emission reductions to control PM2.5 transport and to 
require ozone-season NOX emission reductions to control 
ozone transport. In the proposal, EPA discussed and requested comment 
on the inclusion of southern states in the annual NOX 
program for PM2.5 control.
3. Comments and Responses
    EPA received no adverse comments on its proposal to regulate 
SO2 for addressing PM2.5 transport, the proposal 
not to regulate direct PM2.5 or organic PM2.5 
precursors, and the proposal to focus ozone-season efforts on 
NOX and not to regulate VOCs.
    One commenter questioned EPA's regulation of NOX for 
purposes of addressing PM2.5 transport in all states 
(including northern states with cooler climates and higher nitrate 
deposition). Several commenters, representing southern state air 
quality agencies and regulated sources in southern states, disagreed 
with EPA's proposed regulation of annual NOX emissions for 
all regulated states. These commenters, while not disagreeing with the 
need for regulation of SO2, observed that in EPA's modeling 
analysis, contributions from certain southern states' NOX 
emissions to PM2.5 in downwind states were relatively small.
    Accordingly, these commenters argued that either (1) EPA should 
remove NOX as a precursor analyzed for PM2.5 
contribution from those states, or (2) the required remedy for emission 
reductions in those states should not require reductions in annual 
NOX.
    For the final rule, EPA retains the approach for regulated 
pollutants in the proposal, which regulates annual NOX and 
SO2 for states affecting downwind state PM2.5 
nonattainment and maintenance sites, and ozone-season NOX 
for states impacting downwind state ozone nonattainment and 
maintenance. EPA considered commenters' requests to remove some states 
from the annual NOX program. However, EPA believes that it 
is

[[Page 48223]]

appropriate to establish a cap on these states' annual NOX 
emissions, in part to ensure the continued annual operation of existing 
control equipment that would prevent substantial increases in 
NOX emissions. EPA believes that without these reductions, 
increased ``nitrate replacement'' could occur, a known atmospheric 
phenomenon whereby some of the sulfate reductions due to SO2 
emission reductions are eroded by increases in nitrate concentrations 
due solely to those SO2 reductions.\16\ This is an 
especially pertinent concern for southern states which have significant 
impacts on northern receptors in colder climates where nitrate 
concentrations are generally higher. For example, Alabama and Tennessee 
are both linked to Washtenaw County, MI for 24-hour PM2.5; 
North Carolina is linked to Lancaster County, PA for 24-hour 
PM2.5; and Texas is linked to Madison County, IL for both 
annual and 24-hour PM2.5. All of these downwind areas have 
appreciable nitrate deposition contributing to nonattainment and 
maintenance concerns for the PM2.5 NAAQS. If the states 
linked to those receptors were to make SO2 reductions only, 
their beneficial impact on downwind air quality would be partially 
eroded by nitrate replacement. EPA therefore believes that it is 
reasonable to seek both SO2 and NOX reductions 
from states included in the Transport Rule program that are found to 
significantly contribute to nonattainment or interfere with maintenance 
of the PM2.5 NAAQS in downwind states.
---------------------------------------------------------------------------

    \16\ SO2 reductions successfully decrease atmospheric 
formation of ammonium sulfate, but in doing so they ``free up'' the 
ammonia component that would otherwise have reacted with 
SO2 and is now free to react with NOX instead, 
causing a ``rebound effect'' partially eroding the improvement in 
PM2.5 concentrations. This effect can be mitigated with 
tandem NOX reductions.
---------------------------------------------------------------------------

    In addition, EPA notes that there would be important disbenefits to 
effectively removing CAIR's existing annual NOX requirements 
in those states. If EPA were to allow annual NOX emissions 
to increase for those states, there would be potentially harmful 
effects on visibility, nitrogen deposition, and other aspects of human 
and environmental health.

B. Baseline for Pollution Transport Analysis

    Implementing the mandate of CAA section 110(a)(2)(D)(i)(I) requires 
EPA to determine which states significantly contribute to nonattainment 
and interfere with maintenance of the NAAQS in other states, as well as 
to quantify the emissions in each state that must be eliminated. This 
process begins with an analysis of baseline emissions. Baseline 
emissions are the emissions that would occur in each state if EPA did 
not promulgate the Transport Rule. To conduct such analysis, EPA 
generally takes into account emission limitations that are currently, 
and will continue to be, in place. From that baseline, EPA analyzes 
whether additional reductions are necessary beyond those already 
mandated by existing emission limitation requirements. For example, the 
base case used in CAIR reflected the reductions already required by the 
NOX SIP Call, which remained in effect even after the CAIR 
emission reduction requirements took effect.
    The unique legal situation addressed by the Transport Rule 
necessarily affects the quantification of baseline emissions. 
Specifically, because the Transport Rule will replace CAIR, EPA cannot 
consider reductions associated with CAIR in the ``base case'' (i.e., 
analytical baseline emissions scenario). If EPA were to consider all 
reductions associated with CAIR in the ``base case,'' the baseline 
emissions would not adequately reflect the true 2012 baseline in each 
state (i.e., the emissions that would occur in each state in 2012 if 
the Transport Rule did not require any reductions in that state). 
Similarly, if EPA were to treat the capital investments that have 
already been made to meet the requirements of CAIR as new costs rather 
than treating them as ``sunk'' capital costs, EPA's analysis would not 
accurately reflect the cost of emission reductions required by the 
Transport Rule. As explained below, EPA's analysis both properly 
considered all capital investments made in response to CAIR and 
properly recognized that, after CAIR is terminated, the emission 
limitations imposed by CAIR will cease to exist.
    In 2005 EPA promulgated CAIR, which required large electric 
generating units in 29 states to make phase I emission reductions in 
NOX emissions starting in 2009, phase I emission reductions 
in SO2 starting in 2010 and phase II reductions in emissions 
of both pollutants starting in 2015. On July 11, 2008, the DC Court of 
Appeals held that CAIR had ``more than several fatal flaws,'' North 
Carolina, 531 F.3d at 901, and remanded and vacated the rule, id. at 
930. The Court subsequently granted EPA's petition for rehearing in 
part and remanded CAIR without vacatur ``for EPA to conduct further 
proceedings consistent with'' the Court's July 11, 2008 opinion. North 
Carolina, 550 F.3d 1176. The Court explained that it was ``allowing 
CAIR to remain in effect until it is replaced by a rule consistent with 
[the July 11, 2008] opinion'' because this ``would at least temporarily 
preserve the environmental values covered by CAIR.'' Id. at 1178. 
Moreover, the Court stated that it did not ``intend to grant an 
indefinite stay of the effectiveness of'' the July 11, 2008 order 
vacating CAIR. Id. In summary, the Court determined that CAIR was 
fatally flawed and could remain in effect only as a stopgap measure 
until EPA could act to replace it.
    Thus, unlike most other regulatory requirements (such as the Acid 
Rain Program under CAA Title IV, the NOX Budget Trading 
Program under the NOX SIP Call, New Source Performance 
Standards, and state laws and consent orders requiring emission 
reductions), the emission limitations contained in CAIR are only 
temporary. Moreover, the duration of these limitations is directly tied 
to the Transport Rule. The Transport Rule replaces CAIR. Thus, CAIR 
itself will be terminated for the SO2, annual 
NOX, and ozone-season NOX control periods 
starting in 2012 when the emission limitations established in the final 
Transport Rule for those control periods take effect (January 1, 2012 
for the annual control periods and May 1, 2012 for the ozone-season 
control period). For this reason, emission reductions made to comply 
with CAIR cannot be treated as if they were emission reductions 
achieved to comply with statutory provisions, rules, consent decrees, 
and other enforceable requirements that establish permanent emission 
limitations. EPA takes reductions made to comply with permanent 
limitations into consideration when quantifying each state's baseline 
emissions for the purpose of analyzing whether its emissions 
significantly contribute to nonattainment or interfere with maintenance 
in another state. However, the unique legal status of CAIR and its 
replacement with the Transport Rule distinguish the emission reductions 
required by CAIR from those of other regulatory requirements. Since the 
limitations and emission reduction requirements in CAIR are temporary 
and will be terminated by the Transport Rule, they must be excluded 
from the Transport Rule's base case analysis.
    Some comments on the Transport Rule proposal claim that EPA's 
treatment of CAIR is inconsistent with the treatment, in prior 
rulemakings, of the Acid Rain Program and the NOX SIP Call. 
Such comments ignore the unique legal status of CAIR, and EPA therefore 
rejects these claims.
    A simple example illustrates this point. Assume state Z's emissions 
before

[[Page 48224]]

CAIR were 2,000 tons and that state Z was required by CAIR to reduce 
its emissions to 1,000 tons. If EPA were to determine that state Z's 
baseline emissions were 1,000 tons and then conclude, based on that 
assumption, that no additional reductions in state Z are necessary 
because state Z does not significantly contribute to downwind 
nonattainment unless its emissions exceed 1,500 tons, then state Z 
would not be covered by the Transport Rule. However, the Transport Rule 
will terminate all CAIR requirements in all CAIR states regardless of 
whether they are covered by the Transport Rule. Thus, after 
promulgation of the Transport Rule, state Z would again be allowed, and 
would be projected in this example, to emit 2,000 tons. In other words, 
state Z would be allowed to significantly contribute to nonattainment 
and/or interfere with maintenance in other states--a result that would 
be inconsistent with the statutory mandate of CAA section 
110(a)(2)(D)(i)(I). On the other hand, if EPA assumes state Z's 
baseline emissions are 2,000 tons as projected without CAIR in place, 
EPA can properly determine whether, if state Z were allowed to emit 
that amount (i.e., the amount state Z would be projected to emit if 
excluded from the Transport Rule), the state would significantly 
contribute to nonattainment or interfere with maintenance in any other 
state. In other words, EPA can determine the stringency of emission 
limitations needed (if any) to replace those that were established by 
CAIR in order to ensure that state Z prohibits all emissions that 
significantly contribute to nonattainment or interfere with maintenance 
in other states.
    In fact, commenters' suggestion that the Transport Rule base case 
should include CAIR would cause the anomalous result of excluding 
sources in a state from the Transport Rule because of their CAIR-
required emission reductions while simultaneously eliminating those 
CAIR emission reduction requirements. If EPA's base case analysis were 
to assume erroneously that reductions from CAIR would continue 
indefinitely, a state currently covered by CAIR, but not covered by the 
Transport Rule, would have no CAIR requirements once the Transport Rule 
programs began and so could increase emissions beyond the CAIR 
limitations. Downwind areas that are in attainment (and are not 
experiencing interference with maintenance of such attainment) solely 
because of emission reductions required by CAIR could again face 
nonattainment or interference with maintenance problems because the 
current protection from upwind pollution from such an upwind state 
would not be replaced. In short, the analysis of whether a state should 
be included in a rule eliminating and replacing CAIR cannot logically 
assume that CAIR remains in place. For these reasons, EPA believes it 
is reasonable to use a base case that does not assume that the CAIR 
reduction requirements will continue to be achieved and so does not 
include CAIR-specific emission reductions.
    As a result, EPA's 2012 base case shows emissions higher than 
current levels in some states. In the absence of the CAIR 
SO2 and NOX programs that EPA has been directed 
to eliminate and replace, utility emissions in CAIR states will be 
limited only by non-CAIR constraints including the Acid Rain Program, 
the NOX SIP Call, New Source Performance Standards, any 
state laws and consent order requiring emission reductions, and any 
other permanent and enforceable binding reduction commitments. This 
will lead to increased emissions in some states in the 2012 base case 
relative to current emissions. For example, efforts to comply with the 
Acid Rain Program at the least cost may occur, in some cases, without 
the operation of existing scrubbers through use of readily available, 
inexpensive Title IV allowances.
    It is important to note that, to the extent that emission 
reductions currently required by CAIR are also reflected in emission 
reduction requirements under the Acid Rain Program, the NOX 
SIP Call, New Source Performance Standards, any state laws and consent 
orders requiring emission reductions, and any other enforceable binding 
reduction commitments, such reductions are accounted for in EPA's 2012 
base case. Some commenter claimed that in excluding CAIR-specific 
emission reductions from the base case, EPA ignores non-CAIR legal 
requirements (e.g., in Title V permits) that may prevent sources from 
increasing emissions above CAIR levels. Such allegations are incorrect. 
As discussed elsewhere in this preamble, EPA accounted for any Title V 
permits, consent decrees, state rules, and other enforceable 
limitations on sources' emissions; if these non-CAIR limitations 
effectively restrain a state's emissions to not exceed the state's CAIR 
limitations, EPA's base case modeling would reflect this outcome. 
Commenters also assert that utilities are unlikely to dismantle or 
discontinue running the installed controls to the point of returning to 
pre-CAIR emission levels. EPA agrees that installed controls are not 
likely to be physically dismantled, and as discussed elsewhere in this 
preamble, EPA's analysis properly treats the capital investments made 
in emission controls attributed to CAIR as ``sunk'' capital costs 
(i.e., capital costs already obligated in the past) that are not 
included as costs of meeting Transport Rule requirements.
    Our cost analysis for significant contribution reflects on-the-
ground realities. Investments in pollution control equipment were made 
in response to CAIR requirements. Those expenditures are ``sunk'' 
capital costs, meaning that those investments were committed in the 
past, prior to the Transport Rule. Adding the capital costs of that 
equipment into the costs of Transport Rule emission reduction options 
would be incorrect; those capital investments are represented in place 
in the base case.
    However, given ongoing costs associated with operating these 
controls, EPA believes sources would have an economic incentive to 
discontinue operating installed controls, or to operate those controls 
less effectively, except to the extent non-CAIR legal requirements 
mandate emission reductions or to the extent that sources would find it 
economic to operate the controls for non-CAIR market-based emission 
control programs. EPA properly treats the costs of operating controls 
installed to meet CAIR requirements as costs of meeting Transport Rule 
requirements.\17\ EPA's base case accounts for non-CAIR requirements 
and does not make the unreasonable assumption that installed controls 
would be operated to achieve emission reductions that are not necessary 
to meet non-CAIR requirements. For all of these reasons, EPA rejects 
commenters' claims that the base case is ``unrepresentative'' or lacks 
``a rational relationship to the real world.''
---------------------------------------------------------------------------

    \17\ For more details on how EPA models economic operation of 
existing pollution control equipment in the Transport Rule base 
case, please see Section 6 (``Dispatchable Controls'') in ``Updates 
to EPA Base Case v3.02 EISA Using the Integrated Planning Model'' 
Technical Support Document (TSD) for the Transport Rule Docket ID 
No. EPA-HQ-OAR-2009-0491, U.S. EPA, July 2010 (available at http://www.epa.gov/airmarkets/progsregs/epa-ipm/IPM Update 
Documentation.pdf).
---------------------------------------------------------------------------

C. Air Quality Modeling To Identify Downwind Nonattainment and 
Maintenance Receptors

1. Emission Inventories
    To inform air quality modeling for the development of the final 
Transport Rule, EPA developed emission

[[Page 48225]]

inventories for a 2005 base year and for 2012 and 2014 projections. The 
inventories for all years include emission estimates for EGUs, non-EGU 
point sources, stationary nonpoint sources, onroad mobile sources, 
nonroad mobile sources, and biogenic (non-human) sources. EPA's air 
quality modeling relies on this comprehensive set of emission 
inventories because emissions from multiple source categories are 
needed to model ambient air quality and to facilitate comparison of 
model outputs with ambient measurements. In addition, EPA considers all 
relevant emissions (regardless of source category) when determining 
whether a state is found to be significantly contributing to or 
interfering with maintenance of a particular NAAQS in another state.
    The emission inventories were processed through the Sparse Matrix 
Operator Kernel Emissions (SMOKE) Modeling System version 2.6 to 
produce the gridded, hourly, speciated, model-ready emissions for input 
to the CAMx air quality model. Additional information on the 
development of the emission inventories and related data sets for 
emissions modeling are provided in the Emission Inventory Final 
Transport Rule TSD.
    On October 27, 2010, EPA issued a NODA on ``Revisions to Emission 
Inventories.'' The NODA's primary purpose was to notify the public 
about changes to emission inventories made since the proposal modeling. 
The affected emission sectors were non-EGU stationary point sources, 
nonpoint sources, and Category 3 commercial marine vessel sources. The 
NODA also presented a newly released model for developing onroad mobile 
source emissions for use in air quality modeling for the final 
Transport Rule.
    The major comments received in response to the emission inventories 
and modeling included in the proposed Transport Rule and the October 27 
NODA are summarized in the following subsections. EPA agreed with the 
comments summarized below and adopted technical corrections or updates 
to the emission inventories and modeling accordingly. For EPA to be 
able to take appropriate action, comments on the emission inventories 
needed to be specific enough to allow for credible alternative data 
sources to be located. EPA adopted corrections from comments on in-
place control programs or devices where the controls were enforceable 
and quantifiable.
a. Foundation Emission Inventory Data Sets
    EPA developed emission data representing the year 2005 to support 
air quality modeling of a base year from which future air quality could 
be forecasted. EPA used the 2005 National Emission Inventory (NEI), 
version 2 from October 6, 2008, as the chief basis for the U.S. 
inventories supporting the 2005 air quality modeling. This inventory 
includes 2005-specific data for point and mobile sources, while most 
nonpoint data were carried forward from version 3 of the 2002 NEI. The 
future base case scenarios modeled for 2012 and 2014 represent 
predicted emission reductions primarily from already promulgated 
federal measures.
    EPA used a 2006 Canadian inventory and a 1999 Mexican inventory for 
the portions of Canada and Mexico within the air quality modeling 
domains for all modeled scenarios. Emissions from Canada and Mexico for 
all source sectors (including EGUs) in these countries were held 
constant for all base- and future-year cases. EPA made this assumption 
because it does not currently have sufficient data to support 
projections of future-year emissions from Canada and Mexico.
b. Development of Emission Inventories for EGUs
    The annual NOX and SO2 emissions for EGUs in 
the 2005 NEI v2 are based primarily on data from continuous emissions 
monitoring systems (CEMS), with other EGU pollutants estimated using 
emission factors and annual heat input data reported to EPA. Although 
only NOX and SO2 are considered for control in 
this rule, emissions for all criteria air pollutants are necessary to 
model air quality. For EGUs without CEMS, EPA used data submitted to 
the NEI by the states. For more information on the details of how the 
2005 EGU emissions were developed, see the Emissions Inventory Final 
Rule TSD.
    Commenters stated that some point sources that were classified as 
non-EGUs in the proposal modeling were actually EGUs, resulting in 
double counting of emissions in future-year modeling. EPA reviewed its 
assignment of EGUs and non-EGUs and reclassified EGU sources found to 
be in the non-EGU inventory for the updated 2005 EGU inventory to 
prevent double counting of future-year emissions.
    The future base case scenarios for EGUs reflect projected changes 
to fuel usage and economics, as described in the Emission Inventory 
Final Rule TSD. Future year base case EGU emissions that predict 
SO2, NOX, and PM2.5 were obtained from 
version 4.10--FTransport of the Integrated Planning Model (IPM) outputs 
(http://www.epa.gov/airmarkt/progsregs/epa-ipm/index.html). The IPM is 
a multi-regional, dynamic, deterministic linear programming model of 
the U.S. electric power sector; version 4.10--FTransport reflects state 
rules and consent decrees through December 1, 2010, and incorporates 
public comments on existing controls submitted to EPA through both the 
Transport Rule-related notice and comment process as well as the 
proposed Mercury and Air Toxics Standards Information Collection 
Request (ICR). The operation of existing SO2 or 
NOX advanced controls (e.g., scrubber, SCR) on units that 
were not required to operate those controls for compliance with Title 
IV, New Source Review (NSR), state settlements, or state-specific rules 
was projected by IPM on the basis of providing least cost operation of 
the power generation system subject to existing regulatory requirements 
except CAIR (see baseline discussion in section V.B).
    Additionally, IPM v.4.10--FTransport incorporates comments received 
during the rulemaking process. Fuel-related updates include comment-
driven unit-specific limitations on 2012 coal rank selection, limiting 
unrestricted switching from bituminous to subbituminous coal by 
imposing boiler modification costs for those units shifting from 
bituminous to subbituminous coal without historical precedent, and a 
correction of waste coal prices. Pollution control-related updates 
include keying the performance assumptions for FGD and SCR more closely 
to historic performance data, and the inclusion of dry sorbent 
injection (DSI), a SO2 removal technology. Other notable 
updates include revised assumptions on the heat rate and consequent 
dispatching of cogenerating units and incorporation of additional 
planned retirements. Further details on these updates are available in 
the IPM Documentation, available in the docket and at: http://www.epa.gov/airmarkets/progsregs/epa-ipm/index.html.
c. Development of Emission Inventories for Non-EGU Point Sources
    Details on the development of emission inventories are available in 
the Emission Inventory Final Rule TSD. In both the proposal and final 
modeling, controls on industrial boilers installed under the 
NOX SIP call were assumed to have been implemented by 2005 
and captured in the 2005 NEI v2. The non-EGU point source emissions 
were updated from the 2005 NEI and the

[[Page 48226]]

emissions used for the proposal modeling through the incorporation of 
comments on the proposal emissions values, previously unknown facility 
closures, and through other data improvements as identified by EPA 
analyses.
    EPA does not factor in economic growth to develop non-EGU point 
source emission projections because analysis of historical emission 
trends and economic data did not support using economic growth to 
project non-EGU emissions. More details on the rationale for not 
applying economic growth to non-EGU industrial sources can be found in 
Appendix D of the Regulatory Impact Assessment (RIA) for the PM NAAQS 
rule (http://www.epa.gov/ttn/ecas/regdata/RIAs/Appendix%20D_
Inventory.pdf). Although projections based on economic growth were not 
included, EPA did include reductions resulting from plant and unit 
closures, local and federal consent decrees, and several Maximum 
Achievable Control Technology (MACT) standards.
    For non-EGU point sources, local control programs that may be 
necessary for areas to attain the annual PM2.5 NAAQS and the 
ozone NAAQS are only included in the future base case projections when 
specific information about existing enforceable local controls was 
provided.
    Since aircraft at airports were treated as point emissions sources 
in the 2005 NEI v2, we applied projection factors based on activity 
growth projected by the Federal Aviation Administration Terminal Area 
Forecast (TAF) system, published in December 2008.
    A number of comments were received on the stationary non-EGU point 
source inventories. Below is a summary of the major comments that 
impacted the stationary non-EGU point source inventories for the final 
modeling:
    Comment: Commenters stated that EPA did not properly represent some 
point source emissions in base-year and future-year inventories due to 
facility and unit closures, consent decrees, emission caps, control 
programs, and alternative emission estimates.
    Response: EPA reviewed the sources referenced in the individual 
comments regarding the base-year and future-year inventories. In cases 
where credible alternative data were available, EPA revised the 
emission inventories to incorporate additional facility and unit 
closures, consent decrees, emission caps, control programs, enforceable 
local controls, and alternative emission estimates.
    Comment: Commenters stated that EPA should include controls from 
the National Emission Standards for Hazardous Air Pollutants for 
Reciprocating Internal Combustion Engines (RICE NESHAP) in our 
modeling.
    Response: EPA included reductions expected to be achieved by the 
RICE NESHAP across the United States in our final modeling of 
stationary non-EGU and nonpoint sources.
    Comment: Commenters stated that EPA was not properly representing 
existing or planned controls for cement plants.
    Response: EPA updated control and projection information for cement 
plants based on the latest available data and cement sector-specific 
modeling results.
    Comment: EPA specifically requested comments on whether to 
incorporate emission reduction estimates from the NESHAP for Major 
Sources: Industrial, Commercial, and Institutional Boilers and Process 
Heaters (75 FR 32006). Commenters stated that emission reduction 
estimates should not be included until the rule became final.
    Response: EPA did not incorporate emission reduction estimates from 
the NESHAP for Major Sources: Industrial, Commercial, and Institutional 
Boilers and Process Heaters (75 FR 32006) into the proposal or final 
modeling because the rule was not final at the time the modeling was 
performed. Note that reductions from this rule would not have impacted 
the 2012 base case due to its implementation schedule, and only the 
2014 emissions would have been affected.
d. Development of Emission Inventories for Onroad Mobile Sources
    The onroad emissions in the proposal modeling were primarily based 
on the National Mobile Inventory Model (NMIM) monthly, county, and 
process level emissions along with gasoline exhaust emissions from a 
fall 2008 draft version of the Motor Vehicle Emission Simulator 
(MOVES). A major comment on the proposal modeling for onroad mobile 
sources was the following:
    Comment: Commenters stated that EPA should use a publicly released 
version of MOVES for its final modeling.
    Response: EPA updated the final modeling to use data from the 
publicly released version of the MOVES 2010 model because the model 
became available in time for inclusion of its results in the final 
modeling. It was not used for the proposal modeling because it was not 
available at the time the modeling was performed.
    In the final Transport Rule modeling, EPA used MOVES 2010 state-
month level emissions for all criteria pollutants and all modes 
(evaporative, exhaust, brake wear and tire wear) and allocated those 
emissions to counties according to state-county NMIM emissions ratios. 
For California (the emissions for which are included to support the 
coarse modeling domain), the onroad mobile emissions data were derived 
from data provided by the state. These data were augmented with MOVES 
2010 outputs for NH3 because data for that pollutant had not 
been provided. Additional information on the approach to onroad mobile 
source emissions is available in the Emission Inventory Final Rule TSD.
    In the future-year base modeling for mobile sources, all national 
measures available at the time of modeling were included. The future 
scenarios for mobile sources reflect projected changes to fuel usage, 
as described in the Emission Inventory Final Rule TSD. Emissions for 
these years reflect onroad mobile control programs including the Light-
Duty Vehicle Tier 2 Rule, the Onroad Heavy-Duty Rule, the Light-Duty 
Vehicle Greenhouse Gas Rule, the Renewable Fuel Standards Rule, and the 
Mobile Source Air Toxics (MSAT) final rule.
e. Development of Commercial Marine Category 3 Vessel Emission 
Inventories
    For the 2005 modeling, the commercial marine category 3 (C3) vessel 
emissions, a portion of nonroad mobile emissions, were augmented with 
gridded 2005 emissions from the previous modeling efforts for the rule 
called ``Control of Emissions from New Marine Compression-Ignition 
Engines at or Above 30 Liters per Cylinder.'' Emissions out to 200 
nautical miles from the coastline were allocated to states in the 
proposal modeling. A major comment on the proposal modeling was the 
following:
    Comment: Commenters stated that emissions from commercial marine 
sources (a component of the nonroad emissions in the summaries that 
were provided for the NPR) were too high.
    Response: EPA reviewed the approach used for commercial marine 
C3 emissions in the proposal. In the final modeling, instead 
of using the boundary of 200 nautical miles from the coast as was used 
in the proposal, EPA adopted the Mineral Management Service state-
federal water boundaries that assign state waters 3-10 nautical miles 
from the coast. This approach is consistent with the approach used in 
the 2005 and 2008 National Emission Inventories. In addition, the 
category 3 commercial marine emissions were adjusted to reflect a 
coordination between the Emissions Control Area proposal to the 
International Maritime Organization

[[Page 48227]]

(EPA-420-F-10-041, August 2010) control strategy; reductions of 
NOX, VOC, and CO emissions for new C3 engines 
starting in 2011; and fuel sulfur limits that go into effect as early 
as 2010.
f. Development of Emission Inventories for Other Nonroad Mobile Sources
    The nonroad mobile source emissions for sources other than 
C3 marine were primarily based on NMIM monthly, county, and 
process level emissions from the 2005 NEI v2. These emissions were 
unchanged from proposal modeling, except for PM emissions in California 
that were updated to correct for missing emissions in a few counties 
and source categories.
    Nonroad mobile emissions were created for future years with NMIM 
using an approach consistent with that used for 2005. The nonroad 
emissions for 2012 and 2014 were calculated using NMIM future-year 
equipment population estimates and control programs. Nonroad mobile 
emission reductions for 2012 and 2014 include reductions to 
locomotives, various nonroad engines including diesel engines and 
various marine engine types, fuel sulfur content, and evaporative 
emissions standards. A more comprehensive list of control programs 
included for mobile sources is available in the Emission Inventory 
Final Rule TSD.
    The 2012 and 2014 nonroad mobile emissions for locomotives and 
category 1 and 2 (C1 and C2) commercial marine vessels were based on 
emissions published in EPA's Locomotive Marine Rule, Regulatory Impact 
Assessment, Chapter 3.
g. Development of Nonpoint Emission Inventories
    For the proposal Transport Rule modeling, EPA augmented the 2002 
NEI nonpoint emission inventory with a non-California Western Regional 
Air Partnership (WRAP) oil and gas exploration inventory, which 
includes emissions in several states within the eastern U.S. 12 km 
modeling domain and additional states within the national 36 km 
modeling domain. For the final Transport Rule modeling, EPA updated the 
nonpoint emission estimates for oil and gas sources. EPA continued to 
use the same WRAP inventory from the proposal, emissions in Texas and 
Oklahoma were updated but for the final modeling with data from the 
Texas Commission on Environmental Quality (TCEQ) and the Oklahoma 
Department of Environmental Quality (DEQ), respectively.
    The average-year county-based inventories for wildfire and 
prescribed burning emissions were unchanged between the proposal and 
final modeling.
    For stationary nonpoint sources, local control programs that may be 
necessary for areas to attain the annual PM2.5 NAAQS and the 
ozone NAAQS are not included in the future base case projections unless 
specific information about existing enforceable controls was available 
(e.g., ozone SIP controls from Ozone Transport Commission rules that 
impact source categories such as Consumer Products, Solvent Cleaning, 
Adhesives and Sealants). EPA specifically requested comment on local 
control data as part of the proposal and the October 27 NODA, and 
incorporated any usable data that was provided into the final 
inventories.
    For stationary nonpoint sources, refueling emissions were projected 
using the refueling results from the NMIM runs performed for the onroad 
mobile sector.
    Portable fuel container emissions were projected to future years 
using estimates from previous OTAQ rulemaking inventories. Emissions of 
ammonia and dust from animal operations were projected based on animal 
population data from the Department of Agriculture and EPA. Residential 
wood combustion was projected by replacement of obsolete wood stoves 
with new wood stoves and a 1 percent annual increase in fireplaces. 
Landfill emissions were projected using MACT controls. All other 
nonpoint sources were held constant between 2005 and the future years.
    Some specific adjustments to the inventories were made in the final 
modeling to address comments that were received as described below. 
Area source MACT programs and controls from the RICE NESHAP were 
included in the final modeling to address submitted comments, as were 
fuel sulfur controls that were enforceable and that take effect by 
2014.
    The major comments that impacted the nonpoint sectors are as 
follows:
    Comment: Commenters stated that the SO2 emissions from 
industrial fuel combustion in Nebraska EPA are too high.
    Response: EPA reviewed the NEI 2002-based data that had been used 
for the proposal modeling and determined that emissions from the 2005 
inventory compiled for the Central Regional Air Planning Association 
(CENRAP) were more up to date for this source category and based on 
more localized data sources. The 2005 CENRAP emissions for industrial 
fuel combustion were used in the final modeling.
    Comment: Commenters stated that EPA should include sulfur rule 
controls that take effect prior to the future years that were modeled.
    Response: EPA included quantifiable sulfur rule controls in 2014 
modeling for those states that had implemented the rules (New Jersey 
and Maine).
    Comment: A commenter stated that emissions for Delaware were 
overestimated for several nonpoint categories in base-year and future-
year inventories and provided alternative estimates for these 
categories.
    Response: EPA reviewed the alternative estimates provided and found 
them to be credible and based on more detailed local scale information 
than were available in the national inventories. EPA incorporated the 
alternative emission estimates for Delaware into the final modeling.
    Comment: A commenter stated that residual oil is not used as an 
industrial fuel in South Carolina.
    Response: EPA analyzed the emissions from residual oil industrial 
fuel combustion in South Carolina and all other states, and analyzed 
preliminary regional planning office inventories and the 2008 NEI 
submittals. The South Carolina residual oil industrial fuel emissions 
were determined to be anomalously large in comparison to the near zero 
emissions in other submittals and were therefore removed from the 
nonpoint inventory.
2. Air Quality Basis for Identifying Receptors
a. Introduction
    In this section, we describe the final approach to identify 
downwind nonattainment and maintenance receptors. We briefly summarize 
the modeling platform, the proposed approach to identify receptors, 
comments received, and the results of the final analysis.
    In the Transport Rule, EPA has explicitly given independent meaning 
to the ``interfere with maintenance'' prong of section 
110(a)(2)(D)(i)(I) by evaluating contributions to identified 
maintenance receptors as well as contributions to identified 
nonattainment receptors. EPA identified maintenance receptors as those 
receptors that would have difficulty maintaining the relevant NAAQS in 
a scenario that takes into account historic variability in air quality 
at that receptor. Specifically, EPA projects future air quality design 
values based on measured data during the period 2003 to 2007. In 
determining the downwind receptors of concern, EPA

[[Page 48228]]

does not solely rely on the projection of an average design value based 
on measured data from the relevant period (in this case 2003 to 2007) 
to make a determination of ``attainment'' or ``nonattainment.'' 
Instead, EPA also evaluates the maximum future design value at that 
receptor based on measured data over the relevant period. Receptors for 
which this latter analysis projects design values higher than the NAAQS 
are identified as maintenance receptors.
    EPA believes it is appropriate and reasonable to use this approach 
to identify receptors that may have maintenance problems in the future. 
This approach uses measured data in order to establish potential air 
quality outcomes at each receptor that take into account the variable 
meteorological conditions present across the entire period of measured 
data (2003 to 2007). EPA interprets the maximum future design value to 
be a potential future air quality outcome consistent with the 
meteorology that yielded maximum measured concentrations in the ambient 
data set analyzed for that receptor. In other words, the average design 
value gives a reasonable projection of future air quality at the 
receptor under ``average'' conditions. However, EPA also recognizes 
that previously experienced meteorological conditions (e.g., dominant 
wind direction, temperatures, air mass patterns) promoting ozone or 
fine particle formation that led to maximum concentrations in the 
measured data may reoccur in the future. The maximum design value gives 
a reasonable projection of future air quality at the receptor under a 
scenario in which such conditions do, in fact, reoccur. It also 
identifies upwind emissions that under those circumstances could 
interfere with the downwind area's ability to maintain the NAAQS.
    Per the court's opinion in North Carolina, it is necessary for the 
Agency to evaluate ``interference with maintenance'' separately from 
``significant contribution to nonattainment'' in order to give 
independent meaning to that phrase in the statute. The approach 
described above does so and provides a reasonable basis for identifying 
upwind emissions that interfere with maintenance of the NAAQS at 
downwind receptors.
    Because the methodology is based on actual variations in design 
values measured at the receptors, EPA believes that the application of 
this design value methodology for identifying maintenance receptors 
reasonably anticipates possible future air quality outcomes based on 
meteorological conditions independent of emission reduction 
requirements occurring between 2005 (the base year for air quality 
analysis) and 2012 (the future year for air quality analysis of the 
base case without CAIR or the Transport Rule in place). EPA uses air 
quality modeling to properly account for changes in air quality from 
2005 to 2012 due to emission control requirements and trends in 
emission source fleet turnover (such as increasingly cleaner motor 
vehicle fleets). The air quality modeling process allows EPA to 
effectively adjust measured data to project design values in 2012 based 
on the forecast changes in emissions. For a given receptor, the 
forecast change in emissions from 2005 to 2012 is a constant factor 
applied across all of the design values from the period 2003 to 2007. 
Thus, a comparison of the projected (future-year) design values 
themselves is equivalent to comparing the base period design values 
from the data set to consider how pollution concentrations are affected 
by non-modeled factors such as environmental and meteorological 
variability independent of the forecast emission reductions that stem 
from successful imposition of emission limitations and controls on 
various sources between the base and future modeling years. EPA 
believes it is reasonable to anticipate that these year-to-year 
meteorological fluctuations may reoccur at any time in the future and 
are relevant to determining receptors that are at risk of having a 
problem in the future with maintenance of the NAAQS. Therefore, EPA 
assesses the relationship of the maximum projected design value for 
2012 at each receptor to the relevant NAAQS, and where such a value 
exceeds the NAAQS, EPA determines that receptor to be a ``maintenance'' 
receptor for purposes of defining interference with maintenance under 
the Transport Rule.
    To provide an illustrative example, consider a hypothetical 
receptor ``Y'' whose measured data for 2003-2007 yields three design 
values for annual fine particles: 17 for 2003-05; 14 for 2004-06; and 
12 [micro]g/m\3\ for 2005-07. Thus, the maximum measured design value 
for this period is 17 and the average design value is 14.3. To 
determine whether the receptor is a nonattainment or maintenance 
receptor, EPA projects a corresponding future-year (2012) design value 
for each measured design value. These projections are based on the 
results of air quality modeling, which demonstrates predicted changes 
in pollution concentrations for each receptor from 2005 to 2012. For 
this example, assume that the projected future-year design values that 
correspond with the measured design values, are 16 (corresponds with 
the 2003-05 design value of 17), 13 (corresponds with the 2004-06 
design value of 14), and 11 [micro]g/m\3\ (corresponds with the 2005-07 
design value of 12). The average future-year design value is 13.3 
(corresponds with the average measured design value from 2003-2007 of 
14.3). The projected future design values are all lower than the 
measured design values because air quality is projected to improve 
between 2005 and 2012. In this example, the analysis establishes that 
the average projected future design value is 13.3 and the maximum 
projected future design value is 16.
    The average future (2012) projected design value of 13.3 based on 
the average design value for the period 2003-07 does not exceed the 
1997 annual PM2.5 NAAQS. For this reason, EPA would conclude 
that receptor Y will most likely have attainment air quality in the 
future year. Therefore, it would not be identified as a nonattainment 
receptor.
    However, the future projected design value of 16 based on the 
maximum design value for the period 2003-07 does exceed the NAAQS. For 
this reason, EPA would conclude that the receptor may have difficulty 
maintaining attainment with the NAAQS under future potential 
meteorological conditions. EPA therefore would identify the receptor as 
a maintenance receptor and evaluate whether upwind state emissions 
interfere with maintenance of the NAAQS at that receptor.
    EPA's methodology accounts for the range of meteorological 
conditions reflected by design values from the measured 2003-2007 data 
at receptor Y and also accounts for the projected changes in emissions 
from 2005 to 2012 at receptor Y. The range of meteorological conditions 
is accounted for by using data from three different 3-year periods as 
described above. The projected changes in emissions are accounted for 
by applying to the measured design values the forecasted change in 
PM2.5 concentrations, as determined through air quality 
modeling of the 2005 and 2012 emissions. In this example, the maximum 
measured design value for receptor Y is 17. This design value 
represents measured data from 2003 to 2005. EPA applies to this design 
value the modeled 2005-to-2012 change in concentrations at receptor Y 
to obtain a 2012 maximum design value for that

[[Page 48229]]

receptor, which is 16. In this way, this maximum 2012 design value 
takes into consideration the air quality impacts of all known and 
legally applicable emission limitations taking effect after the 2003 to 
2005 base period. Therefore, each of the projected future-year design 
values provide a fair representation of future air quality at receptor 
Y under different conditions while accounting for the emissions 
projected to remain in 2012. EPA thus believes that if one of these 
future-year design values for a particular receptor exceeds the NAAQS, 
it is reasonable to conclude that the area may have difficulty 
maintaining that NAAQS. For this reason, EPA identifies such receptors 
as maintenance receptors. In this example, EPA would find that while 
receptor Y's average future-year design value would not exceed the 
NAAQS, its maximum future-year design value (16) would exceed the 
NAAQS, and it would thus be designated as a ``maintenance'' receptor 
for purposes of the Transport Rule analyses.
    In the proposed rule we used air quality modeling to (1) Identify 
locations where we expected there to be nonattainment and/or 
maintenance problems for annual average PM2.5, 24-hour 
PM2.5, and/or 8-hour ozone in 2012, (2) quantify the impacts 
(i.e., air quality contributions) of SO2 and NOX 
emissions from upwind states on downwind annual average and 24-hour 
PM2.5 concentrations at monitoring sites projected to be 
nonattainment or have maintenance problems in 2012 for the 1997 annual 
and 2006 24-hour PM2.5 NAAQS, respectively, and (3) quantify 
the impacts of NOX emissions from upwind states on downwind 
8-hour ozone concentrations at monitoring sites projected to be 
nonattainment or have maintenance problems in 2012 for the 1997 ozone 
NAAQS.
    To support the proposal, air quality modeling was performed for 
four emission scenarios: a 2005 base year, a 2012 ``no CAIR'' base 
case, a 2014 ``no CAIR'' base case, and a 2014 control case that 
reflects the emission reductions expected from the FIPs. The modeling 
for 2005 was used as the base year for projecting air quality for each 
of the 3 future-year scenarios. The 2012 base case modeling was used to 
identify future nonattainment and maintenance locations and to quantify 
the contributions of emissions in upwind states to annual average and 
24-hour PM2.5 and 8-hour ozone. The 2012 ozone and 
PM2.5 concentrations were derived by projecting 2003 through 
2007 based ambient ozone and/or PM2.5 data to the future 
using the relative (percent) change in modeled concentrations between 
2005 and 2012. The 2014 base case and 2014 control case modeling were 
used to quantify the benefits of this proposal.
    In the proposed rule, EPA used the Comprehensive Air Quality Model 
with Extensions (CAMx) version 5.20 \18\ to simulate ozone and 
PM2.5 concentrations for the 2005 base year and the 2012 and 
2014 future year scenarios. The CAMx model applications were designed 
to cover states in the central and eastern U.S. using a horizontal 
resolution of 12 x 12 km.\19\
---------------------------------------------------------------------------

    \18\ Comprehensive Air Quality Model with Extensions Version 5 
User's Guide. Environ International Corporation. Novato, CA. March 
2009.
    \19\ The 12 km domain was nested within a coarse grid, 36 x 36 
km modeling domain which covers the lower 48 states and adjacent 
portions of Canada and Mexico. Predictions from this Continental 
U.S. (CONUS) domain were used to provide initial and boundary 
concentrations for simulations in the 12 km domain.
---------------------------------------------------------------------------

    CAMx contains ``source apportionment'' tools that are designed to 
quantify the contribution of emissions from various sources and areas 
to ozone and PM2.5 component species in other downwind 
locations. The source apportionment tools were used to quantify the 
downwind contributions of ozone and PM2.5 from upwind 
states.
    In the proposed rule, EPA used a 2005-based air quality modeling 
platform which included 2005 base year emissions and 2005 meteorology 
for modeling ozone and PM2.5 with CAMx.
    We received comments related to several aspects of the air quality 
modeling platform.
    Comment: There was wide support from commenters for the use of CAMx 
as an appropriate, state-of-the science air quality tool for use in the 
Transport Rule. There were no comments that suggested that EPA should 
use an alternative model for quantifying interstate transport. Many 
commenters requested that EPA update the emission inventories used for 
the Transport Rule and then remodel the 2005 base year and future year 
emissions using the updated emissions and the most recent version of 
CAMx to reassess interstate transport for the final rule.
    Response: For the final rule we have updated our modeling using the 
latest public release of CAMx (version 5.30) and associated 
preprocessors. We have also made numerous improvements to the emission 
inventories for the 2005 base year as well as the 2012 and 2014 future 
year base cases in response to public comments. The emissions changes 
are described in section V.C.1. The projection of future year 
nonattainment and maintenance sites and the quantification of ozone and 
PM2.5 transport for the final rule are based on modeling 
with CAMx v5.30 using the updated emission inventories. The final rule 
air quality projections of 2012 nonattainment and maintenance are 
described below. The final rule interstate contributions are presented 
in section V.D.
    Comment: The performance evaluation of the 2005 base year model 
predictions for the proposed rule was too cursory and did not provide 
sufficient detail on model performance. Commenters requested additional 
analyses and spatial resolution describing how well base year model 
predictions compare to the corresponding measured values.
    Response: For the final rule we have expanded the scope of the 
model evaluation for 2005 to include a broader suite of statistics to 
characterize performance for individual subregions of the eastern U.S. 
modeling domain. The results of the performance evaluation for the 
final rule 2005 base year air quality modeling are described in the Air 
Quality Modeling Final Rule TSD.
    Comment: The 2005 based modeling platform should be updated to a 
more recent year. There were several different aspects of this comment. 
Some commenters stated that EPA should be using a more recent emission 
inventory as a base year, due to identified changes and updates to the 
inventories. Other commenters stated that EPA should use a more recent 
base year, due to a trend of improvement in air quality over the past 
few years. The commenters claim that the 2005-based EPA modeling does 
not account for large emission reductions and air quality improvements 
that have occurred over the last several years.
    Response: There are several reasons why the use of a 2005 modeling 
base case is both reasonable and, in fact, necessary for the Transport 
Rule. As explained in section V.B, above, because the Transport Rule 
will replace CAIR, EPA cannot consider reductions associated with CAIR 
in the analytical baseline emissions scenario. Thus, the base year for 
the air quality projections should be a year that represents emissions 
before CAIR was in place (i.e. 2005). We are projecting emissions to a 
future 2012 ``no CAIR'' case and therefore want to best represent the 
air quality change between 2005 and 2012, without CAIR. To do this, we 
projected emissions that existed before CAIR was in effect and modeled 
the air quality change that occurs between 2005 and 2012 without CAIR.

[[Page 48230]]

    A key consideration in our projection methodology is the use of 
ambient data to anchor the design value projections to the future. The 
modeling is used in a relative sense by multiplying the modeled percent 
change in ozone or PM2.5 species concentrations by the base 
year ambient data. The ozone and PM2.5 modeling guidance 
recommends projecting design values based on 5 years \20\ of monitoring 
data that is centered on the base model year. Using 2005 as a base 
emissions and meteorological year entailed the use of 2003-2007 ambient 
air quality data (5 years of data centered about 2005). This was a 
reasonable choice because the majority of the ambient data from this 
period was not impacted by CAIR emission reductions.
---------------------------------------------------------------------------

    \20\ The modeling guidance recommends using a five year weighted 
average design value. This is calculated by averaging the three 
consecutive design value periods of 2003-2005, 2004-2006, and 2005-
2007.
---------------------------------------------------------------------------

    After 2005, early emission reductions of SO2 and 
NOX in response to CAIR began to impact the measured air 
quality concentrations. Since the modeling projection methodology uses 
both modeled and observed data, 2005 is the latest base year that we 
deemed appropriate (before CAIR emission reductions took place) for use 
in projecting the measured air quality to a 2012 future year. The early 
years of the 5 year period (2003, 2004, and 2005) were not impacted by 
CAIR.\21\ The last 2 years in the period (2006 and 2007) were slightly 
impacted by CAIR emission reductions. But the 5 year average is 
weighted towards the middle year of the period (2005), so the impact of 
the years after CAIR promulgation should be minimal.
---------------------------------------------------------------------------

    \21\ The CAIR final rule was published on May 12, 2005.
---------------------------------------------------------------------------

    The 2005 base year was also chosen because it was an appropriate 
meteorological year. In the eastern U.S. there was relatively high 
ozone during the summer of 2005 and relatively high PM2.5 
periods during the year. The modeled attainment tests for both ozone 
and 24-hour PM2.5 depend on having a sufficient number of 
``high'' modeled days to project to the future. Modeling a year that is 
not meteorologically conducive to ozone and/or PM2.5 
formation is discouraged by the modeling guidance because a 
meteorological year that is not conducive to ozone or PM2.5 
formation may be less responsive to changes in emissions in the future. 
Therefore, projecting the relative change in ozone or PM2.5 
for a non-conducive base year may underestimate the future change in 
ozone and/or PM2.5 concentrations.
    Additionally, all enforceable emission reductions that occurred 
between 2005 and 2012 (other than those required under CAIR) are 
captured by the modeling system. Any enforceable non-EGU emission 
reductions due to existing rules or the installation of emissions 
controls after 2005 were included in the 2012 base case inventory. As 
explained above in section V.B, to capture changes in EGU emissions 
between 2005 and 2012, EPA did not assume operation of all controls 
installed during that time period, as many of those controls were built 
in response to CAIR. EPA used IPM to project 2012 EGU emissions 
incorporating all non-CAIR enforceable emission constraints; operation 
of existing pollution controls was taken into account only where non-
CAIR constraints made it economic or legally necessary to operate them. 
We also accounted for permanent source shutdowns that occurred after 
2005. Where possible, we incorporated reported emission changes based 
on comments to the proposed rule and a subsequent emission inventory 
NODA.
    Comment: Several commenters stated that we used a ``modeled + 
monitored'' test in CAIR to identify future year nonattainment 
receptors, but we only used a modeled test in the Transport Rule 
proposal. They suggest that we should either go back to the ``modeled + 
monitored'' test or explain why we should not use monitoring data in 
the identification of nonattainment and maintenance receptors. They say 
that we should not base nonattainment and maintenance receptors solely 
on modeled violations. They also say that we if we had looked at the 
most recent ambient data we would see that most of the modeled 
nonattainment and maintenance receptors are already attaining the ozone 
and/or PM2.5 NAAQS.
    Response: In the identification of future year nonattainment 
receptors for CAIR, EPA used what was called the ``modeled + monitored 
test''. The most recent ambient data (2001-2003 design values at the 
time) were examined to further verify that nonattainment was still 
being measured at potential future year nonattainment receptors. In the 
proposed Transport Rule, EPA identified future year nonattainment and 
maintenance receptors based on modeled projections of ambient data from 
the 2003-2007 time period. The future year receptors were not compared 
to most recent ambient data to verify that nonattainment still existed.
    For the final Transport Rule, there are several reasons that EPA 
did not examine the most recent ambient data to verify that receptors 
were still measuring nonattainment. The main reason for dropping the 
``monitored'' part of the modeled + monitored test is the fact that the 
most recent monitoring data (2007-2009 design values) include large 
emission reductions from CAIR. As explained in section V.B, above, 
because the Transport Rule will replace CAIR, we must model a future 
year base case which does not assume that CAIR is in place (a ``no-
CAIR'' case). It is simply not appropriate to examine the current 
monitoring data, which represent air quality with CAIR emission 
reductions in place, and compare the values to 2012 projected air 
quality that is based on a no-CAIR modeling case. As discussed above, 
we modeled a 2005 base case with pre-CAIR emissions and a 2012 future 
``no CAIR'' case. The change in modeled air quality is due to the non-
CAIR enforceable emission changes between 2005 and 2012 and therefore 
explicitly does not take CAIR into account. As a consequence, the 2012 
projected design values represent a unique case (necessary for 
analyzing future air quality without either CAIR or its replacement 
Transport Rule in effect) that cannot be represented by current ambient 
data.
    It is also important to note that all of the projected 2012 design 
values are based on projections of measured ambient data. They are a 
combination of measured data and modeled response factors. Therefore, 
it is inaccurate to imply that future year nonattainment and 
maintenance receptors are solely based on modeled projections. The 
future year concentrations are firmly rooted in base year measured 
ambient data that have been projected to the future using modeled data.
    There are additional reasons for not verifying the nonattainment 
and maintenance receptors against the most recent ambient data. In CAIR 
we did not explicitly identify maintenance receptors. In the Transport 
Rule proposal we identified maintenance receptors based on 2012 
projections of maximum design values from the 2003-2007 period. Even 
though receptors may be measuring attainment based on recent data, they 
may still be at risk for falling back into nonattainment. Therefore, 
even if commenters argue that recent data show that monitoring sites 
should not be nonattainment receptors (with which we disagree), the 
same argument cannot be made regarding maintenance receptors. Clearly, 
receptors with recent ``clean'' ambient data may still experience 
higher PM2.5 and/or ozone concentrations in the future 
(based on

[[Page 48231]]

meteorological and emission variability) and therefore may be 
appropriate maintenance receptors.
    Comment: Several commenters claim that the maintenance receptor 
methodology overstates actual future design values. They also recommend 
an alternative methodology which takes into account the downward trend 
in observed PM2.5 concentrations over the last 5+ years. The 
methodology would remove the trend in the data where air quality is 
improving over the period by applying a linear fit to the data, 
calculating the residuals and then adding the residuals back to the 
average of the data. Given a site with a downward trend, this has the 
effect of decreasing the calculated maximum values from the early years 
in the period and increasing the values from the end years in the 
period.
    Response: EPA continues to believe that our approach to identify 
maintenance receptors is reasonable and appropriate. For the final 
rule, we continue to identify maintenance receptors by projecting the 
maximum design value from the 2003-2007 period to the future. The 
methodology assumes that the combination of emissions and meteorology 
that occurred in the base period (which led to relatively high ambient 
design values) could happen again in the future (albeit at lower 
emissions levels). There is no information presented by the commenters 
which explains why the magnitude of base year design value variability 
could not occur in the same way in the future. The commenters cite the 
downward trend in ambient data as the reason why the EPA methodology is 
not reasonable. However, in most cases, the recent downward trend in 
ambient data is due to a combination of ongoing emission reductions 
(which includes CAIR), variability in meteorology, and depressed 
emissions due to the recession. In fact, the most recent ambient design 
value period (2007-2009) is heavily influenced by extremely low ozone 
and PM2.5 concentrations measured in 2009. The 2009 data are 
marked by relatively low emissions due to cool summer weather and 
ongoing effects of the recession. The preliminary \22\ 2010 ambient 
data in the eastern U.S. show that ozone and PM2.5 values 
were considerably higher in 2010 compared to 2009. In the states that 
are included in the final Transport Rule region, there were 158 ozone 
monitor days that exceeded 84 ppb in 2009 compared to 412 monitor 
exceedance days in 2010. For PM2.5, there were 251 monitor 
days that exceeded 35 [mu]g/m \3\ in 2009 compared to 417 monitor 
exceedance days in 2010. Even though the SO2 and 
NOX emissions were generally lower in 2010, the observed 
ozone and PM2.5 concentrations were higher. This shows the 
important influence of meteorology on ambient concentrations. Clearly, 
the year to year variability due to meteorology can be large. We 
acknowledge the downward trend in ambient data over the last few years. 
But this does not mean that conditions that led to high ozone and/or 
PM2.5 in the 2003-2007 period could not occur again in the 
future. The 2010 ambient data show that meteorology can cause 
concentrations to go back up, even though there is a downward trend in 
emissions.
---------------------------------------------------------------------------

    \22\ The 2010 data is preliminary. Exceptional event data has 
not been flagged and removed from the reported data.
---------------------------------------------------------------------------

    We also believe that the alternate maintenance methodology 
presented by the commenter is inappropriate. The EPA modeling for 2012 
(and 2014) appropriately accounts for emission reductions that occur 
after 2005 except for those that should not be considered, as explained 
in section V.B., because they were required only by CAIR. Therefore, 
the starting point design values used to project to the future should 
not be lowered to account for emission reduction trends that occur 
after 2005. Doing so would give ``double credit'' to the more recent 
emission reductions and provides an inappropriate downward adjustment 
to the early design value periods of the 2003-2007 period.
    Comment: One commenter claims that EPA did not follow our own 
modeling guidance by not doing local scale modeling in urban areas with 
high PM2.5 concentration gradients. They suggested that the 
methodology to calculate future year design values should have included 
dispersion modeling to calculate the change in concentration over time 
of primary PM2.5 emissions.
    Response: EPA modeling guidance for PM2.5 attainment 
demonstrations recommends photochemical grid modeling to examine future 
year changes in PM2.5 concentrations. There are several 
optional aspects of the modeling which are recommended in specific 
cases. This includes a recommendation for a ``local area analysis'' 
using a dispersion model. An area with relatively large local primary 
PM2.5 concentration gradients may want to do additional 
modeling to examine the impacts of local controls on its future year 
PM2.5 concentrations. This is particularly important when 
local controls of primary PM2.5 are included as part of the 
attainment demonstration.
    As noted above, a ``local area analysis'' is recommended as part of 
the local attainment demonstration process in specific situations. It 
is impractical for EPA to perform this type of analysis for each local 
area in the regional Transport Rule. National rulemakings are not 
attainment demonstrations. We are not able to perform fine scale 
analyses for each area. For the final rule modeling, we have attempted 
to address all emissions and modeling related comments. We have updated 
the modeling platform to use the latest version of CAMx and are 
continuing to model ozone and PM2.5 at 12km grid resolution, 
which for PM2.5 is a more refined grid resolution compared 
to the CAIR modeling.
    Additionally, there is no evidence presented by the commenter that 
would indicate that the future year PM2.5 concentrations 
from the Transport Rule are biased high. In fact, depending on the 
circumstances, local fine scale grid or dispersion modeling may result 
in lower or higher future year design values. In a fine scale analysis, 
the dominant local primary PM2.5 emissions become a larger 
percentage of the PM2.5 concentrations. Therefore, if the 
local emissions are forecast to decrease, fine scale modeling may lead 
to lower future design values. However, if the local emissions are 
forecast to increase or stay the same between the base and future 
years, local modeling will likely show higher future year design values 
compared to a regional analysis. This points to the fact that perceived 
biases in modeling results may not always be correct.
    In sum, fine scale modeling of local areas may lead to either 
higher or lower future year design values. There is no indication that 
EPA's regional modeling is biased in either direction. EPA's Transport 
Rule modeling generally followed EPA's modeling guidance and is 
appropriate for the purpose of this rulemaking.
    Comment: One commenter completed and submitted a detailed CAMx 
based modeling analysis with a 2008 base year and future years of 2014 
and 2018. The analysis shows that the majority of the proposed rule 
2012 nonattainment and maintenance sites are already attaining based on 
either 2006-2008 or 2007-2009 ambient data. Based on this, the 
commenter claims that air quality has improved more rapidly than 
predicted by EPA's proposed rule modeling. Also, based on the 
commenter's 2014 modeling of CAIR emissions (including utility consent 
decrees and state programs), the commenter concludes that no additional 
controls are needed

[[Page 48232]]

beyond CAIR to bring most or all sites into attainment by 2014.
    Response: As an initial matter, we note that the basic question 
addressed by the commenter, ``whether additional controls beyond CAIR 
are necessary,'' is not on point. As explained previously, the D.C. 
Circuit remanded CAIR to EPA and it remains in place only temporarily. 
The question EPA must answer in this rulemaking, therefore, is not what 
controls in addition to CAIR are necessary but what, if any, 
restrictions on emissions must be put in place to replace CAIR in order 
to satisfy the requirements of section 110(a)(2)(D)(i)(I) of the CAA. 
For this reason, and as explained in greater detail in section V.B of 
this preamble, any analysis of whether beyond CAIR controls are 
necessary is irrelevant to this rulemaking. Nonetheless, we have 
carefully reviewed different aspects of the commenter's analysis. We 
previously addressed comments related to the use of more recent ambient 
data to examine future year nonattainment and maintenance receptors. As 
noted above, the 2006-2008 and 2007-2009 ambient data is heavily 
influenced by several factors. Among them are the emissions reductions 
from CAIR, the relatively low recent observed ozone and 
PM2.5 concentrations at least partially due to non-conducive 
meteorology (particularly in 2009), and the atypical suppression of 
emissions due to the sharp recession. For all of these reasons, we 
believe it is not possible to directly compare the most recent design 
values to the predicted future year 2012 and 2014 design values from 
the Transport Rule. In particular, it is inappropriate to compare 
current design values to EPA's no-CAIR 2012 future year modeling 
results. As noted in the comment summary, the commenter's modeling 
analysis assumed that CAIR was in place in both 2008 and the future 
years. This is a fundamentally different assumption than the modeling 
EPA used to define the Transport Rule nonattainment and maintenance 
receptors in 2012 and is inappropriate for purposes of the Transport 
Rule for reasons described above and in section V.B.
    Additionally, EPA's maintenance methodology chooses the highest of 
three base year design value periods projected to the future. The 
commenter only used a single design value period in their analysis and 
therefore did not fully examine maintenance issues. In fact, the 2014 
nonattainment modeling receptors in the final Transport Rule and the 
commenter's modeling analysis are similar. As documented in section 
VI.D, in the 2014 final rule remedy case, there is only one remaining 
nonattainment area for ozone and one remaining nonattainment area for 
24-hour PM2.5. This is similar to the modeling results 
presented in the comments.\23\ However, EPA modeling identifies 
additional maintenance receptors in 2012 that continue to have 
maintenance issues in 2014.
---------------------------------------------------------------------------

    \23\ The purpose of this comparison is to note that the modeling 
analyses are actually more similar than the commenter implies. 
However, the Transport Rule differs from the commenter's modeling 
due to the assumption that CAIR was in place. CAIR and the Transport 
Rule differ in state coverage and emission budgets. They are 
therefore not directly comparable.
---------------------------------------------------------------------------

    EPA also examined our ozone and PM2.5 projection 
procedures to see if there might be additional reasons for the 
relatively lower current ambient design values (and modeled design 
values in the commenter's analysis) compared to the 2014 remedy modeled 
values. Upon further analysis of EPA's 24-hour attainment test 
methodology, we noted certain discrepancies between the methodology and 
the calculation of the ambient 24-hour design values. In the proposed 
rule 24-hour attainment test, for each PM2.5 monitor, we 
projected the measured 98th percentile concentrations from the 2003-
2007 period to the future. A basic assumption in this methodology is 
that the distribution of high measured days in the base period will be 
the same in the future. For example, if the observed 98th percentile 
day is the 3rd high day for a particular year, we assume that the 1st, 
2nd, and 3rd high days (and subsequent high days) in the future remain 
in the same basic distribution. Further examination of the proposed 
rule modeling found that this is not always the case. In situations 
where there are large summer PM2.5 concentration reductions, 
some of the high days may switch from the summer in the base period to 
the winter in the future period.
    In order to better account for the complicated future response in 
24-hour design values, we have updated the 24-hour attainment 
demonstration methodology to more closely reflect the way 24-hour 
design values are calculated. In the revised methodology, we do not 
assume that the temporal distribution of high days in the base and 
future periods will remain the same. We project a larger set of ambient 
days from the base period to the future and then re-rank the entire set 
of days to find the new future 98th percentile value (for each year). 
More specifically, we project the highest 8 days per quarter (32 days 
per year) to the future and then re-rank the 32 days to derive the 
future year 98th percentile concentrations. In the case of the 
Transport Rule model results, this has the effect of lowering the 
future year 24-hour design values compared to the old methodology. The 
2012 base case design values for all nonattainment and maintenance 
receptors were either unchanged or lower with the revised methodology.
3. How did EPA project future nonattainment and maintenance for annual 
PM2.5, 24-hour PM2.5, and 8-hour ozone?
    Final Rule: In general, the methodology to project ozone and 
PM2.5 concentrations to the future year(s) remains the same 
for the final rule. The proposal modeling followed the modeling 
guidance procedures for projecting ambient design values to future 
years. For the final rule, we continue to follow the basic procedures 
outlined in the guidance. The 8-hour ozone and annual PM2.5 
methodology are unchanged from the proposal. However, the 24-hour 
PM2.5 methodology has been updated in the final rule to be 
more consistent with the calculation of 24-hour PM2.5 design 
values. There were also additional minor updates to the ambient 
data.\24\ The methodology to identify maintenance receptors is also 
unchanged from the proposal. We continue to use the maximum design 
value (projected from the 5 year base period) to calculate future year 
maintenance receptors.
---------------------------------------------------------------------------

    \24\ The base year design values were updated based on the 
latest official data. See http://www.epa.gov/airtrends/values.html.
---------------------------------------------------------------------------

    As noted in the proposal, EPA considers that the maintenance 
concept has two components: Year-to-year variability in emissions and 
air quality, and continued maintenance of the air quality standard over 
time. The way that EPA defined maintenance based on year-to-year 
variability (as discussed in detail here) directly affects the 
requirements of this final rule. EPA also considered whether further 
reductions were necessary to ensure continued lack of interference with 
maintenance of the NAAQS over time (e.g., after 2014). EPA concluded 
that in light of projected emission trends, and also considering the 
emission reductions from this proposed rule, no further reductions are 
required solely for this purpose at PM2.5 and ozone 
receptors for which we are partially or fully determining significant 
contribution for the current NAAQS. (See discussion of emission trends 
in Chapter 7 of TSD entitled ``Emission Inventories,'' included in the 
docket for the Transport Rule proposal.)

[[Page 48233]]

a. Which ambient ozone and PM2.5 data did EPA use for the 
purpose of projecting future year concentrations?
    The final rule modeling continues to use a 2005 base case inventory 
and 2005 meteorology. Therefore, we continue to use ambient data from 
the 2003-2007 period. For each monitoring site, all valid design values 
(up to 3) from this period were averaged together. Since 2005 is 
included in all three design value periods, this has the effect of 
creating a 5-year weighted average, where the middle year is weighted 3 
times, the 2nd and 4th years are weighted twice, and the 1st and 5th 
years are weighted once. We refer to this as the 5-year weighted 
average value. The 5-year weighted average values were then projected 
to the future years that were analyzed for this final rule. The 2003-
2005, 2004-2006, and 2005-2007 design values are accessible at http://www.epa.gov/airtrends/values.html. The design values have been updated 
based on the latest official values. The official values have 
exceptional events removed from the calculations if they are flagged by 
states and concurred with by EPA Regional offices.
    The procedures for projecting annual average PM2.5 and 
8-hour ozone conform to the methodology in the current attainment 
demonstration modeling guidance.\25\
---------------------------------------------------------------------------

    \25\ U.S. EPA, 2007: Guidance on the Use of Models and Other 
Analyses for Demonstrating Attainment of Air Quality Goals for 
Ozone, PM2.5, and Regional Haze; Office of Air Quality 
Planning and Standards, Research Triangle Park, NC.
---------------------------------------------------------------------------

b. Projection of Future Annual and 24-Hour PM2.5 
Nonattainment and Maintenance
(1) Methodology for Projecting Future Annual PM2.5 
Nonattainment and Maintenance
    For the final rule, annual PM2.5 modeling was performed 
for the 2005 base year emissions and for the 2012 base case as part of 
the approach for projecting which locations are expected to be in 
nonattainment and/or have difficulty maintaining the PM2.5 
standards in 2012. We refer to these areas as nonattainment sites and 
maintenance sites respectively.
    Concentrations of PM2.5 in 2012 were estimated by 
applying the modeled 2005-to-2012 relative change in PM2.5 
species to each of the 3-year ambient monitoring data periods (i.e., 
2003-2005, 2004-2006, and 2005-2007) to obtain up to 3 future-year 
PM2.5 design values for each monitoring site. We used the 
highest of these projections at each monitoring site to determine which 
sites are expected to have maintenance problems in 2012. We used the 5 
year weighted average of those projections to determine which 
monitoring sites are expected to be nonattainment in this future year.
    For the analysis of both nonattainment and maintenance, monitoring 
sites were included in the analysis if they had at least one complete 
design value in the 2003-2007 period.\26\ There were 721 monitoring 
sites in the 12 km modeling domain which had at least one complete 
design value period for the annual PM2.5 NAAQS, and 722 
sites which met this criterion for the 24-hour NAAQS.\27\
---------------------------------------------------------------------------

    \26\ If there is only one complete design value, then the 
nonattainment and maintenance design values are the same.
    \27\ Design values were only used if they were deemed to be 
officially complete based on CFR 40 Part 50 Appendix N. The 
completeness criteria for the annual and 24-hour PM2.5 
NAAQS are different. Therefore, there are fewer complete sites for 
the annual NAAQS.
---------------------------------------------------------------------------

    EPA followed the procedures recommended in the modeling guidance 
for projecting PM2.5 by projecting individual 
PM2.5 component species and then summing these to calculate 
the concentration of total PM2.5. EPA's Modeled Attainment 
Test Software (MATS) was used to calculate the future year design 
values. The software (including documentation) is available at: http://www.epa.gov/scram001/modelingapps_mats.htm. Additional details on the 
annual PM2.5 nonattainment and maintenance projections 
methodology can be found in the Air Quality Modeling Final Rule TSD.
    The 2012 annual PM2.5 design values were calculated for 
each of the 721 sites. The calculated annual PM2.5 design 
values are truncated after the second decimal place.\28\ This is 
consistent with the ambient monitoring data truncation and rounding 
procedures for the annual PM2.5 NAAQS. Any value that is 
greater than or equal to 15.05 [micro]g/m\3\ is rounded to 15.1 
[micro]g/m\3\ and is considered to be violating the NAAQS. Thus, sites 
with projected 5-year weighted average (``average'') annual 
PM2.5 design values of 15.05 [micro]g/m\3\ or greater are 
predicted to be nonattainment sites. Sites with projected maximum 
design values of 15.05 [micro]g/m\3\ or greater are predicted to be 
maintenance sites. Note that nonattainment sites are also maintenance 
sites because the maximum design value is always greater than or equal 
to the 5-year weighted average. For ease of reference we use the term 
``nonattainment sites'' to refer to those sites that are projected to 
exceed the NAAQS based on both the average and maximum design values. 
Those sites that are projected to be attainment based on the average 
design value, but exceed the NAAQS based on the maximum design value, 
are referred to as maintenance sites. The monitoring sites that we 
project to be nonattainment and/or maintenance for the annual 
PM2.5 NAAQS in the 2012 base case are the nonattainment/
maintenance receptors used for assessing the contribution of emissions 
in upwind states to downwind nonattainment and maintenance of the 
annual PM2.5 NAAQS.
---------------------------------------------------------------------------

    \28\ For example, a calculated annual average concentration of 
14.94753 * * * becomes 14.94 when digits beyond two places to the 
right of the decimal are truncated.
---------------------------------------------------------------------------

    Table V.C-1 contains the 2003-2007 base case period average and 
maximum annual PM2.5 design values and the corresponding 
2012 base case average and maximum design values for sites projected to 
be nonattainment of the annual PM2.5 NAAQS in 2012. Table 
V.C-2 contains this same information for projected 2012 maintenance 
sites.

        Table V.C-1--Average and Maximum 2003-2007 and 2012 Base Case Annual PM2.5 Design Values ([micro]g/m\3\) at Projected Nonattainment Sites
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                         Final rule        Final rule
          Monitor ID                     State                    County           Average  design   Maximum  design   average design    maximum design
                                                                                   value 2003-2007   value 2003-2007     value 2012        value 2012
--------------------------------------------------------------------------------------------------------------------------------------------------------
010730023....................  Alabama.................  Jefferson..............             18.57             18.94             16.15             16.46
010732003....................  Alabama.................  Jefferson..............             17.15             17.69             15.16             15.64
131210039....................  Georgia.................  Fulton.................             17.43             17.47             15.07             15.10
171191007....................  Illinois................  Madison................             16.72             17.01             15.46             15.73
261630033....................  Michigan................  Wayne..................             17.50             18.16             15.73             16.32

[[Page 48234]]

 
390350038....................  Ohio....................  Cuyahoga...............             17.37             18.10             15.99             16.66
390350045....................  Ohio....................  Cuyahoga...............             16.47             16.98             15.14             15.61
390350060....................  Ohio....................  Cuyahoga...............             17.11             17.66             15.67             16.18
390610014....................  Ohio....................  Hamilton...............             17.29             17.53             15.76             15.98
390610042....................  Ohio....................  Hamilton...............             16.85             17.25             15.40             15.77
390618001....................  Ohio....................  Hamilton...............             17.54             17.90             16.01             16.33
420030064....................  Pennsylvania............  Allegheny..............             20.31             20.75             17.94             18.33
--------------------------------------------------------------------------------------------------------------------------------------------------------

        Table V.C-2--Average and Maximum 2003-2007 and 2012 Base Case Annual PM2.5 Design Values ([mu]g/m\3\) at Projected Maintenance-Only Sites
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                         Final rule        Final rule
          Monitor ID                     State                    County           Average  design   Maximum  design   average design    maximum design
                                                                                   value 2003-2007   value 2003-2007     value 2012        value 2012
--------------------------------------------------------------------------------------------------------------------------------------------------------
180970081....................  Indiana.................  Marion.................             16.05             16.36             14.86             15.16
180970083....................  Indiana.................  Marion.................             15.90             16.27             14.71             15.06
390350065....................  Ohio....................  Cuyahoga...............             15.97             16.44             14.67             15.10
390617001....................  Ohio....................  Hamilton...............             16.17             16.56             14.74             15.10
--------------------------------------------------------------------------------------------------------------------------------------------------------

 (2) Methodology for Projecting Future 24-Hour PM2.5 
Nonattainment and Maintenance
    The procedures for calculating the future year 24-hour 
PM2.5 design values have been updated for the final 
rule.\29\ The revised procedures are in response to comments which 
noted relatively high future year 24-hour PM2.5 design 
values in EPA's modeling of the proposed Transport Rule. The updates 
are intended to make the projection methodology more consistent with 
the procedures for calculating ambient design values.
---------------------------------------------------------------------------

    \29\ There were no updates to the ozone and annual 
PM2.5 attainment test methodology.
---------------------------------------------------------------------------

    As noted above, for the proposed Transport Rule EPA projected for 
each PM2.5 monitor the measured 98th percentile 
concentrations from the 2003-2007 period to the future. As an 
additional check, we also projected the next highest concentrations 
from the three calendar quarters in each year when the 98th percentile 
did not occur in the 2003-2007 base period, to ensure that the future 
year 98th percentile did not switch seasons in the future year compared 
to the base year. A basic assumption in this methodology is that the 
distribution of high measured days in the base period will be the same 
in the future.
    In other words, EPA assumed at proposal that the 98th-percentile 
day could only be displaced ``from below'' in the instance that a 
different day's future concentration exceeded the original 98th-
percentile day's future concentration. In that case, the original 98th-
percentile day may become the 97th- or 96th-percentile day in the 
future year; EPA accounted for this possibility at proposal. EPA did 
not, however, consider that the 98th-percentile day could also be 
displaced ``from above'' in the instance that higher-concentration days 
in the base period were projected to have future concentrations lower 
than the original 98th-percentile day's future concentration. In that 
case, the original 98th-percentile day may become the 99th- or 100th-
percentile day. Because EPA continued to use that day's future 
concentration to determine the monitor's future design value at 
proposal, this sometimes resulted in overstatement of future-year 
design values for 24-hour PM2.5 monitoring sites whose 
seasonal distribution of highest-concentration 24-hour PM2.5 
days changed between the 2003-2007 period and the future year modeling. 
Examination of the proposed rule remedy modeling (2014 remedy case) 
showed that many of the highest PM2.5 days switched from the 
summer in the base period to the winter in the future period. This is 
especially true in areas of the upper Midwest which experience both 
high summer and winter PM2.5 episodes.
    In the revised methodology, we do not assume that the seasonal 
distribution of high days in the base period years and future years 
will remain the same. We project a larger set of ambient days from the 
base period to the future and then re-rank the entire set of days to 
find the new future 98th percentile value (for each year). More 
specifically, we project the highest 8 days per quarter (32 days per 
year) to the future and then re-rank the 32 days to derive the future 
year 98th percentile concentrations. In the case of the Transport Rule 
model results, this has the effect of lowering the future year 24-hour 
design values compared to the old methodology.
    The modeling guidance recommendations for state attainment 
demonstrations have been updated to reflect the changes outlined above. 
Further details on the 24-hour PM2.5 design value 
calculations can be found in the Air Quality Modeling Final Rule TSD. 
The above procedures for determining future year 24-hour 
PM2.5 concentrations were applied for each site. The 24-hour 
PM2.5 design values are truncated after the first decimal 
place. This approach is consistent with the ambient data truncation and 
rounding procedures for the 24-hour PM2.5 NAAQS. Any value 
that is greater than or equal to 35.5 [micro]g/m\3\ is rounded to 36 
[mu]g/m\3\ and is violating the NAAQS. Sites with future year 5-year 
weighted average design values of 35.5 [mu]g/m\3\ or greater, based on 
the projection of 5-year weighted average concentrations, are predicted 
to be nonattainment. Sites with future year maximum design values of 
35.5 [micro]g/m\3\ or greater are predicted to be maintenance sites. 
Note that nonattainment sites for the 24-hour NAAQS are also 
maintenance sites because the maximum design value is always greater 
than or equal to the 5-year weighted average. The monitoring

[[Page 48235]]

sites that we project to be nonattainment and/or maintenance for the 
24-hour PM2.5 NAAQS in the 2012 base case are the 
nonattainment/maintenance receptors used for assessing the contribution 
of emissions in upwind states to downwind nonattainment and maintenance 
of 24-hour PM2.5 NAAQS as part of this final rule.
    Table V.C-3 contains the 2003-2007 base period average and maximum 
24-hour PM2.5 design values and the 2012 base case average 
and maximum design values for sites projected to be 2012 nonattainment 
of the 24-hour PM2.5 NAAQS in 2012. Table V.C-4 contains 
this same information for projected 2012 24-hour maintenance sites.

          Table V.C-3--Average and Maximum 2003-2007 and 2012 Base Case 24-Hour PM2.5 Design Values ([mu]g/m3) at Projected Nonattainment Sites
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                         Final rule        Final rule
          Monitor ID                     State                    County           Average  design   Maximum  design   average design    maximum design
                                                                                   value 2003-2007   value 2003-2007     value 2012        value 2012
--------------------------------------------------------------------------------------------------------------------------------------------------------
010730023....................  Alabama.................  Jefferson..............              44.0              44.2              36.9              37.3
170311016....................  Illinois................  Cook...................              43.0              46.3              37.5              40.4
171191007....................  Illinois................  Madison................              39.1              40.1              36.5              36.8
180970043....................  Indiana.................  Marion.................              38.4              39.9              35.7              37.1
180970066....................  Indiana.................  Marion.................              38.3              39.6              35.7              36.9
180970081....................  Indiana.................  Marion.................              38.2              39.2              35.8              36.9
261470005....................  Michigan................  St Clair...............              39.6              40.6              36.2              37.1
261630015....................  Michigan................  Wayne..................              40.1              40.6              35.5              36.0
261630016....................  Michigan................  Wayne..................              42.9              45.4              38.9              41.2
261630019....................  Michigan................  Wayne..................              40.9              41.4              37.3              37.8
261630033....................  Michigan................  Wayne..................              43.8              44.2              39.4              39.8
390350038....................  Ohio....................  Cuyahoga...............              44.2              47.0              39.4              41.8
390350060....................  Ohio....................  Cuyahoga...............              42.1              45.7              37.7              40.8
420030064....................  Pennsylvania............  Allegheny..............              64.2              68.2              56.7              59.9
420030093....................  Pennsylvania............  Allegheny..............              45.6              51.5              39.1              44.3
420030116....................  Pennsylvania............  Allegheny..............              42.5              42.5              35.5              35.5
420070014....................  Pennsylvania............  Beaver.................              43.4              44.6              36.2              37.4
420710007....................  Pennsylvania............  Lancaster..............              40.8              44.0              35.9              38.3
540090011....................  West Virginia...........  Brooke.................              43.9              44.9              37.5              38.3
550790043....................  Wisconsin...............  Milwaukee..............              39.9              40.8              36.2              37.1
--------------------------------------------------------------------------------------------------------------------------------------------------------

      Table V.C-4--Average and Maximum 2003-2007 and 2012 Base Case 24-Hour PM2.5 Design Values ([micro]g/m\3\) at Projected Maintenance-Only Sites
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                         Final rule        Final rule
          Monitor ID                     State                    County           Average  design   Maximum  design   average design    maximum design
                                                                                   value 2003-2007   value 2003-2007     value 2012        value 2012
--------------------------------------------------------------------------------------------------------------------------------------------------------
010732003....................  Alabama.................  Jefferson..............              40.3              40.8              35.3              35.9
170310052....................  Illinois................  Cook...................              40.2              41.4              34.9              36.0
170312001....................  Illinois................  Cook...................              37.7              40.6              33.6              36.1
170313301....................  Illinois................  Cook...................              40.2              43.3              34.9              37.6
170316005....................  Illinois................  Cook...................              39.1              41.8              34.1              36.4
171190023....................  Illinois................  Madison................              37.3              38.1              35.1              35.8
180890022....................  Indiana.................  Lake...................              38.9              44.0              34.9              39.5
180890026....................  Indiana.................  Lake...................              38.4              41.3              34.0              37.0
261610008....................  Michigan................  Washtenaw..............              39.4              40.8              35.0              36.3
390170003....................  Ohio....................  Butler.................              39.2              41.1              34.4              36.5
390350045....................  Ohio....................  Cuyahoga...............              38.5              41.5              34.7              38.1
390350065....................  Ohio....................  Cuyahoga...............              38.6              41.0              34.9              37.6
390618001....................  Ohio....................  Hamilton...............              40.6              40.9              35.2              35.8
390811001....................  Ohio....................  Jefferson..............              41.9              45.5              34.5              37.8
391130032....................  Ohio....................  Montgomery.............              37.8              40.0              33.6              35.6
420031008....................  Pennsylvania............  Allegheny..............              41.3              42.8              35.0              36.3
420031301....................  Pennsylvania............  Allegheny..............              40.3              42.4              33.9              35.6
420033007....................  Pennsylvania............  Allegheny..............              37.5              43.1              32.3              37.3
421330008....................  Pennsylvania............  York...................              38.2              40.7              33.3              36.0
550790010....................  Wisconsin...............  Milwaukee..............              38.6              40.0              35.4              36.7
550790026....................  Wisconsin...............  Milwaukee..............              37.3              41.3              33.6              37.2
--------------------------------------------------------------------------------------------------------------------------------------------------------

(3) Methodology for Projecting Future 8-Hour Ozone Nonattainment and 
Maintenance
    The final rule methodology to calculate 8-hour ozone nonattainment 
and maintenance receptors is identical to the proposed rule. The May-
to-September 24-hour maximum 8-hour average concentrations from the 
2005 base case and the 2012 base case were used to project ambient 
design values to 2012. The following is a brief summary of the future 
year 8-hour average ozone calculations. Additional details are provided 
in the Air Quality Modeling Final Rule TSD.
    We are using the base period 2003-2007 ambient ozone design value 
data for projecting future year design values. Relative response 
factors (RRF) for each monitoring site were calculated as the

[[Page 48236]]

percent change in ozone on days with modeled ozone greater than 85 
ppb.\30\
---------------------------------------------------------------------------

    \30\ As specified in the attainment demonstration modeling 
guidance, if there are less than 10 modeled days > 85 ppb, then the 
threshold is lowered in 1 ppb increments (to as low as 70 ppb) until 
there are 10 days. If there are less than 5 days > 70 ppb, then an 
RRF calculation is not completed for that site.
---------------------------------------------------------------------------

    The maximum future design value is calculated by projecting design 
values for each of the three base periods (2003-2005, 2004-2006, and 
2005-2007) separately. The highest of the three future values is the 
maximum design value. This maximum value is used to identify the 8-hour 
ozone maintenance receptors.
    The future year design values are truncated to integers in units of 
ppb. This approach is consistent with the ambient data truncation and 
rounding procedures for the 8-hour ozone NAAQS. Future year design 
values that are greater than or equal to 85 ppb are considered to be 
violating the NAAQS. Sites with future year 5-year weighted average 
design values of 85 ppb or greater are predicted to be nonattainment. 
Sites with future year maximum design values of 85 ppb or greater are 
predicted to be future year maintenance sites. Note that, as described 
previously for the annual and 24-hour PM2.5 NAAQS, 
nonattainment sites for the ozone NAAQS are also maintenance sites 
because the maximum design value is always greater than or equal to the 
5-year weighted average. The monitoring sites that we project to be 
nonattainment and/or maintenance for the 8-hour ozone NAAQS in the 2012 
base case are the nonattainment/maintenance receptors used for 
assessing the contribution of emissions in upwind states to downwind 
nonattainment and maintenance of ozone NAAQS.
    Table V.C-5 contains the 2003-2007 base period average and maximum 
8-hour ozone design values and the 2012 base case average and maximum 
design values for sites projected to be 2012 nonattainment of the 8-
hour ozone NAAQS in 2012. Table V.C-6 contains this same information 
for projected 2012 8-hour ozone maintenance sites.

             Table V.C-5--Average and Maximum 2003-2007 and 2012 Base Case 8-Hour Ozone Design Values (ppb) at Projected Nonattainment Sites
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                         Final rule        Final rule
          Monitor ID                     State                    County           Average  design   Maximum  design   average design    maximum design
                                                                                   value 2003-2007   value 2003-2007     value 2012        value 2012
--------------------------------------------------------------------------------------------------------------------------------------------------------
220330003....................  Louisiana...............  East Baton Rouge.......              92.0                96              85.6              89.3
480391004....................  Texas...................  Brazoria...............              94.7                97              86.7              88.8
482010051....................  Texas...................  Harris.................              93.0                98              86.1              90.8
482010055....................  Texas...................  Harris.................             100.7               103              93.3              95.4
482010062....................  Texas...................  Harris.................              95.7                99              88.8              91.8
482010066....................  Texas...................  Harris.................              92.3                96              87.1              90.6
482011039....................  Texas...................  Harris.................              96.3               100              88.8              92.2
--------------------------------------------------------------------------------------------------------------------------------------------------------

           Table V.C-6--Average and Maximum 2003-2007 and 2012 Base Case 8-Hour Ozone Design Values (ppb) at Projected Maintenance-Only Sites
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                   Average  design   Maximum  design   Average design    Maximum design
          Monitor ID                     State                    County           value 2003-2007   value 2003-2007     value 2012        value 2012
--------------------------------------------------------------------------------------------------------------------------------------------------------
090011123....................  Connecticut.............  Fairfield..............              92.3                94              83.9              85.5
090093002....................  Connecticut.............  New Haven..............              90.3                93              82.7              85.1
240251001....................  Maryland................  Harford................              92.7                94              84.4              85.6
260050003....................  Michigan................  Allegan................              90.0                93              82.4              85.1
482010024....................  Texas...................  Harris.................              88.0                92              83.4              87.2
482010029....................  Texas...................  Harris.................              91.7                93              84.2              85.4
482011015....................  Texas...................  Harris.................              89.0                96              82.4              88.9
482011035....................  Texas...................  Harris.................              86.3                95              79.9              88.0
482011050....................  Texas...................  Harris.................              89.3                92              82.8              85.4
--------------------------------------------------------------------------------------------------------------------------------------------------------

D. Pollution Transport From Upwind States

1. Choice of Air Quality Thresholds
a. Thresholds
    In this action, EPA uses air quality thresholds to identify 
linkages between upwind states and downwind nonattainment and 
maintenance receptors. States whose contributions to a specific 
receptor meet or exceed the thresholds identified are considered linked 
to that receptor; those states' emissions (and available emission 
reductions) are analyzed further in the second step of EPA's 
significant contribution analysis. States whose contributions are below 
the thresholds are not included in the Transport Rule for that NAAQS. 
In other words, we are finding that states whose contributions are 
below these thresholds do not significantly contribute to nonattainment 
or interfere with maintenance of the relevant NAAQS.
    We use separate air quality thresholds for annual PM2.5, 
24-hour PM2.5, and 8-hour ozone. Each air quality threshold 
is calculated as 1 percent of the NAAQS. Specifically, we use an air 
quality threshold of 0.15 [mu]g/m\3\ for annual PM2.5, 0.35 
[mu]g/m\3\ for 24-hour PM2.5, and 0.8 ppb for 8-hour ozone. 
These are the same air quality thresholds we proposed.
    EPA received a number of comments on the thresholds we proposed, 
and those comments and EPA's responses are discussed below.
b. General Comments on the Overall Stringency and Use of 1 Percent of 
the NAAQS
    EPA received numerous comments supporting and opposing the proposed 
thresholds. A number of commenters cited support for EPA's approach. 
Some

[[Page 48237]]

commenters believed that use of a 1 percent threshold was too 
stringent, and recommended that EPA should use a threshold greater than 
1 percent. Others believed that 1 percent was not stringent enough, and 
they recommended using a lower value such as 0.5 percent. EPA believes 
that for both PM2.5 and for ozone, it is appropriate to use 
a threshold of 1 percent of the NAAQS for identifying states whose 
contributions do not significantly contribute to nonattainment or 
interfere with maintenance of the relevant NAAQS; therefore, EPA has 
retained the 1 percent threshold for the reasons described below.
    As we found at the time of CAIR, EPA's 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. (See section 
II of the January 2004 CAIR proposal, 69 FR 4575-87).
    In the 1998 NOX SIP Call (63 FR 57456, October 27, 1998) 
and in CAIR, EPA also found important contributions from multiple 
upwind states. As a result of the upwind ``collective contributions,'' 
EPA determined that it is appropriate to use a low air quality 
threshold when analyzing upwind states' contributions to downwind 
states' attainment and maintenance problems for ozone as well as 
PM2.5.
    Low threshold values are also warranted, as EPA discussed in the 
notices for CAIR, due to adverse health impacts associated with ambient 
PM2.5 and ozone even at low concentrations (See relevant 
portions of the CAIR proposal notice (63 FR 4583-84) and the CAIR final 
rule notice (70 FR 25189-25192)).
    To aid in responding to comments, EPA has compiled the contribution 
modeling results to analyze the impact of different possible 
thresholds. This analysis demonstrates the reasonableness of using the 
1 percent threshold to account for the combined impact of relatively 
small contributions from many upwind states (see Air Quality Modeling 
Final Rule TSD). In this analysis, EPA identifies for annual 
PM2.5 (sulfate and nitrate), 24-hour PM2.5 
(sulfate and nitrate), and 8-hour ozone receptors: (1) Total upwind 
state contributions, and (2) the amount of the total upwind state 
contribution that is captured at thresholds of 1 percent, 5 percent and 
0.5 percent of the NAAQS. EPA continues to find that the total 
``collective contribution'' from upwind sources represents a large 
portion of PM2.5 and ozone at downwind locations and that 
the total amount of transport is composed of the individual 
contribution from numerous upwind states.
    The analysis shows that the 1 percent threshold captures a high 
percentage of the total pollution transport affecting downwind states 
for both PM2.5 and ozone. In response to commenters who 
advocated a higher threshold, EPA observes that higher thresholds would 
exclude increasingly large percentages of total transport, which we do 
not believe would be appropriate. For example, a 5 percent threshold 
would exclude the majority--and for annual PM, more than 80 percent--of 
interstate pollution transport affecting the downwind state receptors 
analyzed (based on the average percentage of total interstate transport 
across all receptors captured at the 5 percent threshold).
    In response to commenters who advocated a lower threshold, EPA 
observes that the analysis shows that a lower threshold such as 0.5 
percent would result in relatively modest increases in the overall 
percentages of PM2.5 and ozone pollution transport captured 
relative to the amounts captured at the 1 percent level. A 0.5 percent 
threshold could lead to emission reduction responsibilities in 
additional states that individually have a very small impact on those 
receptors--an indicator that emission controls in those states are 
likely to have a smaller air quality impact at the downwind receptor. 
We are not convinced that selecting a threshold below 1 percent is 
necessary or desirable. A strong indication that the amount of 
pollution transport being excluded from consideration is not excessive 
is that the controls required under this rule are projected to 
eliminate nonattainment and maintenance problems with air quality 
standards at most downwind state receptors.
    Considering the combined downwind impact of multiple upwind states, 
the health effects of low levels of PM2.5 and ozone 
pollution, and EPA's previous use of a 1 percent threshold for 
PM2.5 in CAIR, EPA's judgment is that the 1 percent 
threshold is a reasonable choice.
    Some commenters noted that the PM2.5 thresholds used for 
this rule are less than the ``significant impact levels'' (SILs) used 
for permitting programs. As EPA stated at the time of CAIR, 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 (70 FR 25191; May 12, 2005).
c. Comments on the Rounding Conventions for PM2.5
    In the final Transport Rule, EPA is using two-digit values for the 
PM2.5 thresholds. Some commenters suggested that EPA should 
use the same rounding convention for annual PM2.5 used in 
CAIR; that is, the threshold should be 0.2 [mu]g/m\3\ rather than 0.15 
[mu]g/m\3\. The reasons for EPA's decision are below.
    The rationale for the single digit value for the final CAIR rule 
was that a single digit is consistent with the EPA monitoring data 
reporting requirements in Part 50, Appendix N, section 4.3. These 
reporting requirements specify that design values for the annual 
PM2.5 standard shall be rounded to the tenths place 
(decimals 0.05 and greater are rounded up to the next 0.1, and any 
decimal lower than 0.05 is rounded down to the nearest 0.1).
    Because the design value is to be reported only to the nearest 0.1 
[mu]g/m\3\, EPA deemed it preferable for the final CAIR to select the 
threshold value at the nearest 0.1 [mu]g/m\3\ as well, and hence one 
percent of the 15 [mu]g/m\3\, rounded to the nearest 0.1 [mu]g/m\3\ 
became 0.2 [mu]g/m\3\.
    The reporting requirements in section Part 50, Appendix N, section 
4.3 for the 24-hour PM2.5 standard state that design values 
for this standard shall be rounded to the nearest 1 [mu]g/m\3\ 
(decimals 0.5 and greater are rounded up to the nearest whole number, 
and any decimal lower than 0.5 is rounded down to the nearest whole 
number).
    If the approach used in CAIR were to be used to establish an air 
quality threshold for the 24-hour PM2.5 NAAQS (which CAIR 
did not address), the resulting threshold would be zero. One percent of 
the 24-hour standard is 0.35 [mu]g/m\3\, and rounding to the nearest 
whole number would yield an air quality threshold of zero. Thus if we 
were to apply the same rationale used to develop the annual 
PM2.5 threshold for the final CAIR, there would be no air 
quality threshold for 24-hour PM2.5, which EPA believes to 
be counter-intuitive and unworkable as an approach for assessing 
interstate contributions.
    Therefore, for this rule, EPA proposed and is now finalizing an 
approach that decouples the precision of the air quality thresholds 
from the monitoring reporting requirements, and uses 2-digit values 
representing one percent of the PM2.5 NAAQS; that is, 0.15 
[mu]g/m\3\ for the annual standard, and 0.35 [mu]g/m\3\ for the 24-hour 
standard. EPA believes there are a number of considerations favoring 
this approach. First, it provides for a consistent approach for the 
annual and 24-hour standards. Second, the

[[Page 48238]]

approach is readily applicable to any current and future NAAQS and 
would automatically adjust the stringency of the transport threshold to 
maintain a constant relationship with the stringency of the relevant 
NAAQS as they are revised. The CAIR approach would not allow for this 
continuity: For example, if EPA were to retain the CAIR approach for 
the annual standard, any future lowering of the PM2.5 NAAQS 
to below 15 [mu]g/m\3\ would reduce the air quality threshold to the 
same outcome: 0.1 [mu]g/m\3\. This would occur because any value less 
than 0.15 [mu]g/m\3\ would round to 0.1 [mu]g/m\3\ (assuming EPA would 
not round down to zero for the reasons described above), which means 
that the air quality threshold would have a different relative 
stringency to each possible future NAAQS value. For the above reasons, 
EPA believes the use of two-digit thresholds for both annual 
PM2.5 and 24-hour PM2.5 in the final rule is both 
reasonable and appropriate. The departure from the approach used for 
annual PM2.5 in CAIR is appropriate given the additional 
considerations that were not in existence at the time of the final 
CAIR, and the importance of using a consistent approach to developing 
air quality thresholds for all NAAQS addressed by this rule as well as 
future NAAQS considered in future transport-related actions.
    Some of these commenters suggested using the CAIR rounding 
conventions coupled with use of a 1-digit threshold of 0.4 [mu]g/m\3\ 
for 24-hour PM2.5. EPA considered the approach suggested by 
commenters, but determined that the proposed approach is more 
appropriate. First, adhering to the rounding conventions used for CAIR 
for annual PM2.5 is not workable for the 24-hour standard 
because the rounding convention would yield a threshold of zero. 
Rounding alternatively to 0.4 [mu]g/m\3\ would require EPA to find a 
basis for rounding the threshold to the nearest 0.1 [mu]g/m\3\ instead 
of using a strict application of 1 percent; we do not see any basis for 
such rounding at this time.
d. Comments Related to the Multi-Factor Test EPA Used for Ozone in CAIR
    Some commenters suggested that, for ozone, EPA should use the 
multiple-metric test we used for CAIR, and not a simple threshold based 
on 1 percent of the NAAQS. With respect to ozone, EPA proposed in the 
Transport Rule to take a more straightforward approach to air quality 
thresholds than the multi-factor approaches used for the NOX 
SIP Call and the CAIR. As proposed, EPA is using a contribution metric 
that is calculated based on the multi-day average contribution. This 
metric is compared to one percent of the 1997 8-hour ozone standard of 
0.08 ppm. Under this approach, one percent of the NAAQS is a value of 
0.8 ppb. Contributions of 0.8 ppb and higher are above the threshold; 
ozone contributions less than 0.8 ppb are below the threshold. In past 
rulemakings (e.g., CAIR) EPA used multiple ozone metrics, including the 
average contribution and maximum single day contribution to downwind 
nonattainment. EPA believes the average contribution (calculated over 
multiple high ozone days) is a robust metric compared to the maximum 
contribution on a single day. EPA believes that this approach is 
preferable because it uses a robust metric, it is consistent with the 
approach for PM2.5, and it provides for a consistent 
approach that takes into account, and is applicable to, any future 
ozone standards below 0.08 ppm.
    One of these commenters suggested that the 0.8 ppb threshold value 
was substantially more stringent than the 2 ppb screening test which 
was a part of the approach used for CAIR. The 1 percent threshold (0.8 
ppb) is not substantially more stringent than the previous 2 ppb test 
because of differences in the metrics used to evaluate contributions 
against these two levels. The 2 ppb test was evaluated using the 
highest single day absolute model-predicted downwind contribution from 
an upwind state. The 1 percent threshold is evaluated based on the 
average relative downwind impact calculated over multiple days. 
Therefore, it is appropriate to set a lower concentration threshold for 
use with the average contribution metric calculated for the Transport 
Rule. More details on the calculation of the contribution metric can be 
found in the Air Quality Modeling Final Rule TSD. As noted above, EPA 
believes that the approach used for the proposed rule provides for a 
simplified, yet robust approach compared to CAIR. Accordingly, for the 
final rule we have retained the approach used for the proposal.
    One commenter suggested that EPA retain the CAIR multiple-factor 
approach for ozone, and to apply that same approach to 24-hour 
PM2.5. As noted above, EPA is not retaining this approach 
for ozone, and for similar reasons we believe a multi-factor approach 
is not needed for 24-hour PM2.5. The approach based on 1 
percent of the NAAQS is consistent with the form of the 24-hour 
standard. In addition, this approach is based on contributions on days 
with high 24-hour PM2.5 predictions and therefore is 
relevant for characterizing transport during short-term high 
PM2.5 episodic conditions.
e. Comments on the Relationship to Measurement Precision
    Other commenters suggested that, as did commenters on the 
thresholds used in CAIR, EPA should take into consideration the 
measurement precision of existing PM2.5 monitors in setting 
the thresholds for the Transport Rule. EPA disagrees that monitoring 
precision is relevant to determining the amount of modeled 
PM2.5 or ozone that should be considered to be a 
``contribution'' from upwind states since states are not required to, 
nor would it be possible for them to, measure their individual state 
impacts on downwind receptors. The approach for eliminating significant 
contribution is based on the implementation of enforceable emissions 
budgets and not on a measurement of ambient air quality. Thus, EPA 
believes it is a reasonable exercise of its discretion to de-couple 
monitoring precision from the choice of contribution states.
f. Comments Related to the CAIR Court Decision
    Commenters recommended that EPA should have retained the criteria 
used for CAIR because those values were upheld by the Court. As noted 
above, EPA could not have used the approach for annual PM2.5 
that was used in CAIR to develop a 24-hour PM2.5 threshold, 
as that approach would have yielded a threshold value of zero 24-hour 
PM2.5.
    Further, nothing in the North Carolina opinion suggests that the 
thresholds and methods used in CAIR were the only possible approaches 
EPA could have used, that they were preferable to other approaches, or 
that other alternatives would not be acceptable. Instead, the Court 
upheld the 0.2 [micro]g/m\3\ threshold used for PM2.5 on the 
grounds that it was not ``wholly unsupported by the record'' (North 
Carolina, 531 F.3d at 915). EPA has determined for reasons explained in 
the record that the thresholds used in this final rule are both 
reasonable and appropriate for use in this final rule.
2. Approach for Identifying Contributing Upwind States
    This section documents the procedures used by EPA to quantify the 
contribution of emissions in specific upwind states to air quality 
concentrations in projected 2012 downwind nonattainment and maintenance 
locations for annual PM2.5, 24-hour PM2.5, and 8-
hour ozone. In the

[[Page 48239]]

proposed rule EPA used CAMx photochemical source apportionment modeling 
to quantify the impact of emissions in specific upwind states on 
projected downwind nonattainment and maintenance receptors for both 
PM2.5 and 8-hour ozone. In this modeling we tracked the 
ozone and PM2.5 formed from 2012 base case emissions from 
anthropogenic sources in each upwind state in the 12 km modeling 
domain. The CAMx Particulate Source Apportionment Technique (PSAT) was 
used to calculate downwind contributions to nonattainment and 
maintenance of PM2.5. In the PSAT simulation NOX 
emissions are tracked to particulate nitrate concentrations, 
SO2 emissions are tracked to particulate sulfate 
concentrations, and primary particulates (organic carbon, elemental 
carbon, and other PM2.5) are tracked as primary 
particulates. As described earlier in section V.A, the nitrate and 
sulfate contributions were combined and used to evaluate interstate 
contributions of PM2.5.
    The CAMx Ozone Source Apportionment Technique (OSAT) was used to 
calculate downwind 8-hour ozone contributions to nonattainment and 
maintenance. OSAT tracks the formation of ozone from NOX and 
VOC emissions.
    Comment: Three commenters stated that the CAMx source apportionment 
techniques used for the proposed rule reflect state-of-the science 
technologies and are appropriate for evaluating interstate transport. 
One commenter asked that EPA do more to demonstrate that the PSAT and 
OSAT techniques give reliable answers, although no suggestions were 
provided on how this might be done. Another commenter said that the 
results of the contribution analyses were consistent with the results 
of their scientific research.
    Response: EPA is not changing its conclusion that the CAMx source 
apportionment techniques are appropriate for quantifying interstate 
transport. The strength of the source apportionment technique is that 
all modeled ozone and/or PM2.5 mass at a given location in 
the modeling domain is tracked back to specific sources of emissions 
and boundary conditions to fully characterize culpable sources. No 
commenters provided technically valid analyses indicating that EPA's 
use of CAMx source apportionment techniques are inappropriate for the 
purposes of the Transport Rule.
    Comment: We received comments that certain states included in the 
proposed rule should be excluded from the final rule because EPA had 
overstated the 2012 emissions in these states. Commenter requested that 
we redo the contribution modeling using 2012 base case emission 
inventories that are revised based on proposed rule comments. Several 
commenters also asked that EPA update the contribution modeling 
analyses using the latest version of CAMx.
    Response: In response to these comments, we have rerun our source 
apportionment modeling for PM2.5 and ozone for the 2012 base 
case using the updated emission inventories described above in section 
V.C.1 and the latest version of CAMx, version 5.30.
    The states EPA analyzed for interstate contributions for ozone and 
for PM2.5 for the final rule are: Alabama, Arkansas, 
Connecticut, Delaware, Florida, Georgia, Illinois, Indiana, Iowa, 
Kansas, Kentucky, Louisiana, Maine, Maryland,\31\ 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.\32\ These are 
the same states that EPA analyzed for the proposed rule.
---------------------------------------------------------------------------

    \31\ As in the proposal, EPA has combined the contributions from 
Maryland and the District of Columbia as a single entity in our 
contribution analysis for the final rule. EPA believes that this is 
a fair representation of emissions for transport analysis because of 
the small size of the District of Columbia and its close proximity 
to Maryland. However, the District of Columbia is not included in 
the Transport Rule due to the significant contribution analysis 
findings in section VI.D.
    \32\ There were also several other states that are only 
partially contained within the 12 km modeling domain (i.e., 
Colorado, Montana, New Mexico, and Wyoming). However, EPA did not 
individually track the emissions or assess the contribution from 
emissions in these states.
---------------------------------------------------------------------------

    For the proposed rule, we used a relative approach for calculating 
the contributions to downwind nonattainment and maintenance receptors 
from the outputs of the source apportionment modeling. As part of this 
approach, the source apportionment predictions are combined with 
measurement-based concentrations to calculate the contributions from 
each state to nonattainment and/or maintenance receptors. This is 
similar to the approach used to calculate future year design values, as 
described in section V.C.2.
    Comment: One commenter said that using the source apportionment 
modeling predictions in a relative sense strengthens the determination 
of contributions and addresses an important source of uncertainty. 
There were no comments that suggested an alternative approach.
    Response: For the final Transport Rule we are applying the relative 
approach developed for the proposed rule to calculate contributions 
from each state to downwind nonattainment and maintenance receptors.
    As noted above, for the final rule we modeled the updated 2012 base 
case emissions using CAMX v5.30 to determine the 
contributions from emissions in upwind states to nonattainment and 
maintenance sites in downwind states. Contributions to nonattainment 
and maintenance receptors are evaluated independently for each state to 
determine if the contributions are at or above the threshold criteria.
    For each upwind state, the maximum contribution to nonattainment is 
calculated based on the single largest contribution to a future year 
(2012) downwind nonattainment receptor. The maximum contribution to 
maintenance is calculated based on the single largest contribution to a 
future year (2012) downwind maintenance receptor. Since the 
contributions are calculated independently for each receptor, the 
upwind contribution to maintenance can sometimes be larger than the 
contribution to nonattainment, and vice versa. This also means that 
maximum contributions to nonattainment can be below the threshold while 
maximum contributions to maintenance may be at or above the threshold, 
or vice versa.
V.D.2.a. Estimated Interstate Contributions to Annual PM2.5 
and 24-Hour PM2.5
    In this section, we present the interstate contributions from 
emissions in upwind states to downwind nonattainment and maintenance 
sites for the annual PM2.5 NAAQS and the 24-hour 
PM2.5 NAAQS based on modeling updated for the final rule. As 
described previously in section V.D.1, states which contribute 0.15 
[mu]g/m\3\ or more to annual PM2.5 nonattainment or 
maintenance in another state are identified as states with 
contributions large enough to warrant further analysis. For 24-hour 
PM2.5, states which contribute 0.35 [mu]g/m \3\ or more to 
24-hour PM2.5 nonattainment or maintenance in another state 
are identified as states with contributions to downwind nonattainment 
and maintenance sites large enough to warrant further analysis.
    For annual PM2.5, we calculated each state's 
contribution to each of the 12 monitoring sites that are projected to 
be nonattainment and each of the 4 sites that are projected to have 
maintenance problems for the annual PM2.5 NAAQS in the 2012 
base case. A detailed

[[Page 48240]]

description of the calculations can be found in the Air Quality 
Modeling Final Rule TSD. The largest contribution from each state to 
annual PM2.5 nonattainment in downwind sites is provided in 
Table V.D-1. The Largest Contribution from Each State to Annual 
PM2.5 maintenance in downwind sites is also provided in 
Table V.D-1. The contributions from each state to all projected 2012 
nonattainment and maintenance sites for the annual PM2.5 
NAAQS are provided in the Air Quality Modeling Final Rule TSD.

 Table V.D-1--Largest Contribution to Downwind Annual PM2.5 ([mu]g/m\3\)
           Nonattainment and Maintenance for Each of 37 States
------------------------------------------------------------------------
                                   Largest downwind    Largest downwind
                                    contribution to     contribution to
          Upwind state             nonattainment for    maintenance for
                                     annual PM2.5        annual PM2.5
                                     ([mu]g/m\3\)        ([mu]g/m\3\)
------------------------------------------------------------------------
Alabama.........................                0.51                0.19
Arkansas........................                0.10                0.04
Connecticut.....................                0.00                0.00
Delaware........................                0.00                0.00
Florida.........................                0.08                0.01
Georgia.........................                0.46                0.13
Illinois........................                0.50                0.65
Indiana.........................                1.34                1.27
Iowa............................                0.26                0.14
Kansas..........................                0.09                0.04
Kentucky........................                0.94                0.81
Louisiana.......................                0.09                0.03
Maine...........................                0.00                0.00
Maryland........................                0.15                0.06
Massachusetts...................                0.00                0.00
Michigan........................                0.64                0.64
Minnesota.......................                0.14                0.09
Mississippi.....................                0.05                0.01
Missouri........................                1.22                0.27
Nebraska........................                0.06                0.03
New Hampshire...................                0.00                0.00
New Jersey......................                0.02                0.01
New York........................                0.21                0.21
North Carolina..................                0.20                0.06
North Dakota....................                0.06                0.04
Ohio............................                1.34                0.94
Oklahoma........................                0.08                0.03
Pennsylvania....................                0.54                0.54
Rhode Island....................                0.00                0.00
South Carolina..................                0.24                0.04
South Dakota....................                0.03                0.01
Tennessee.......................                0.32                0.32
Texas...........................                0.18                0.07
Vermont.........................                0.00                0.00
Virginia........................                0.12                0.06
West Virginia...................                0.95                0.40
Wisconsin.......................                0.22                0.19
------------------------------------------------------------------------

    Based on the state-by-state contribution analysis, there are 18 
states \33\ which contribute 0.15 [mu]g/m\3\ or more to downwind annual 
PM2.5 nonattainment. These states are: Alabama, Georgia, 
Illinois, Indiana, Iowa, Kentucky, Maryland, Michigan, Missouri, New 
York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, 
Texas, West Virginia, and Wisconsin. In Table V.D-2, we provide a list 
of the downwind nonattainment sites to which each upwind state 
contributes 0.15 [mu]g/m\3\ or more (i.e., the upwind state to downwind 
nonattainment ``linkages'').
---------------------------------------------------------------------------

    \33\ As in the proposal, EPA has combined the contributions from 
Maryland and the District of Columbia as a single entity in our 
contribution analysis for the final rule. EPA believes that this is 
a fair representation of emissions for transport analysis because of 
the small size of the District of Columbia and its close proximity 
to Maryland. However, the District of Columbia is not included in 
the Transport Rule due to the significant contribution analysis 
findings in section VI.D.
---------------------------------------------------------------------------

    There are 12 states which contribute 0.15 [mu]g/m\3\ or more to 
downwind annual PM2.5 maintenance. These states are: 
Alabama, Illinois, Indiana, Kentucky, Michigan, Missouri, New York, 
Ohio, Pennsylvania, Tennessee, West Virginia, and Wisconsin. In Table 
V.D-3, we provide a list of the downwind maintenance sites to which 
each upwind state contributes 0.15 [mu]g/m\3\ or more (i.e., the upwind 
state to downwind maintenance ``linkages'').

[[Page 48241]]

             Table V.D-2--Upwind State to Downwind Nonattainment Site ``Linkages'' for Annual PM2.5
----------------------------------------------------------------------------------------------------------------
 
----------------------------------------------------------------------------------------------------------------
        Upwind state                                        Downwind receptor sites
----------------------------------------------------------------------------------------------------------------
Alabama.....................  Fulton, GA           Hamilton, OH         Hamilton, OH         Hamilton, OH
                               (131210039).         (390610014).         (390610042).         (390618001).
Georgia.....................  Jefferson, AL        Jefferson, AL
                               (10730023).          (10732003).
Illinois....................  Jefferson, AL        Fulton, GA           Wayne, MI            Cuyahoga, OH
                               (10732003).          (131210039).         (261630033).         (390350038).
                              Cuyahoga, OH         Cuyahoga, OH         Hamilton, OH         Hamilton, OH
                               (390350045).         (390350060).         (390610014).         (390610042).
                              Hamilton, OH         Allegheny, PA
                               (390618001).         (420030064).
Indiana.....................  Jefferson, AL        Jefferson, AL        Fulton, GA           Madison, IL
                               (10730023).          (10732003).          (131210039).         (171191007).
                              Wayne, MI            Cuyahoga, OH         Cuyahoga, OH         Cuyahoga, OH
                               (261630033).         (390350038).         (390350045).         (390350060).
                              Hamilton, OH         Hamilton, OH         Hamilton, OH         Allegheny, PA
                               (390610014).         (390610042).         (390618001).         (420030064).
Iowa........................  Madison, IL
                               (171191007).
Kentucky....................  Jefferson, AL        Jefferson, AL        Fulton, GA           Madison, IL
                               (10730023).          (10732003).          (131210039).         (171191007).
                              Wayne, MI            Cuyahoga, OH         Cuyahoga, OH         Cuyahoga, OH
                               (261630033).         (390350038).         (390350045).         (390350060).
                              Hamilton, OH         Hamilton, OH         Hamilton, OH         Allegheny, PA
                               (390610014).         (390610042).         (390618001).         (420030064).
Maryland....................  Allegheny, PA
                               (420030064).
Michigan....................  Madison, IL          Cuyahoga, OH         Cuyahoga, OH         Cuyahoga, OH
                               (171191007).         (390350038).         (390350045).         (390350060).
                              Hamilton, OH         Hamilton, OH         Hamilton, OH         Allegheny, PA
                               (390610014).         (390610042).         (390618001).         (420030064).
Missouri....................  Madison, IL          Cuyahoga, OH         Cuyahoga, OH         Cuyahoga, OH
                               (171191007).         (390350038).         (390350045).         (390350060).
                              Hamilton, OH         Hamilton, OH         Hamilton, OH
                               (390610014).         (390610042).         (390618001).
New York....................  Cuyahoga, OH         Cuyahoga, OH         Cuyahoga, OH         Allegheny, PA
                               (390350038).         (390350045).         (390350060).         (420030064).
North Carolina..............  Fulton, GA
                               (131210039).
Ohio........................  Jefferson, AL        Jefferson, AL        Fulton, GA           Madison, IL
                               (10730023).          (10732003).          (131210039).         (171191007).
                              Wayne, MI            Allegheny, PA
                               (261630033).         (420030064).
Pennsylvania................  Fulton, GA           Wayne, MI            Cuyahoga, OH         Cuyahoga, OH
                               (131210039).         (261630033).         (390350038).         (390350045).
                              Cuyahoga, OH         Hamilton, OH         Hamilton, OH         Hamilton, OH
                               (390350060).         (390610014).         (390610042).         (390618001).
South Carolina..............  Fulton, GA
                               (131210039).
Tennessee...................  Jefferson, AL        Jefferson, AL        Fulton, GA           Madison, IL
                               (10730023).          (10732003).          (131210039).         (171191007).
                              Hamilton, OH         Hamilton, OH         Hamilton, OH
                               (390610014).         (390610042).         (390618001).
Texas.......................  Madison, IL
                               (171191007).
West Virginia...............  Fulton, GA           Wayne, MI            Cuyahoga, OH         Cuyahoga, OH
                               (131210039).         (261630033).         (390350038).         (390350045).
                              Cuyahoga, OH         Hamilton, OH         Hamilton, OH         Hamilton, OH
                               (390350060).         (390610014).         (390610042).         (390618001).
                              Allegheny, PA
                               (420030064).
Wisconsin...................  Madison, IL          Wayne, MI            Cuyahoga, OH         Cuyahoga, OH
                               (171191007).         (261630033).         (390350038).         (390350045)
                              Cuyahoga, OH         Hamilton, OH         Hamilton, OH
                               (390350060).         (390610014).         (390618001).
----------------------------------------------------------------------------------------------------------------

              Table V.D-3--Upwind State to Downwind Maintenance Site ``Linkages'' for Annual PM2.5
----------------------------------------------------------------------------------------------------------------
 
----------------------------------------------------------------------------------------------------------------
        Upwind state                                        Downwind receptor sites
----------------------------------------------------------------------------------------------------------------
Alabama.....................  Marion, IN           Marion, IN           Hamilton, OH
                               (180970081).         (180970083).         (390617001).
Illinois....................  Marion, IN           Marion, IN           Cuyahoga, OH         Hamilton, OH
                               (180970081).         (180970083).         (390350065).         (390617001).
Indiana.....................  Cuyahoga, OH         Hamilton, OH
                               (390350065).         (390617001).
Kentucky....................  Marion, IN           Marion, IN           Cuyahoga, OH         Hamilton, OH
                               (180970081).         (180970083).         (390350065).         (390617001).
Michigan....................  Marion, IN           Marion, IN           Cuyahoga, OH         Hamilton, OH
                               (180970081).         (180970083).         (390350065).         (390617001).
Missouri....................  Marion, IN           Marion, IN           Cuyahoga, OH         Hamilton, OH
                               (180970081).         (180970083).         (390350065).         (390617001).
New York....................  Cuyahoga, OH
                               (390350065).
Ohio........................  Marion, IN           Marion, IN
                               (180970081).         (180970083).
Pennsylvania................  Marion, IN           Marion, IN           Cuyahoga, OH         Hamilton, OH
                               (180970081).         (180970083).         (390350065).         (390617001).
Tennessee...................  Marion, IN           Marion, IN           Hamilton, OH
                               (180970081).         (180970083).         (390617001).
West Virginia...............  Marion, IN           Marion, IN           Cuyahoga, OH         Hamilton, OH
                               (180970081).         (180970083).         (390350065).         (390617001).
Wisconsin...................  Marion, IN           Marion, IN           Cuyahoga, OH         Hamilton, OH
                               (180970081).         (180970083).         (390350065).         (390617001).
----------------------------------------------------------------------------------------------------------------

    For 24-hour PM2.5, we calculated each state's 
contribution to each of the 20 monitoring sites that are projected to 
be nonattainment and each of the 21 sites that are projected to have 
maintenance problems for the 24-hour PM2.5 NAAQS in the 2012 
base case. A detailed description of the calculations can be found in 
the Air Quality Modeling Final Rule TSD. The largest contribution from 
each state to 24-hour PM2.5 nonattainment in downwind sites 
is provided in Table V.D-4. The largest contribution from each state to 
24-hour PM2.5 maintenance in downwind sites is also provided 
in Table V.D-4. The contributions from each state to all projected 2012 
nonattainment and maintenance sites for the 24-hour PM2.5 
NAAQS are provided in the Air Quality Modeling Final Rule TSD.

 Table V.D-4--Largest Contribution to Downwind 24-Hour PM2.5 ([micro]g/
        m\3\) Nonattainment and Maintenance for Each of 37 States
------------------------------------------------------------------------
                                   Largest downwind    Largest downwind
                                    contribution to     contribution to
          Upwind state             nonattainment for  maintenance for 24-
                                     24-hour PM2.5    hour PM2.5  ([mu]g/
                                     ([mu]g/m\3\)            m\3\)
------------------------------------------------------------------------
Alabama.........................                0.51                0.42

[[Page 48242]]

 
Arkansas........................                0.24                0.23
Connecticut.....................                0.10                0.18
Delaware........................                0.22                0.20
Florida.........................                0.07                0.03
Georgia.........................                1.10                0.92
Illinois........................                3.72                5.70
Indiana.........................                3.56                5.15
Iowa............................                0.82                1.55
Kansas..........................                0.37                0.81
Kentucky........................                4.38                3.58
Louisiana.......................                0.11                0.13
Maine...........................                0.06                0.10
Maryland........................                2.83                2.11
Massachusetts...................                0.19                0.30
Michigan........................                1.86                2.03
Minnesota.......................                0.61                1.01
Mississippi.....................                0.06                0.07
Missouri........................                3.73                3.71
Nebraska........................                0.24                0.52
New Hampshire...................                0.05                0.10
New Jersey......................                0.68                0.75
New York........................                0.83                1.34
North Carolina..................                0.40                0.38
North Dakota....................                0.21                0.33
Ohio............................                5.85                4.74
Oklahoma........................                0.17                0.20
Pennsylvania....................                2.85                2.29
Rhode Island....................                0.02                0.03
South Carolina..................                0.29                0.25
South Dakota....................                0.10                0.17
Tennessee.......................                1.38                1.30
Texas...........................                0.37                0.33
Vermont.........................                0.03                0.05
Virginia........................                1.21                1.01
West Virginia...................                4.02                3.33
Wisconsin.......................                0.69                0.97
------------------------------------------------------------------------

    Based on the state-by-state contribution analysis, there are 21 
states \34\ which contribute 0.35 [mu]g/m\3\ or more to downwind 24-
hour PM2.5 nonattainment. These states are: Alabama, 
Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky, Maryland, Michigan, 
Minnesota, Missouri, New Jersey, New York, North Carolina, Ohio, 
Pennsylvania, Tennessee, Texas, Virginia, West Virginia, and Wisconsin. 
In Table V.D-5, we provide a list of the downwind nonattainment 
counties to which each upwind state contributes 0.35 [mu]g/m\3\ or more 
(i.e., the upwind state to downwind nonattainment ``linkages'').
---------------------------------------------------------------------------

    \34\ As in the proposal, EPA has combined the contributions from 
Maryland and the District of Columbia as a single entity in our 
contribution analysis for the final rule. EPA believes that this is 
a fair representation of emissions for transport analysis because of 
the small size of the District of Columbia and its close proximity 
to Maryland. However, the District of Columbia is not included in 
the Transport Rule due to the significant contribution analysis 
findings in section VI.D.
---------------------------------------------------------------------------

    There are 21 states which contribute 0.35 [mu]g/m\3\ or more to 
downwind 24-hour PM2.5 maintenance. These states are: 
Alabama, Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky, Maryland, 
Michigan, Minnesota, Missouri, Nebraska, New Jersey, New York, North 
Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and 
Wisconsin. In Table V.D-6, we provide a list of the downwind 
maintenance sites to which each upwind state contributes 0.35 [mu]g/
m\3\ or more (i.e., the upwind state to downwind maintenance 
``linkages'').

             Table V.D-5--Upwind State to Downwind Nonattainment Site ``Linkages'' for 24-Hour PM2.5
----------------------------------------------------------------------------------------------------------------
 
----------------------------------------------------------------------------------------------------------------
        Upwind state                                        Downwind receptor sites
----------------------------------------------------------------------------------------------------------------
Alabama.....................  Marion, IN           Marion, IN           Marion, IN
                               (180970043).         (180970066).         (180970081).
Georgia.....................  Jefferson, AL
                               (10730023).
Illinois....................  Marion, IN           Marion, IN           Marion, IN           St Clair, MI
                               (180970043).         (180970066).         (180970081).         (261470005).
                              Wayne, MI            Wayne, MI            Wayne, MI            Wayne, MI
                               (261630015).         (261630016).         (261630019).         (261630033).
                              Cuyahoga, OH         Cuyahoga, OH         Allegheny, PA        Allegheny, PA
                               (390350038).         (390350060).         (420030064).         (420030093).
                              Allegheny, PA        Beaver, PA           Brooke, WV           Milwaukee, WI
                               (420030116).         (420070014).         (540090011).         (550790043).

[[Page 48243]]

 
Indiana.....................  Jefferson, AL        Cook, IL             Madison, IL          St Clair, MI
                               (10730023).          (170311016).         (171191007).         (261470005).
                              Wayne, MI            Wayne, MI            Wayne, MI            Wayne, MI
                               (261630015).         (261630016).         (261630019).         (261630033).
                              Cuyahoga, OH         Cuyahoga, OH         Allegheny, PA        Allegheny, PA
                               (390350038).         (390350060).         (420030064).         (420030093).
                              Allegheny, PA        Beaver, PA           Brooke, WV           Milwaukee, WI
                               (420030116).         (420070014).         (540090011).         (550790043).
Iowa........................  Cook, IL             Madison, IL          Milwaukee, WI
                               (170311016).         (171191007).         (550790043).
Kansas......................  Madison, IL
                               (171191007).
Kentucky....................  Jefferson, AL        Cook, IL             Madison, IL          Marion, IN
                               (10730023).          (170311016).         (171191007).         (180970043).
                              Marion, IN           Marion, IN           St Clair, MI         Wayne, MI
                               (180970066).         (180970081).         (261470005).         (261630015).
                              Wayne, MI            Wayne, MI            Wayne, MI            Cuyahoga, OH
                               (261630016).         (261630019).         (261630033).         (390350038).
                              Cuyahoga, OH         Allegheny, PA        Allegheny, PA        Allegheny, PA
                               (390350060).         (420030064).         (420030093).         (420030116).
                              Beaver, PA           Brooke, WV           Milwaukee, WI
                               (420070014).         (540090011).         (550790043).
Maryland....................  Cuyahoga, OH         Lancaster, PA
                               (390350038).         (420710007).
Michigan....................  Cook, IL             Madison, IL          Cuyahoga, OH         Cuyahoga, OH
                               (170311016).         (171191007).         (390350038).         (390350060).
                              Allegheny, PA        Allegheny, PA        Beaver, PA           Brooke, WV
                               (420030064).         (420030093).         (420070014).         (540090011).
                              Milwaukee, WI
                               (550790043).
Minnesota...................  Milwaukee, WI
                               (550790043).
Missouri....................  Cook, IL             Madison, IL          Marion, IN           Marion, IN
                               (170311016).         (171191007).         (180970043).         (180970066).
                              Marion, IN           St Clair, MI         Wayne, MI            Allegheny, PA
                               (180970081).         (261470005).         (261630015).         (420030064).
                              Allegheny, PA        Beaver, PA           Milwaukee, WI
                               (420030116).         (420070014).         (550790043).
New Jersey..................  Lancaster, PA
                               (420710007).
New York....................  St Clair, MI         Wayne, MI            Wayne, MI            Wayne, MI
                               (261470005).         (261630016).         (261630019).         (261630033).
                              Cuyahoga, OH         Lancaster, PA
                               (390350060).         (420710007).
North Carolina..............  Lancaster, PA
                               (420710007).
Ohio........................  Jefferson, AL        Cook, IL             Madison, IL          Marion, IN
                               (10730023).          (170311016).         (171191007).         (180970043).
                              Marion, IN           Marion, IN           St Clair, MI         Wayne, MI
                               (180970066).         (180970081).         (261470005).         (261630015)
                              Wayne, MI            Wayne, MI            Wayne, MI            Allegheny, PA
                               (261630016).         (261630019).         (261630033).         (420030064).
                              Allegheny, PA        Allegheny, PA        Beaver, PA           Lancaster, PA
                               (420030093).         (420030116).         (420070014).         (420710007).
                              Brooke, WV           Milwaukee, WI
                               (540090011).         (550790043).
Pennsylvania................  Jefferson, AL        Cook, IL             Madison, IL          Marion, IN
                               (10730023).          (170311016).         (171191007).         (180970043).
                              Marion, IN           Marion, IN           St Clair, MI         Wayne, MI
                               (180970066).         (180970081).         (261470005).         (261630015).
                              Wayne, MI            Wayne, MI            Wayne, MI            Cuyahoga, OH
                               (261630016).         (261630019).         (261630033).         (390350038).
                              Cuyahoga, OH         Brooke, WV           Milwaukee, WI
                               (390350060).         (540090011).         (550790043)..
Tennessee...................  Jefferson, AL        Madison, IL          Marion, IN           Marion, IN
                               (10730023).          (171191007).         (180970043).         (180970066).
                              Marion, IN           St Clair, MI         Wayne, MI            Wayne, MI
                               (180970081).         (261470005).         (261630015).         (261630033).
                              Cuyahoga, OH         Allegheny, PA
                               (390350038).         (420030116).
Texas.......................  Madison, IL
                               (171191007).
Virginia....................  Lancaster, PA
                               (420710007).
West Virginia...............  Jefferson, AL        Cook, IL             Madison, IL          Marion, IN
                               (10730023).          (170311016).         (171191007).         (180970043).
                              Marion, IN           Marion, IN           St Clair, MI         Wayne, MI
                               (180970066).         (180970081).         (261470005).         (261630015).
                              Wayne, MI            Wayne, MI            Wayne, MI            Cuyahoga, OH
                               (261630016).         (261630019).         (261630033).         (390350038).
                              Cuyahoga, OH         Allegheny, PA        Allegheny, PA        Allegheny, PA
                               (390350060).         (420030064).         (420030093).         (420030116).
                              Beaver, PA           Lancaster, PA        Milwaukee, WI
                               (420070014).         (420710007).         (550790043).
Wisconsin...................  Cook, IL             Wayne, MI            Wayne, MI
                               (170311016).         (261630019).         (261630033).
----------------------------------------------------------------------------------------------------------------

              Table V.D-6--Upwind State to Downwind Maintenance Site ``Linkages'' for 24-Hour PM2.5
----------------------------------------------------------------------------------------------------------------
 
----------------------------------------------------------------------------------------------------------------
        Upwind state                                        Downwind receptor sites
----------------------------------------------------------------------------------------------------------------
Alabama.....................  Washtenaw, MI        Butler, OH           Montgomery, OH
                               (261610008).         (390170003).         (391130032).
Georgia.....................  Jefferson, AL
                               (10732003).
Illinois....................  Lake, IN             Lake, IN             Washtenaw, MI        Butler, OH
                               (180890022).         (180890026).         (261610008).         (390170003).
                              Cuyahoga, OH         Cuyahoga, OH         Hamilton, OH         Jefferson, OH
                               (390350045).         (390350065).         (390618001).         (390811001).
                              Montgomery, OH       Allegheny, PA        Allegheny, PA        Allegheny, PA
                               (391130032).         (420031008).         (420031301).         (420033007).
                              York, PA             Milwaukee, WI        Milwaukee, WI
                               (421330008).         (550790010).         (550790026).
Indiana.....................  Jefferson, AL        Cook, IL             Cook, IL             Cook, IL
                               (10732003).          (170310052).         (170312001).         (170313301).
                              Cook, IL             Madison, IL          Washtenaw, MI        Butler, OH
                               (170316005).         (171190023).         (261610008).         (390170003).
                              Cuyahoga, OH         Cuyahoga, OH         Hamilton, OH         Jefferson, OH
                               (390350045).         (390350065).         (390618001).         (390811001).
                              Montgomery, OH       Allegheny, PA        Allegheny, PA        Allegheny, PA
                               (391130032).         (420031008).         (420031301).         (420033007).
                              York, PA             Milwaukee, WI        Milwaukee, WI
                               (421330008).         (550790010).         (550790026).
Iowa........................  Cook, IL             Cook, IL             Cook, IL             Cook, IL
                               (170310052).         (170312001).         (170313301).         (170316005).
                              Madison, IL          Lake, IN             Lake, IN             Milwaukee, WI
                               (171190023).         (180890022).         (180890026).         (550790010).
                              Milwaukee, WI
                               (550790026).
Kansas......................  Cook, IL             Cook, IL             Milwaukee, WI        Milwaukee, WI
                               (170310052).         (170316005).         (550790010).         (550790026).
Kentucky....................  Jefferson, AL        Cook, IL             Cook, IL             Cook, IL
                               (10732003).          (170310052).         (170312001).         (170313301).
                              Cook, IL             Madison, IL          Lake, IN             Lake, IN
                               (170316005).         (171190023).         (180890022).         (180890026).
                              Washtenaw, MI        Butler, OH           Cuyahoga, OH         Cuyahoga, OH
                               (261610008).         (390170003).         (390350045).         (390350065).
                              Hamilton, OH         Jefferson, OH        Montgomery, OH       Allegheny, PA
                               (390618001).         (390811001).         (391130032).         (420031008).
                              Allegheny, PA        Allegheny, PA        York, PA             Milwaukee, WI
                               (420031301).         (420033007).         (421330008).         (550790010).
                              Milwaukee, WI
                               (550790026).

[[Page 48244]]

 
Maryland....................  York, PA
                               (421330008).
Michigan....................  Cook, IL             Cook, IL             Cook, IL             Cook, IL
                               (170310052).         (170312001).         (170313301).         (170316005).
                              Madison, IL          Lake, IN             Lake, IN             Butler, OH
                               (171190023).         (180890022).         (180890026).         (390170003).
                              Cuyahoga, OH         Cuyahoga, OH         Hamilton, OH         Jefferson, OH
                               (390350045).         (390350065).         (390618001).         (390811001).
                              Montgomery, OH       Allegheny, PA        Allegheny, PA        Allegheny, PA
                               (391130032).         (420031008).         (420031301).         (420033007).
                              York, PA             Milwaukee, WI        Milwaukee, WI
                               (421330008).         (550790010).         (550790026).
Minnesota...................  Milwaukee, WI        Milwaukee, WI
                               (550790010).         (550790026).
Missouri....................  Cook, IL             Cook, IL             Cook, IL             Cook, IL
                               (170310052).         (170312001).         (170313301).         (170316005).
                              Madison, IL          Lake, IN             Lake, IN             Washtenaw, MI
                               (171190023).         (180890022).         (180890026).         (261610008).
                              Butler, OH           Hamilton, OH         Montgomery, OH       Allegheny, PA
                               (390170003).         (390618001).         (391130032).         (420031008).
                              Milwaukee, WI        Milwaukee, WI
                               (550790010).         (550790026).
Nebraska....................  Milwaukee, WI        Milwaukee, WI
                               (550790010).         (550790026).
New Jersey..................  York, PA
                               (421330008).
New York....................  Washtenaw, MI        Cuyahoga, OH         Cuyahoga, OH         York, PA
                               (261610008).         (390350045).         (390350065).         (421330008).
North Carolina..............  York, PA
                               (421330008).
Ohio........................  Jefferson, AL        Cook, IL             Cook, IL             Cook, IL
                               (10732003).          (170310052).         (170312001).         (170313301).
                              Cook, IL             Madison, IL          Lake, IN             Lake, IN
                               (170316005).         (171190023).         (180890022).         (180890026).
                              Washtenaw, MI        Allegheny, PA        Allegheny, PA        Allegheny, PA
                               (261610008).         (420031008).         (420031301).         (420033007).
                              York, PA             Milwaukee, WI        Milwaukee, WI
                               (421330008).         (550790010).         (550790026).
Pennsylvania................  Jefferson, AL        Cook, IL             Cook, IL             Cook, IL
                               (10732003).          (170310052).         (170312001).         (170313301).
                              Madison, IL          Lake, IN             Lake, IN             Washtenaw, MI
                               (171190023).         (180890022).         (180890026).         (261610008).
                              Butler, OH           Cuyahoga, OH         Cuyahoga, OH         Hamilton, OH
                               (390170003).         (390350045).         (390350065).         (390618001).
                              Jefferson, OH        Montgomery, OH       Milwaukee, WI        Milwaukee, WI
                               (390811001).         (391130032).         (550790010).         (550790026).
Tennessee...................  Jefferson, AL        Madison, IL          Washtenaw, MI        Butler, OH
                               (10732003).          (171190023).         (261610008).         (390170003).
                              Cuyahoga, OH         Hamilton, OH         Montgomery, OH
                               (390350065).         (390618001).         (391130032).
Virginia....................  York, PA
                               (421330008).
West Virginia...............  Jefferson, AL        Cook, IL             Cook, IL             Cook, IL
                               (10732003).          (170310052).         (170312001).         (170313301).
                              Madison, IL          Lake, IN             Lake, IN             Washtenaw, MI
                               (171190023).         (180890022).         (180890026).         (261610008).
                              Butler, OH           Cuyahoga, OH         Cuyahoga, OH         Hamilton, OH
                               (390170003).         (390350045).         (390350065).         (390618001).
                              Jefferson, OH        Montgomery, OH       Allegheny, PA        Allegheny, PA
                               (390811001).         (391130032).         (420031008).         (420031301).
                              Allegheny, PA        York, PA             Milwaukee, WI
                               (420033007).         (421330008).         (550790010).
Wisconsin...................  Cook, IL             Cook, IL             Cook, IL             Cook, IL
                               (170310052).         (170312001).         (170313301).         (170316005).
                              Lake, IN             Lake, IN
                               (180890022).         (180890026).
----------------------------------------------------------------------------------------------------------------

b. Estimated Interstate Contributions to 8-Hour Ozone
    In this section, we present the interstate contributions from 
emissions in upwind states to downwind nonattainment and maintenance 
sites for the ozone NAAQS. As described previously in section V.D.1, 
states which contribute 0.8 ppb or more to 8-hour ozone nonattainment 
or maintenance in another state are identified as states with 
contributions to downwind attainment and maintenance sites large enough 
to warrant further analysis.
    We calculated each state's contribution to ozone at each of the 4 
monitoring sites that are projected to be nonattainment and each of 6 
\35\ sites that are projected to have maintenance problems for the 8-
hour ozone NAAQS in the 2012 base case. A detailed description of the 
calculations can be found in the Air Quality Modeling Final Rule TSD. 
The largest contribution from each state to 8-hour ozone nonattainment 
in downwind sites is provided in Table V.D-7. The largest contribution 
from each state to 8-hour ozone maintenance in downwind sites is also 
provided in Table V.D.2-7. The contributions from each state to all 
projected 2012 nonattainment and maintenance sites for the 8-hour ozone 
NAAQS are provided in the Air Quality Modeling Final Rule TSD.
---------------------------------------------------------------------------

    \35\ There are 6 additional sites with projected 2012 
nonattainment or maintenance (Harris Co., Texas sites 482010024, 
482010062, 482010066, 482011015, 482011035, and 482011039) for which 
there are less than 5 days with 8-hour ozone predictions of at least 
70 ppb. Thus, we did not calculate contributions for these 6 sites.

Table V.D-7--Largest Contribution to Downwind 8-Hour Ozone Nonattainment
                  and Maintenance for Each of 37 States
------------------------------------------------------------------------
                                   Largest downwind    Largest downwind
                                    contribution to     contribution to
          Upwind state             nonattainment for    maintenance for
                                     ozone  (ppb)        ozone  (ppb)
------------------------------------------------------------------------
Alabama.........................                 4.0                 2.8
Arkansas........................                 2.1                 2.0

[[Page 48245]]

 
Connecticut.....................                 0.0                 0.2
Delaware........................                 0.0                 0.6
Florida.........................                 0.5                 3.6
Georgia.........................                 1.6                 2.8
Illinois........................                 1.9                26.8
Indiana.........................                 1.3                 9.4
Iowa............................                 0.6                 0.9
Kansas..........................                 0.5                 1.0
Kentucky........................                 1.6                 1.6
Louisiana.......................                 8.0                11.1
Maine...........................                 0.0                 0.0
Maryland........................                 0.0                 2.7
Massachusetts...................                 0.0                 0.6
Michigan........................                 0.0                 0.9
Minnesota.......................                 0.3                 0.2
Mississippi.....................                 4.0                 3.3
Missouri........................                 1.1                 4.8
Nebraska........................                 0.2                 0.2
New Hampshire...................                 0.0                 0.1
New Jersey......................                 0.0                11.5
New York........................                 0.0                18.8
North Carolina..................                 0.5                 1.3
North Dakota....................                 0.2                 0.1
Ohio............................                 0.1                 3.2
Oklahoma........................                 0.3                 2.8
Pennsylvania....................                 0.1                 8.2
Rhode Island....................                 0.0                 0.0
South Carolina..................                 0.4                 0.9
South Dakota....................                 0.1                 0.1
Tennessee.......................                 2.2                 1.1
Texas...........................                 3.9                 1.9
Vermont.........................                 0.0                 0.0
Virginia........................                 0.2                 8.2
West Virginia...................                 0.0                 2.8
Wisconsin.......................                 0.2                 2.2
------------------------------------------------------------------------

    Based on the state-by-state contribution analysis, there are 11 
states that contribute 0.8 ppb or more to downwind 8-hour ozone 
nonattainment. These states are: Alabama, Arkansas, Georgia, Illinois, 
Indiana, Kentucky, Louisiana, Mississippi, Missouri, Tennessee, and 
Texas.\36\ In Table V.D-8, we provide a list of the downwind 
nonattainment counties to which each upwind state contributes 0.8 ppb 
or more (i.e., the upwind state to downwind nonattainment 
``linkages'').
---------------------------------------------------------------------------

    \36\ As discussed in section III, EPA is issuing a supplemental 
notice of proposed rulemaking to provide an opportunity for public 
comment on our conclusion that emissions from Iowa, Kansas, 
Michigan, Missouri, Oklahoma, and Wisconsin significantly contribute 
to nonattainment or interfere with maintenance of the 1997 ozone 
NAAQS in other states.
---------------------------------------------------------------------------

    There are 26 states \37\ which contribute 0.8 ppb or more to 
downwind 8-hour ozone maintenance. These states are: Alabama, Arkansas, 
Florida, Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky, Louisiana, 
Maryland, Michigan, Mississippi, Missouri, New Jersey, New York, North 
Carolina, Ohio, Oklahoma, Pennsylvania, South Carolina, Tennessee, 
Texas, Virginia, West Virginia, and Wisconsin.\38\ In Table V.D.2-9, we 
provide a list of the downwind nonattainment counties to which each 
upwind state contributes 0.8 ppb or more (i.e., the upwind state to 
downwind nonattainment ``linkages'').
---------------------------------------------------------------------------

    \37\ As in the proposal, EPA has combined the contributions from 
Maryland and the District of Columbia as a single entity in our 
contribution analysis for the final rule. EPA believes that this is 
a fair representation of emissions for transport analysis because of 
the small size of the District of Columbia and its close proximity 
to Maryland. However, the District of Columbia is not included in 
the Transport Rule due to the significant contribution analysis 
findings in section VI.D.
    \38\ As discussed in section III, EPA is issuing a supplemental 
notice of proposed rulemaking to provide an opportunity for public 
comment on our conclusion that emissions from Iowa, Kansas, 
Michigan, Missouri, Oklahoma, and Wisconsin significantly contribute 
to nonattainment or interfere with maintenance of the 1997 ozone 
NAAQS in other states.

[[Page 48246]]

                Table V.D-8--Upwind State to Downwind Nonattainment ``Linkages'' for 8-Hour Ozone
----------------------------------------------------------------------------------------------------------------
 
----------------------------------------------------------------------------------------------------------------
        Upwind state                                        Downwind receptor sites
----------------------------------------------------------------------------------------------------------------
Alabama.....................  East Baton Rouge,    Brazoria, TX         Harris, TX           Harris, TX
                               LA (220330003).      (480391004).         (482010051).         (482010055).
Arkansas....................  East Baton Rouge,    Brazoria, TX
                               LA (220330003).      (480391004).
Georgia.....................  East Baton Rouge,    Brazoria, TX         Harris, TX           Harris, TX
                               LA (220330003).      (480391004).         (482010051).         (482010055).
Illinois....................  Brazoria, TX         Harris, TX           Harris, TX
                               (480391004).         (482010051).         (482010055).
Indiana.....................  Brazoria, TX         Harris, TX           Harris, TX
                               (480391004).         (482010051).         (482010055).
Kentucky....................  Brazoria, TX         Harris, TX           Harris, TX
                               (480391004).         (482010051).         (482010055).
Louisiana...................  Brazoria, TX         Harris, TX           Harris, TX
                               (480391004).         (482010051).         (482010055).
Mississippi.................  East Baton Rouge,    Brazoria, TX         Harris, TX           Harris, TX
                               LA (220330003).      (480391004).         (482010051).         (482010055).
Missouri....................  Brazoria, TX         Harris, TX           Harris, TX
                               (480391004).         (482010051).         (482010055).
Tennessee...................  East Baton Rouge,    Brazoria, TX         Harris, TX           Harris, TX
                               LA (220330003).      (480391004).         (482010051).         (482010055).
Texas.......................  East Baton Rouge,
                               LA (220330003).
----------------------------------------------------------------------------------------------------------------

                 Table V.D-9--Upwind State to Downwind Maintenance ``Linkages'' for 8-Hour Ozone
----------------------------------------------------------------------------------------------------------------
 
----------------------------------------------------------------------------------------------------------------
        Upwind state                                        Downwind receptor sites
----------------------------------------------------------------------------------------------------------------
Alabama.....................  Harris, TX           Harris, TX
                               (482010029).         (482011050).
Arkansas....................  Allegan, MI
                               (260050003).
Florida.....................  Harris, TX           Harris, TX
                               (482010029).         (482011050).
Georgia.....................  Harris, TX           Harris, TX
                               (482010029).         (482011050).
Illinois....................  Fairfield, CT        Allegan, MI          Harris, TX
                               (90011123).          (260050003).         (482011050).
Indiana.....................  Fairfield, CT        New Haven, CT        Harford, MD          Allegan, MI
                               (90011123).          (90093002).          (240251001).         (260050003).
Iowa........................  Allegan, MI
                               (260050003).
Kansas......................  Allegan, MI
                               (260050003).
Kentucky....................  Fairfield, CT        New Haven, CT        Harford, MD          Harris, TX
                               (90011123).          (90093002).          (240251001).         (482011050).
Louisiana...................  Harris, TX           Harris, TX
                               (482010029).         (482011050).
Maryland....................  Fairfield, CT        New Haven, CT
                               (90011123).          (90093002).
Michigan....................  Harford, MD
                               (240251001).
Mississippi.................  Harris, TX           Harris, TX
                               (482010029).         (482011050).
Missouri....................  Allegan, MI
                               (260050003).
New Jersey..................  Fairfield, CT        New Haven, CT
                               (90011123).          (90093002).
New York....................  Fairfield, CT        New Haven, CT        Harford, MD
                               (90011123).          (90093002).          (240251001).
North Carolina..............  New Haven, CT        Harford, MD
                               (90093002).          (240251001).
Ohio........................  Fairfield, CT        New Haven, CT        Harford, MD
                               (90011123).          (90093002).          (240251001).
Oklahoma....................  Allegan, MI
                               (260050003).
Pennsylvania................  Fairfield, CT        New Haven, CT        Harford, MD
                               (90011123).          (90093002).          (240251001).
South Carolina..............  Harris, TX
                               (482010029).
Tennessee...................  Fairfield, CT        Harford, MD          Harris, TX
                               (90011123).          (240251001).         (482011050).
Texas.......................  Allegan, MI
                               (260050003).
Virginia....................  Fairfield, CT        New Haven, CT        Harford, MD
                               (90011123).          (90093002).          (240251001).
West Virginia...............  Fairfield, CT        New Haven, CT        Harford, MD
                               (90011123).          (90093002).          (240251001).
Wisconsin...................  Allegan, MI
                               (260050003).
----------------------------------------------------------------------------------------------------------------

VI. Quantification of State Emission Reductions Required

A. Cost and Air Quality Structure for Defining Reductions

1. Summary
    Section V, above, describes EPA's approach to identifying upwind 
states with air quality contributions that meet or exceed the air 
quality thresholds discussed therein for each of the NAAQS addressed in 
this rule. A state is covered by the Transport Rule if its 
contributions meet or exceed one of those air quality thresholds and 
the Agency identifies, using the cost- and air quality-based approach 
described below, emissions within the state that constitute the state's 
significant contribution to nonattainment and interference with 
maintenance with respect to the 1997 ozone, 1997 PM2.5 or 
2006 PM2.5 NAAQS.
    In this section, EPA explains its final cost- and air quality-based 
approach to quantify the amount of emissions that represent significant 
contribution to nonattainment and interference with maintenance for 
each state. EPA then applies that approach for the three different 
NAAQS being addressed in this rule: The 1997 ozone NAAQS, the 1997 
annual PM2.5 NAAQS and the 2006 24-hour PM2.5 
NAAQS. EPA believes that the methodology finalized could also be used 
to address transport concerns under other NAAQS, including future 
revisions to the ozone and PM2.5 NAAQS.
    EPA applies the methodology described herein to fully quantify the 
emissions that constitute each covered state's significant contribution 
to nonattainment and interference with maintenance with respect to the 
1997 annual PM2.5 and the 2006 24-hour PM2.5 
NAAQS. The FIPs with respect to the annual and 24-hour PM2.5 
NAAQS that are finalized in this action ensure that all such emissions 
are prohibited. Each such FIP thus fully satisfies the requirements of 
110(a)(2)(D)(i)(I) with

[[Page 48247]]

respect to the annual and/or 24-hour PM2.5 NAAQS for the 
covered state.
    EPA also applies the methodology to quantify significant 
contribution to nonattainment and interference with maintenance with 
respect to the 1997 ozone NAAQS. However, we have not been able to 
fully quantify such emissions for all covered states. In this action, 
EPA fully quantifies the significant contribution to nonattainment and 
interference with maintenance for 15 states. We finalize FIPs with 
respect to the 1997 ozone standards for 10 of these 15 states (Florida, 
Maryland, New Jersey, New York, North Carolina, Ohio, Pennsylvania, 
South Carolina, Virginia, and West Virginia). We are also publishing a 
supplemental notice of rulemaking to take comment on whether FIPs 
should be finalized for the remaining 5 states (Iowa, Kansas, Michigan, 
Oklahoma, and Wisconsin). The FIPs for these 10 states (and the FIPs 
for the remaining 5 states, if finalized) fully satisfy the 
requirements of 110(a)(2)(D)(i)(I) with respect to the 1997 ozone NAAQS 
for the covered state.
    In addition, we apply the methodology described herein to quantify, 
for 11 additional states, ozone-season NOX emission 
reductions that are necessary but may not be sufficient to eliminate 
all significant contribution to nonattainment and interference with 
maintenance in other states. We finalize FIPs with respect to the 1997 
ozone standards for 10 of these 11 states (Alabama, Arkansas, Georgia, 
Illinois, Indiana, Kentucky, Louisiana, Mississippi, Tennessee, and 
Texas). We are also publishing a supplemental notice of rulemaking to 
take comment on whether FIPs should be finalized for the remaining 
state (Missouri). The FIPs for these 10 states (and the FIP for the 
remaining state, if finalized) make measurable progress toward 
satisfying the requirements of 110(a)(2)(D)(i)(I) with respect to the 
1997 ozone NAAQS in each covered state. To the extent that significant 
contribution to nonattainment and interference with maintenance is not 
entirely eliminated for the 1997 ozone NAAQS through today's action, 
EPA will address these instances in a future rulemaking. This is 
further explained in section VI.D.
    With respect to the 1997 annual PM2.5 NAAQS, this rule 
finds that 18 states have SO2 and NOX emission 
reduction responsibilities. EPA also finds that 21 states have 
SO2 and NOX emission reduction responsibilities 
with respect to the 2006 24-hour PM2.5 NAAQS. There are a 
total of 23 states that have SO2 and NOX emission 
reduction responsibilities for one or both of the above 
PM2.5 NAAQS. We apply the methodology to quantify emission 
reductions that these states must achieve to eliminate the state's 
significant contribution to nonattainment and interference with 
maintenance. The states are listed in Table III-1 in section III of 
this preamble.
    This rule will prohibit all significant contribution to 
nonattainment and interference with maintenance with respect to the 
annual and 24-hour PM2.5. In addition, it will resolve air 
quality issues at most nonattainment and maintenance receptors 
identified by EPA. EPA projects that unresolved nonattainment and 
maintenance issues will remain in only a few downwind states after 
promulgation and implementation of the Transport Rule. For the annual 
PM2.5 standard, EPA projects that this rule will help assure 
that all areas in the east fully resolve their nonattainment and 
maintenance concerns. This rule will also help a number of areas 
achieve the standard earlier than they may have otherwise. For the 2006 
24-hour PM2.5 NAAQS, one area is projected to remain in 
nonattainment (Liberty-Clairton) and three areas are projected to have 
remaining maintenance concerns after imposition of the Transport Rule 
(Chicago,\39\ Detroit, and Lancaster County).\40\
---------------------------------------------------------------------------

    \39\ This area is not currently designated as nonattainment for 
the 24-hour PM2.5 standard. EPA is portraying the 
receptors and counties in this area as a single 24-hour maintenance 
area based on the annual PM2.5 nonattainment designation 
of Chicago-Gary-Lake County, IL-IN.
    \40\ In the Transport Rule proposal, EPA noted that the Liberty-
Clairton receptor in Allegheny county was significantly impacted by 
local emissions from a sizeable coke production facility and other 
nearby sources (75 FR 45281).
---------------------------------------------------------------------------

    The methodology provides similar assistance for ozone, assuring 
upwind reductions that will assist downwind states in controlling ozone 
pollution. It reduces ozone concentration levels in 2012 and helps 
assure that all but two downwind areas fully resolve their 
nonattainment and maintenance problems with the 1997 ozone NAAQS by 
2014. While Houston is projected to still face nonattainment and Baton 
Rouge is projected to still face maintenance concerns with the 1997 
ozone NAAQS, the Transport Rule improves air quality in these two areas 
and provides both health benefits and assistance for these local areas 
in meeting the NAAQS requirements. For reasons explained below, EPA 
will conduct further analysis in a subsequent transport-related 
rulemaking to determine whether further upwind state reductions are 
warranted to assist attainment and maintenance of the ozone NAAQS in 
Houston and Baton Rouge areas.
    When EPA proposed this air-quality and cost-based multi-factor 
approach to identify emissions that constitute significant contribution 
to nonattainment and interference with maintenance from upwind states 
with respect to the 1997 ozone, annual PM2.5, and 2006 24-
hour PM2.5 NAAQS, the Agency indicated that the approach was 
designed to be applicable to both current and potential future ozone 
and PM2.5 NAAQS (75 FR 45214). EPA believes that the final 
Transport Rule demonstrates the value of this approach for addressing 
the role of interstate transport of air pollution in communities' 
ability to comply with current and future NAAQS. EPA believes that the 
Transport Rule's approach of using air-quality thresholds to determine 
upwind-to-downwind-state linkages and using the cost- and air quality-
based multi-factor approach to quantify significant contribution to 
nonattainment and interference with maintenance (i.e., to determine the 
specific amount of emissions that each upwind state must reduce) could 
serve as a precedent for quantifying upwind state emission reduction 
responsibilities with respect to potential future NAAQS.
    One commenter suggested that the rule could set a flawed precedent 
for future transport analyses and remedies, as it does not fully 
eliminate the prohibited emissions in every upwind state. EPA disagrees 
with this characterization of the Transport Rule. EPA notes that the 
partial determination of significant contribution to nonattainment and 
interference with maintenance for certain upwind states in the 
Transport Rule with respect to the ozone NAAQS is not a function of the 
multi-factor approach itself, but is instead a function of its limited 
application in this rulemaking to identify emission reductions from a 
single source category (EGUs). In fact, the Transport Rule's approach 
itself allowed EPA to determine for which upwind states we have 
identified all emissions that constitute significant contribution to 
nonattainment and interference with maintenance, and for which upwind 
states we have identified emissions that are necessary but may not be 
sufficient to eliminate the prohibited emissions. As EPA explained at 
proposal, developing the additional information needed to consider 
NOX emissions from non-EGU source categories in order to 
fully quantify upwind state responsibility with respect to the 1997 
ozone NAAQS would

[[Page 48248]]

substantially delay promulgation of the Transport Rule. EPA explained 
that we do not believe that effort should delay the emission reductions 
and large health benefits this final rule will deliver (75 FR 45213). 
EPA further explained that we believe it is likely that the Agency can 
provide the greatest assistance to states in addressing transported 
pollution by issuing a separate (subsequent) rule to address additional 
reductions that may be necessary to fully eliminate upwind state 
responsibility with respect to the 1997 ozone NAAQS (75 FR 45288). 
Thus, EPA decided to promulgate the Transport Rule as quickly as 
possible. EPA anticipates that application of this air-quality and 
cost-based multi-factor approach to a broader set of source categories 
in a subsequent rulemaking will identify any remaining prohibited 
emissions in the upwind states for which the Transport Rule may not 
fully eliminate those emissions with respect to the 1997 ozone NAAQS.
2. Background
    After using air quality analysis to identify upwind states that are 
``linked'' to downwind air quality monitoring sites with nonattainment 
and maintenance problems through contribution of at least one percent 
of the relevant NAAQS, EPA quantifies the portion of each state's 
contribution that constitutes its ``significant contribution'' or 
``interference with maintenance.''
    This section describes the methodology developed by EPA for this 
analysis and then explains how that methodology is applied to measure 
significant contribution to nonattainment and interference with 
maintenance with respect to the NAAQS of concern. For this portion of 
the analysis, EPA expands upon the methodology used in the 
NOX SIP Call and CAIR but modifies it in important respects. 
In the NOX SIP Call and CAIR, EPA's methodology defined 
significant contribution as those emissions that could be removed with 
the use of ``highly cost effective'' controls. In the Transport Rule, 
rather than relying solely on an analysis of what constitutes ``highly 
cost effective'' controls, EPA relies on an analysis that accounts for 
both cost and air quality improvement to identify the portion of a 
state's contribution that constitutes its significant contribution to 
nonattainment and interference with maintenance. Furthermore, in 
response to the Court's opinion in North Carolina, EPA has developed an 
approach which gives independent meaning to the ``interfere with 
maintenance'' prong of section 110(a)(2)(D)(i)(I).
    The methodology takes into account both the D.C. Circuit Court's 
determination that EPA may consider cost when measuring significant 
contribution, Michigan, 213 F.3d at 679, and its rejection of the 
manner in which cost was used in the CAIR analysis, North Carolina, 531 
F.3d at 917. It also recognizes that the Court accepted--but did not 
require--EPA's use of a single, uniform cost threshold to measure 
significant contribution. Michigan, 213 F.3d at 679.
    As EPA discussed at length in the Transport Rule proposal, using 
both air quality and cost factors allows EPA to consider the full range 
of circumstances and state-specific factors that affect the 
relationship between upwind emissions and downwind nonattainment and 
maintenance problems (75 FR 45271). For example, considering cost takes 
into account the extent to which existing plants are already controlled 
as well as the potential for, and relative difficulty of, additional 
emission reductions. Therefore, EPA believes that it is appropriate to 
consider both cost and air quality metrics when quantifying each 
state's significant contribution.
    This methodology is consistent with the statutory mandate in 
section 110(a)(2)(D)(i)(I) which requires upwind states to prohibit 
emissions that significantly contribute to nonattainment or 
interference with maintenance in another state. As discussed in more 
detail in the proposal, interpreting significant contribution to 
nonattainment and interference with maintenance inherently involves a 
decision on how much emissions control responsibility should be 
assigned to upwind states, and how much responsibility should be left 
to downwind states. EPA's methodology is intended to ``assign a 
substantial but reasonable amount of responsibility to upwind states. * 
* *to control their emissions'' (75 FR 45272). EPA believes that upwind 
states contributing to downwind state air quality degradation should 
bear substantial responsibility to control their emissions because of 
the plain language of the good neighbor provision, the health risks and 
control cost impacts that upwind emissions cause in the downwind state, 
and the cumulative impact in the downwind state of emissions from 
multiple upwind states, and the importance of achieving attainment in 
downwind states as expeditiously as practicable but no later than 
specific deadlines as required by the Act. EPA's approach does not 
shift the responsibility for achieving or maintaining the NAAQS to the 
upwind state. See 75 FR 45272.
    The methodology defines each state's significant contribution to 
nonattainment and interference with maintenance as the emission 
reductions available at a particular cost threshold in a specific 
upwind state which effectively address nonattainment and maintenance of 
the relevant NAAQS in the linked downwind states of concern. Unlike the 
NOX SIP Call and CAIR, where EPA's significant contribution 
analysis had a regional focus, the methodology used in the Transport 
Rule focuses on state-specific factors. The methodology uses a multi-
step process to analyze costs and air quality impacts, identify 
appropriate cost thresholds, quantify reductions available from EGUs in 
each state at those thresholds, and consider the impact of variability 
in EGU operations. There are four steps to this methodology: (1) 
Identification of each state's emission reductions available at 
ascending costs per ton as appropriate; (2) assessment of those upwind 
emission reductions' downwind air quality impacts; (3) identification 
of upwind ``cost thresholds'' delivering effective emission reductions 
and downwind air quality improvement; and (4) enshrinement of the 
upwind emission reductions available at those cost thresholds in state 
budgets.
    In step one, EPA identifies what emission reductions are available 
at various cost thresholds, quantifying emission reductions that would 
occur within each state at ascending costs per ton of emission 
reductions. In other words, EPA determined for specific cost per ton 
thresholds, the emission reductions that would be achieved in a state 
if all EGUs greater than 25 MW in that state used all emission controls 
and emission reduction measures available at that cost threshold. For 
purposes of this discussion, we refer to these as ``cost curves.''
    For this final rule, EPA used updated IPM modeling to conduct a 
similar cost curve analysis as conducted in the Transport Rule proposal 
(75 FR 45275). In the proposal, the cost curves only reflected 
escalating cost for one pollutant while the other pollutant cost was 
held constant at base case levels (i.e., $0/ton). However, EPA improved 
the costing analysis for the final rule by identifying upwind emission 
reductions available as costs were imposed on both SO2 and 
NOX simultaneously for states linked to downwind states on 
the basis of the PM2.5 NAAQS. In other words, the cost 
curves in the proposal depicted state level emissions when only one 
pollutant was priced (i.e., NOX at $500/

[[Page 48249]]

ton). Separate cost curves were done for each pollutant. For the final 
rule, EPA conducted some preliminary cost curve analysis for 
identifying NOX thresholds in this manner. However, for the 
final cost curve analysis, EPA relied on cost curves that reflected 
state emissions when pollutants were priced simultaneously (e.g., 
NOX at $500/ton and SO2 at $1,600/ton). For 
reasons described in section VI.B, EPA was able to conduct this type of 
analysis because the preliminary cost curves specific to annual and 
ozone-season NOX suggested little flexibility in adjusting 
the $500/ton cost thresholds imposed for each. Therefore, EPA was able 
to hold the cost threshold constant at $500/ton for these pollutants in 
its examination of SO2 at various cost thresholds. EPA 
believes this approach to cost analysis is a better simulation of the 
Transport Rule's likely impact on covered sources. Under the final 
Transport Rule, covered sources in states regulated for 
PM2.5 must address compliance requirements for 
SO2 and NOX emissions simultaneously, and this 
refined approach to cost curve analysis and subsequent air quality 
analysis better reflects this reality. Section VI.B of this preamble 
describes the costing analysis in further detail. Also, for more detail 
on the development of the cost curves, see ``Significant Contribution 
and State Emission Budgets Final Rule TSD'' in the docket for this 
rule.
    Although the cost curves presented in this rule only include EGU 
reductions, EPA also assessed the cost of SO2 and 
NOX emission reductions available for source categories 
other than EGUs in the proposed rulemaking. This preliminary assessment 
in the rule proposal suggested that there likely would be very large 
emission reductions available from EGUs before costs reach the point 
for which non-EGU sources have available reductions (75 FR 45272). EPA 
revisited these non-EGU reduction cost levels in this final rulemaking 
and verified that there are little or no reductions available from non-
EGUs at costs lower than the thresholds that EPA has chosen ($500/ton 
for NOX, $2,300/ton for SO2).
    Further details on EPA's application of cost curves are provided 
below, in section VI.B.
    In step two, EPA uses an air quality assessment tool to estimate 
the impact that the combined reductions available from upwind 
contributing states and the downwind receptor state at different cost-
per-ton levels would have on air quality at downwind monitoring sites 
projected to have nonattainment and/or maintenance problems.\41\ While 
less rigorous than the air quality models used for attainment 
demonstrations, EPA believes this air quality assessment tool (which 
has been refined since proposal) is acceptable for assessing the impact 
of numerous options for upwind emission reductions in the process of 
defining an upwind state's significant contribution to nonattainment 
and interference with maintenance. It allows the Agency to anticipate 
specific air quality impacts of many more potential emission reduction 
scenarios pertinent to the relevant NAAQS than time- and resource-
intensive comprehensive air quality modeling would permit.
---------------------------------------------------------------------------

    \41\ As is discussed in the RIA, EPA also used the CAMx model to 
perform air quality analysis of its proposed remedy to address 
significant contribution. Results from this modeling will not 
exactly correspond to results from the air quality assessment tool 
both because the inputs to the air quality modeling are different 
and the sophisticated model more fully accounts for the complex air 
chemistry interactions. The full air quality modeling looks at the 
remedy, including reductions in upwind states that do not contribute 
as well as the impacts of the variability provisions discussed later 
in this section. It also provides a metric against which to evaluate 
the air quality assessment tool.
---------------------------------------------------------------------------

    Further details on EPA's application of step two in this 
methodology are provided below, in section VI.C.
    In step three, EPA examines cost and air quality information to 
identify ``significant cost thresholds.'' EPA considered a significant 
cost threshold to be a point along the cost curves where a noticeable 
change occurred in downwind air quality, such as a point where large 
upwind emission reductions become available because a certain type of 
emissions control strategy becomes cost-effective.\42\
---------------------------------------------------------------------------

    \42\ The cost thresholds identified in this rule are specific to 
the section 110(a)(2)(D)(i)(I) requirements for the states and NAAQS 
considered in this proposal. They do not represent an agency 
position on the appropriateness of such cost thresholds for any 
other application under the Act.
---------------------------------------------------------------------------

    This methodology allows EPA, where appropriate, to define multiple 
cost thresholds that vary for a particular pollutant for different 
upwind states. As explained in the Transport Rule proposal, EPA does 
not believe it is required to utilize multiple cost thresholds to 
regulate upwind emissions for purposes of the mandate in CAA section 
110(a)(2)(D), but EPA's multi-factor methodology developed for the 
Transport Rule to define significant contribution to nonattainment and 
interference with maintenance allows the Agency to consider whether a 
single cost threshold or multiple cost thresholds are appropriate for 
meeting the requirements of CAA section 110(a)(2)(D) relevant to a 
particular NAAQS (75 FR 45274).
    In step four, EPA uses the information regarding emission 
reductions available in each ``linked'' upwind state at the appropriate 
cost threshold to form a state ``budget,'' representing the remaining 
emissions from covered sources for the state in an average year once 
significant contribution to nonattainment and interference with 
maintenance have been eliminated; each budget also allows for the 
identification of an associated variability limit. These budgets and 
variability limits are used to develop enforceable requirements under 
the final remedy. The final rule's methodology for identifying state 
budgets is derived directly from the cost curves and multi-factor 
analysis EPA uses to determine each state's significant contribution to 
nonattainment and interference with maintenance. State emission budgets 
are discussed in section VI.D and the variability limits are discussed 
in section VI.E.

B. Cost of Available Emission Reductions (Step 1)

    This subsection provides more detail on the cost curves that EPA 
developed to assess the costs of reducing SO2 and 
NOX emissions to address transport related to ozone and 
PM2.5 concentrations (described previously as Step 1). It 
summarizes the information from the curves and then provides EPA's 
interpretation of that information. EPA used IPM to develop the EGU 
cost curves described in this rulemaking. More information can be found 
regarding EPA's use of IPM for the final Transport Rule in the 
``Significant Contribution and State Emission Budgets Final Rule TSD''.
    The amount of emission reductions that the cost curves suggest are 
available at various costs are specific to the 2012 and 2014 time 
periods. These cost estimates factor in the time interval between rule 
finalization and compliance periods, existing controls already in 
place, and controls that could potentially come on line by the start of 
the compliance period. EPA notes that cost curves are a fluid concept 
and would vary given different compliance dates.
1. Development of Annual NOX and Ozone-Season NOX 
Cost Curves
    EPA conducted preliminary cost curve analysis for annual 
NOX and ozone-season NOX in a similar manner to 
that used in the proposed rulemaking. That is, the impact of various 
cost thresholds on emissions was examined individually. For example, 
state level emissions were examined at cost levels for annual 
NOX of $500, $1,000, and

[[Page 48250]]

$2,500/ton while SO2 was held at base case levels. EPA used 
this approach to examine NOX and ozone-season NOX 
emission reductions available from EGUs by 2012 and 2014 at various 
cost levels, reaching to $2,500/ton for annual NOX and up to 
$5,000/ton for ozone-season NOX (in 2007-year dollars). 
Section VI.D explains why EPA analyzed the $500/ton threshold for 
annual and ozone-season NOX. EPA selected two higher cost 
thresholds to analyze for annual and ozone-season NOX that 
provided a reasonable spectrum of emission reduction opportunities from 
EGUs at higher cost thresholds. Specifically, EPA analyzed these two 
higher cost thresholds because the first ($1,000/ton) was informative 
in regards to the additional EGU NOX emissions reductions 
available without installation of advanced controls, and the second 
($2,500/ton for annual NOX, $5,000/ton for ozone-season 
NOX) was informative in regards to additional EGU reductions 
available at cost thresholds where advanced NOX control 
retrofits are economic for some units. The cost thresholds were only 
applied to states with air quality contributions that meet or exceed 
the air quality thresholds as identified in section V.D. For both 
annual and ozone-season NOX, EPA did not consider cost 
thresholds below $500/ton for reasons explained in section VI.D.
    EPA observed in the proposal that low-cost NOX 
reductions are available at upwind sources with existing pollution 
control equipment that may not otherwise be operated in the future 
without the Transport Rule. EPA believes it is appropriate to prohibit 
any ``linked'' upwind state from potentially increasing its emissions 
through a failure to operate these existing pollution controls, which 
could worsen downwind air quality problems. Thus, EPA reflected 
operation of these controls in all modeling of different cost 
thresholds (i.e., the modeling assumes year-round operation of post-
combustion NOX controls in covered PM2.5 states 
and ozone-season operation of post-combustion NOX controls 
in covered ozone states).
    Table VI.B-1 shows the annual NOX emissions from EGUs at 
various levels of control cost per ton for 2014. Table VI.B-2 presents 
the cost curves for ozone-season NOX emissions from EGUs. As 
discussed in section VI.D, EPA determined that $500/ton for annual and 
ozone NOX was the appropriate cost threshold for this rule 
(although EPA plans to determine in the future whether a higher cost/
ton threshold may be warranted for states contributing to nonattainment 
or maintenance problems with the 1997 ozone air quality standard 
projected to remain in two downwind areas).

 Table VI.B-1--2014 Annual NOX Emissions From Fossil-Fuel Fired EGUs Greater Than 25 MW for Each Transport Rule
                                         State at Various Costs per Ton
                                        [(2007$) per ton (thousand tons)]
----------------------------------------------------------------------------------------------------------------
                                           Base case level        $500             $1,000            $2,500
----------------------------------------------------------------------------------------------------------------
Alabama.................................                75                72                72                70
Georgia.................................                48                41                41                39
Illinois................................                55                51                50                49
Indiana.................................               117               108               107               100
Iowa....................................                45                40                39                37
Kansas..................................                32                25                25                23
Kentucky................................                83                83                81                78
Maryland................................                17                17                17                17
Michigan................................                64                61                61                60
Minnesota...............................                38                30                30                30
Missouri................................                55                54                54                51
Nebraska................................                43                27                26                21
New Jersey..............................                 8                 8                 8                 8
New York................................                19                19                18                18
North Carolina..........................                46                46                46                44
Ohio....................................                99                95                94                92
Pennsylvania............................               132               124               124               116
South Carolina..........................                38                38                37                36
Tennessee...............................                29                29                29                29
Texas...................................               141               138               138               136
Virginia................................                36                35                35                28
West Virginia...........................                64                64                64                61
Wisconsin...............................                37                32                32                31
                                         -----------------------------------------------------------------------
    Total...............................             1,321             1,236             1,229             1,174
----------------------------------------------------------------------------------------------------------------

 Table VI.B-2--2012 Ozone-Season NOX Emissions From Fossil-Fuel Fired EGUs Greater Than 25 MW for Each Transport
                                           Rule State at Various Costs
                                        [(2007$) per ton (thousand tons)]
----------------------------------------------------------------------------------------------------------------
                                           Base case level        $500             $1,000            $5,000
----------------------------------------------------------------------------------------------------------------
Alabama.................................                34                34                34                31
Arkansas................................                15                15                15                14
Florida.................................                42                27                27                24
Georgia.................................                29                28                28                25
Illinois................................                21                21                21                21
Indiana.................................                47                46                46                43
Kentucky................................                38                37                36                34

[[Page 48251]]

 
Louisiana...............................                13                13                13                13
Maryland................................                 7                 7                 7                 7
Mississippi.............................                10                10                10                 9
New Jersey..............................                 3                 3                 3                 3
New York................................                 8                 8                 8                 8
North Carolina..........................                23                23                23                21
Ohio....................................                42                42                42                38
Pennsylvania............................                53                53                52                49
South Carolina..........................                15                15                15                14
Tennessee...............................                16                16                15                15
Texas...................................                65                63                63                60
Virginia................................                15                15                15                13
West Virginia...........................                26                26                26                24
                                         -----------------------------------------------------------------------
    Total...............................               523               504               501               467
----------------------------------------------------------------------------------------------------------------

    EPA notes that the cost curves presented here differ somewhat from 
the cost curves presented in the proposal. The NOX emissions 
modeled at a $500/ton cost threshold for the final rule are lower than 
they were at proposal. In addition, the emission reductions they 
represent from the updated base case are not as pronounced as was found 
in modeling for the proposed rule. It is worth emphasizing that the 
lower emission reductions observed at $500/ton in this final rulemaking 
are due to a lower starting point in updated base case EGU 
NOX emission levels (and thus do not reflect higher 
NOX emissions remaining after the reductions made at the 
$500/ton threshold). While the base case 2012 nationwide annual EGU 
NOX emissions were approximately 3 million tons in the 
proposal, they were only 2.1 million tons in the final rule. This 
approximately 33 percent reduction in base case EGU NOX 
emissions in the final rule modeling relative to the proposal is due to 
a combination of modeling updates, including lower natural gas prices, 
reduced electricity demand, newly-modeled consent decrees and state 
rules, and updated NOX rates to reflect 2009 emissions data. 
All of these factors resulted in substantially lower base case 
Transport Rule NOX emissions in the final rule modeling.
2. Development of SO2 Cost Curves
    As explained in detail below in section VI.D, EPA determined that a 
single threshold of $500/ton for ozone-season NOX control in 
the states covered for the 1997 ozone NAAQS and a single threshold of 
$500/ton for annual NOX control in the states covered for 
the PM2.5 NAAQS were appropriate cost thresholds for 
identifying upwind control under the Transport Rule. With these 
parameters determined, EPA was able to assess the availability of 
SO2 emission reductions from EGUs at various SO2 
cost per ton thresholds with the corresponding NOX reduction 
requirements simultaneously represented in the analysis.
    This approach of simultaneously modeling cost levels for covered 
pollutants is different from the approach taken in the proposal. In the 
proposal, cost curves were developed and examined independently for 
each pollutant. For example, with the SO2 cost curves in the 
proposal, the NOX cost level was held constant at base case 
levels as the SO2 cost threshold was varied from base case 
levels to $2,400/ton. Commenters noted that this did not accurately 
reflect a reality where source owners/operators view price signals for 
all covered pollutants simultaneously and make operation decisions 
accordingly. For the final rule, EPA included cost thresholds of $500/
ton for annual NOX in PM2.5 states and $500/ton 
for ozone-season NOX in ozone-season states while examining 
different SO2 cost thresholds. This allows EPA to develop 
final cost curves for air quality analysis and budget determination 
that reflect EGU operation when faced with the appropriate cost 
thresholds on all covered pollutants. EPA believes this approach of 
modeling final cost curves is superior to the methodology used in the 
proposal because it reflects market signals for each pollutant 
simultaneously, as would be experienced by states and sources regulated 
under the Transport Rule.
    In this manner, EPA examined several SO2 cost thresholds 
of $500, $1,600, $2,300, $2,800, $3,300 and $10,000 per ton. EPA 
selected these cost thresholds for the final rule's analysis as a 
representative sampling of points along the SO2 cost curve 
thoroughly explored at proposal. Modeling of these cost thresholds 
provided a spectrum of emission reduction opportunities yielding 
meaningful differences to consider in total costs and air quality 
improvements at each threshold. The proposal's more detailed analysis 
using smaller increments between cost thresholds outlined the general 
form of the sector's SO2 emission reduction cost curve and 
therefore allowed EPA to use larger increments between cost thresholds 
for the final rule's analysis. Each of the cost thresholds examined for 
the final rule represents a point where there is a significant change 
in available controls, emission reductions, or costs and economic 
impacts. EPA believes analysis of these thresholds illustrate a 
meaningful progression of costs and air quality impacts that enabled 
the Agency to determine a proper threshold along this cost curve to 
identify significant contribution to nonattainment and interference 
with maintenance for this rulemaking.
    The cost thresholds above $500/ton were applied starting in 2014. 
In all modeling, the 2012 cost per ton threshold was held constant at 
$500/ton as EPA believes that this cost threshold captures all emission 
reductions feasible by 2012 (see section VI.B.3 below for more 
discussion). At the higher cost levels (e.g., $2,800/ton and above), 
the curve does not include all available reductions as they do not 
include non-EGU reductions. As described above for NOX, EPA 
also observed at proposal that substantial low-cost SO2 
reductions are available from the operation of existing scrubbers that 
may not otherwise operate in the future without the

[[Page 48252]]

Transport Rule in place. Therefore, all of the final SO2 
cost curves assume operation of existing scrubbers in PM2.5 
states under the Transport Rule. In 2014, approximately 3 million tons 
of SO2 reductions can be achieved at the $500/ton cost 
threshold through operation of existing controls and some fuel 
switching.
    This final cost curve also appropriately reflects the Group 1/Group 
2 distinction for states covered for PM2.5. As discussed in 
more detail in section VI.D, EPA identified Group 2 states as those 
that were linked to states where all nonattainment and maintenance 
issues had been resolved at $500/ton levels. There is no longer any 
significant contribution to nonattainment or interference with 
maintenance by these seven Group 2 states at levels above $500/ton. 
Therefore, in the final curves, these Group 2 states' cost thresholds 
were held constant at $500/ton as the higher cost thresholds were 
applied to the remaining Group 1 states starting in 2014. For example, 
the modeled emissions at the $2,300 per ton cost threshold shown in 
Table VI.B-3 below reflect each state's emissions when Group 1 states 
are subjected to a $2,300 per ton SO2 constraint and Group 2 
states are subjected to a $500/ton SO2 constraint.
    Additional reductions can be achieved at the higher cost 
thresholds. The cost curves demonstrate that sources begin to build 
significant additional flue gas desulfurization (FGD) retrofits at an 
SO2 cost threshold of $1,600 per ton and additional dry 
sorbent injection (DSI) retrofits at an SO2 cost threshold 
of $2,300 per ton.
    With these final cost curves in hand, EPA was able to identify the 
combined reductions available from upwind contributing states and the 
downwind state, at different cost-per-ton levels. Additionally, EPA was 
able to examine the economic impacts of imposing such cost constraints 
on power sector generation. However, this only constitutes a portion of 
EPA's multi-factor assessment used to determine the amount of emissions 
that represent significant contribution to nonattainment and 
interference with maintenance. As noted in the Transport Rule proposal, 
EPA's multi-factor assessment considered air quality and cost 
considerations when identifying cost thresholds (75 FR 45271). The air 
quality portion of the assessment is described in section VI.C of the 
final Transport Rule preamble.
3. Amount of Reductions That Could Be Achieved by 2012 and 2014
    EPA applied escalating SO2 cost per ton thresholds for 
Group 1 states to create the cost curves for 2014 and beyond. For 2012 
SO2, the cost per ton was held constant at $500/ton as the 
cost thresholds in 2014 and beyond were varied. The advanced pollution 
controls incentivized by these higher cost-per-ton levels can 
reasonably be installed by 2014. EPA also considered whether any of 
these emission reductions could be achieved prior to 2014. For the 
reasons that follow, EPA concluded that significant reductions could be 
achieved by 2012 and that it is important to require all such 
reductions by 2012 to ensure that they are achieved as expeditiously as 
practicable. SO2 and NOX reductions come from 
operating existing controls, installing combustion controls, fuel 
switching, and increased dispatch of lower-emitting generation which 
can be achieved by 2012. In general, compliance mechanisms that do not 
involve post-combustion control installation are feasible before 2014. 
For this reason, EPA believes it is appropriate to require these 
emissions to be removed in 2012, consistent with the Act's requirement 
that downwind states attain the NAAQS as expeditiously as practicable.
    Therefore, all of the cost curves presented below include all 
feasible 2012 reductions up to a threshold of $500/ton for 
SO2 and $500/ton for annual NOX in states linked 
to receptors for PM2.5, as well as $500/ton for ozone-season 
NOX in states linked to receptors for ozone. These cost per 
ton levels do not precipitate advanced post-combustion control 
installation in 2012 (as EPA acknowledges that such installations are 
not feasible by 2012), but they do promote the compliance options 
outlined above. The higher cost thresholds for SO2 Group 1 
states were only applied starting in 2014. Therefore, the 2012 state 
level emissions in the ``$2,300 per ton threshold'' reflect a cost 
threshold of only $500/ton for all pollutants (the $2,300 per ton value 
starts in 2014 for Group 1 states' SO2).
    The table below illustrates the change in state level 
SO2 emissions as the higher cost per ton thresholds are 
applied to Group 1 states.

Table VI.B-3--2014 SO2 Emissions From Fossil-Fuel-Fired EGUs Greater Than 25 MW for Each Transport Rule State at
                                              Various Costs per Ton
                                               [Thousand tons] \a\
----------------------------------------------------------------------------------------------------------------
                                    State     Base
                                     SO2      case      $500     $1,600    $2,300    $2,800    $3,300    $10,000
                                    group     level
----------------------------------------------------------------------------------------------------------------
Alabama.........................         2       417       201       226       213       214       236       190
Georgia.........................         2       170        94        94        95        95        95        98
Illinois........................         1       138       134       130       124       117       102        36
Indiana.........................         1       711       245       179       161       153       121        69
Iowa............................         1       127       112        78        75        67        45        13
Kansas..........................         2        70        55        57        61        61        61        45
Kentucky........................         1       488       161       126       106       103        89        46
Maryland........................         1        43        32        28        28        26        24        18
Michigan........................         1       266       206       189       144       105        94        24
Minnesota.......................         2        66        43        45        46        46        46        44
Missouri........................         1       382       212       173       166       109        84        21
Nebraska........................         2        72        68        70        70        70        70        66
New Jersey......................         1        39         7         7         7         7         6         5
New York........................         1        40        21        20        12        11        10         8
North Carolina..................         1       120       104        61        58        49        40        30
Ohio............................         1       832       294       175       137       123       115        65
Pennsylvania....................         1       507       294       164       112       107       102        75
South Carolina..................         2       210        93       100       103       104       104       105
Tennessee.......................         1       284        82        63        59        59        59        24

[[Page 48253]]

 
Texas...........................         2       453       281       282       284       281       281       243
Virginia........................         1        65        59        51        35        33        32        16
West Virginia...................         1       497       157       122        76        74        72        55
Wisconsin.......................         1       125        51        47        40        38        34        14
                                 -------------------------------------------------------------------------------
    Total.......................  ........     6,122     3,007     2,487     2,212     2,053     1,919     1,311
                                 -------------------------------------------------------------------------------
    Group 1 total...............  ........     4,665     2,172     1,612     1,340     1,180     1,025       520
                                 -------------------------------------------------------------------------------
    Group 2 total...............  ........     1,457       835       875       872       872       894       791
----------------------------------------------------------------------------------------------------------------
\a\ Note: As described in the preamble language for this section, the escalating cost per ton figures in each
  column header only apply to Group 1 states in 2014 and each year thereafter. Cost per ton for Group 2 states
  is held constant at $500/ton for all the costing runs. In some cases, the escalating cost levels in Group 1
  states affect emission levels in Group 2 states as some generation shifts between states in response to newly
  imposed costs.

C. Estimates of Air Quality Impacts (Step 2)

    After developing cost curves to show the state-by-state cost-
effective emission reductions available, EPA estimates the air quality 
impacts of these reductions using the air quality assessment tool 
coupled with full-scale air quality modeling where possible. EPA uses 
the air quality assessment tool to evaluate the impact on air quality 
for downwind nonattainment and maintenance receptors from upwind 
reductions in ``linked'' states. This section describes the development 
of the air quality assessment tool and summarizes the results of this 
evaluation.
1. Development of the Air Quality Assessment Tool and Air Quality 
Modeling Strategy
    In response to comments on the methodology used for the proposed 
rule, EPA made significant improvements to the air quality assessment 
tool (AQAT) for the final Transport Rule. Furthermore, EPA relied on 
CAMx to model the air quality response to NOX reductions and 
limited AQAT's role (relative to the Transport Rule proposal) to 
estimating the relative response of sulfate concentrations from 
SO2 reductions. EPA did not use AQAT to address 
NOX reductions in the final rule analyses. These and other 
changes to our approach, as described below and in the ``Significant 
Contribution and State Emission Budgets Final Rule TSD'', address 
commenter's concerns about the scientific rigor of the design and 
application of AQAT and commenter's recommendations to rely upon air 
quality modeling as part of this analysis.
    For the final Transport Rule, EPA created an AQAT calibration 
scenario consisting of full-scale air quality modeling using CAMx of a 
2014 control scenario reflecting SO2 and NOX 
emission reductions of similar stringency and from the same geography 
as the Transport Rule proposal. Modeling of this AQAT calibration 
scenario reflected all updates made to the air quality modeling 
platform, as described in the ``Air Quality Modeling Final Rule TSD'' 
found in the docket for this rulemaking. CAMx modeling of each 
receptor's response in this control scenario accounts for complex 
chemical interactions and covariation of these pollutants. Among the 
important atmospheric chemical interactions accounted for in CAMx is 
``nitrate replacement.'' \43\ Nitrate replacement occurs when 
SO2 emission reductions lead to decreases in ammonium 
sulfate, which in turn, can result in an increase in ammonium nitrate 
concentrations. As described below, EPA used the CAMx modeling results 
for this AQAT calibration scenario together with the modeling for the 
2012 base case to characterize the response of ozone, nitrate, and 
sulfate at each nonattainment and maintenance receptor to the mix of 
upwind NOX and SO2 emission reductions at each 
cost threshold.
---------------------------------------------------------------------------

    \43\ Observable indicators of the sensitivity of 
PM2.5 nitrate to emission reductions--Part II: 
Sensitivity to errors in total ammonia and total nitrate of the 
CMAQ-predicted non-linear effect of SO2 emission 
reductions. R.L. Dennis, P.K. Bhave, and R.W. Pinder. 2008. 
Atmospheric Environment (42):1287-1300.doi:10.1016/
j.atmosenv.2007.10.036.
---------------------------------------------------------------------------

    As described in section VI.D, EPA determined that the $500/ton 
threshold for upwind annual and ozone-season NOX control is 
appropriate for the final Transport Rule (although EPA plans to 
determine in the future whether a higher cost/ton threshold may be 
warranted for states contributing to nonattainment or maintenance 
problems with the 1997 ozone air quality standard projected to remain 
at receptors in two downwind areas \44\). Because this threshold 
corresponds to the NOX control strategy modeled in the AQAT 
calibration scenario described above, EPA is able to rely on this CAMx 
air quality modeling to assess the response of ozone and nitrate 
concentrations due to NOX reductions and does not estimate 
ozone or nitrate impacts for this final rulemaking using AQAT. Further 
information on the air quality modeling of this AQAT calibration 
scenario can be found in the Air Quality Modeling Final Rule TSD and 
the Significant Contribution and State Emission Budgets Final Rule TSD 
in the docket for this rulemaking.
---------------------------------------------------------------------------

    \44\ Houston and Baton Rouge nonattainment areas.
---------------------------------------------------------------------------

    In order to estimate 2014 annual and 24-hour PM2.5 
concentrations, AQAT uses the 2012 annual and seasonal contributions 
which quantify the contribution of SO2 emissions in specific 
upwind states to sulfate concentrations at specific downwind receptors. 
These contributions are described in section V.D.2 and the Air Quality 
Modeling Final Rule TSD.
    EPA utilizes CAMx modeling of the AQAT calibration scenario, 
described above, to ``calibrate'' the contribution factors by 
developing and applying linear sulfate response factors for each 
downwind receptor. These factors calibrate each receptor's sulfate 
response to varying levels of upwind SO2 emissions. These 
calibration factors are based on the sulfate response modeled by CAMx 
due to emission changes occurring between the 2012 base case and the 
2014 AQAT

[[Page 48254]]

calibration scenario. Calibration factors were constructed for the 
annual and 24-hour PM2.5 AQAT.
    To further allow adequate assessment of the seasonal impacts of 
various levels of upwind SO2 reductions on each receptor's 
24-hour PM2.5 concentration using AQAT, EPA developed 
response factors for sulfate on a quarterly basis to capture important 
air quality differences between summer and winter emissions and 
concentrations. This process allowed EPA to estimate the air quality 
values for each season at each cost threshold, and then estimate the 
air quality design values.
    Finally, EPA's air quality assessment accounts for the impact that 
this differential response in sulfate by quarter can have on the 
ordering of 24-hour concentrations when calculating the 98th percentile 
for the 24-hour standard. AQAT estimates quarterly-specific relative 
response factors that estimate quarterly-specific proportional change 
in ammonium sulfate resulting from the SO2 emission 
reduction from the 2012 base case scenario to the 2014 cost threshold 
scenario being assessed. These quarterly relative response factors are 
then applied to each of the maximum 24-hour PM2.5 
concentrations for eight days per quarter per year at each receptor 
from the 2012 base case. This methodology improvement allows EPA to 
redetermine the 98th percentile day for each year and recalculate 
average and maximum design values for the 24-hour PM2.5 
standard.
    These improvements for the final rule increase EPA's confidence 
that the air quality estimates provided by AQAT, now customized for 
this application, more accurately estimate the results of full-scale 
air quality modeling of the various levels of upwind SO2 
reductions considered. EPA evaluated the estimates from AQAT using an 
independent data set, the 2014 base case estimates from CAMx, finding 
that the results are unbiased with minimal differences. See 
``Significant Contribution and State Emission Budgets Final Rule TSD'' 
for more details.
    As such, EPA believes the revised AQAT provides an appropriate 
basis for assessing the air quality portion of the multi-factor 
methodology to define significant contribution to nonattainment and 
interference with maintenance.\45\
---------------------------------------------------------------------------

    \45\ EPA used CAMx to conduct full air quality modeling of the 
final Transport Rule remedy embodying the emission reductions that 
EPA first selected on the basis of the multi-factor analysis using 
AQAT to project air quality impacts from varying levels of emission 
reductions analyzed. The CAMx results confirmed the relative 
magnitude and direction of AQAT's estimates of the outcomes for the 
2012 base case nonattainment and maintenance receptors analyzed, and 
the AQAT estimates closely tracked CAMx-modeled concentrations at 
those receptors under the Transport Rule remedy. The paired AQAT-
estimated and CAMx-modeled concentrations were found to be highly 
correlated with an R\2\ value of 0.997. As a result, EPA is 
confident that AQAT's estimates of impacts on sulfate concentrations 
at the varying levels of SO2 emission reductions analyzed 
provide a technically valid and sound basis for the Agency's 
selection of the final rule's emission reductions necessary to 
eliminate (or make meaningful progress toward eliminating) 
significant contribution and interference with maintenance for the 
PM2.5 NAAQS considered in this rulemaking. Further 
details on the comparison of CAMx and AQAT results can be found in 
the Significant Contribution and State Emission Budgets Final Rule 
TSD.
---------------------------------------------------------------------------

2. Utilization of AQAT To Evaluate Control Scenarios
    For the final Transport Rule, EPA performed air quality analysis 
for each downwind annual and 24-hour PM2.5 receptor with a 
nonattainment and/or maintenance problem in the 2012 base case. For 
each receptor, EPA quantified the sulfate reduction and resulting air 
quality improvement when a group of states consisting of the upwind 
states that are ``linked'' to the downwind receptor (as explained in 
section V.D) and the downwind state where the receptor is located, all 
made the SO2 emission reductions that EPA identified as 
available at each cost threshold. EPA assumes reductions at each cost 
threshold from the linked upwind states as well as the downwind 
receptor state to assess the shared responsibility of these upwind 
states to address air quality at the identified receptors. Analysis of 
each receptor did not assume any emission reductions beyond those 
included in the 2014 base case from upwind states that are not 
``linked'' to that specific downwind receptor (even if the state was 
``linked'' to a different receptor and/or otherwise would have made 
emission reductions beginning in 2012 due to the Transport Rule).
    EPA disagrees with comments suggesting that emission reductions, 
and resulting decreases in contribution, from upwind states that are 
not ``linked'' to a particular downwind receptor should be accounted 
for in the 2014 AQAT analysis of that receptor. EPA decided to assume 
reductions only from linked states when analyzing each receptor because 
EPA is performing a state-specific analysis to support a determination 
of the amount of each upwind state's responsibility for air quality 
problems at the downwind receptors that it significantly affects. If 
the AQAT analysis were to assume emissions reductions in other non-
linked states, the AQAT analysis would then contradict the first step 
of our two-step approach to defining significant contribution to 
nonattainment and interference with maintenance. Under EPA's two-step 
approach, only a state that (1) contributes a threshold amount or more 
to a particular downwind state receptor's air quality problem, and (2) 
has emission reductions available at the selected cost threshold can be 
deemed to have responsibility to reduce its emissions to improve air 
quality at that downwind receptor. EPA believes that the commenters' 
suggested approach would not qualify as a state-specific approach for 
determining upwind state responsibility for downwind air quality 
problems.
    Because EPA is relying on the CAMx estimate of nitrate 
concentrations from the AQAT calibration scenario, the response in 
nitrate to NOX reductions at a cost threshold of $500/ton is 
present in each SO2 cost threshold scenario analyzed.
    EPA determines the cumulative air quality improvement that can be 
expected at a particular downwind receptor by multiplying each upwind 
state's percent SO2 emission reduction by its calibrated 
receptor specific sulfate response factor and summing the sulfate, 
nitrate, and other PM2.5 components (also taken from the 
2014 CAMx AQAT calibration scenario).
3. Air Quality Assessment Results
    The results of EPA's air quality assessment of the cost threshold 
scenarios focus on air quality metrics including, but not limited to, 
average air quality improvement at receptors with 2012 base case 
nonattainment and maintenance exceedances and an evaluation of 
estimated receptor design values against annual and 24-hour 
PM2.5 standards. See ``Significant Contribution and State 
Emission Budgets Final Rule TSD'' for more details.
    In EPA's air quality analysis of each downwind receptor, all air 
quality improvements are measured relative to the ``AQAT base case.'' 
This base case reflects AQAT's estimated PM2.5 
concentrations under base case 2014 SO2 emissions. The AQAT 
base case itself is not used for any decision points and only serves as 
an appropriate starting point for comparison of air quality 
improvements at SO2 cost thresholds. EPA ensures internal 
analytic consistency by comparing all air quality improvements at 
analyzed SO2 cost thresholds to the AQAT base case.
    Regarding average air quality improvement at exceeding 2012 base 
case receptors, EPA identified 41 receptors with nonattainment or 
maintenance problems in the 2012 base

[[Page 48255]]

case. EPA assessed the cumulative reduction in 24-hour PM2.5 
maximum design value at each increasing SO2 cost threshold 
from the maximum design value from the AQAT base case, and averaged the 
reduction across the 41 receptors. The results of this assessment 
indicate diminishing incremental returns to 24-hour PM2.5 
maximum design value reduction as SO2 cost threshold levels 
increase. EPA finds reductions in maximum design value of 4.28 [mu]g/
m\3\ at $500; 4.98 [mu]g/m\3\ at $1,600; 5.33 [mu]g/m\3\ at $2,300; 
5.46 [mu]g/m\3\ at $2,800; 5.60 [mu]g/m\3\ at $3,300; and 6.08 [mu]g/
m\3\ at $10,000. These results are provided in table VI.C-1.

  Table VI.C-1--Average 2014 Air Quality Improvement at Receptors With
          2012 Base Case Nonattainment and Maintenance Problems
------------------------------------------------------------------------
                                                           Average air
                                                             quality
                                                         improvement at
       Group 1 state SO2 cost per ton threshold             exceeding
                                                          receptors in
                                                         2012 base case
                                                          ([mu]g/m\3\)
------------------------------------------------------------------------
$500..................................................              4.28
$1,600................................................              4.98
$2,300................................................              5.33
$2,800................................................              5.46
$3,300................................................              5.60
$10,000...............................................              6.08
------------------------------------------------------------------------

    Additionally, EPA evaluated the AQAT estimated 2014 average and 
maximum design values for these receptors at each cost threshold 
against the annual and 24-hour PM2.5 standards. EPA 
determined the estimated number of receptors with nonattainment or 
maintenance problems at $500/ton cost threshold of NOX and 
each of the cost threshold scenarios assessed for SO2. These 
results are provided in table VI.C-2 in terms of the number of 
receptors and the number of nonattainment areas containing these 
receptors.

                 Table VI.C-2--Receptors With Nonattainment and/or Maintenance Exceedances of the Annual or 24-Hour PM2.5 NAAQS in 2014
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                        Annual               Annual              24-hour              24-hour         Annual and 24-hour
                                                    nonattainment       nonattainment or      nonattainment       nonattainment or    nonattainment and
               SO2 cost threshold               ---------------------     maintenance     ---------------------     maintenance          maintenance
                                                                     ---------------------                     -----------------------------------------
                                                  Receptors   Areas    Receptors   Areas    Receptors   Areas    Receptors   Areas    Receptors   Areas
--------------------------------------------------------------------------------------------------------------------------------------------------------
$500...........................................           1        1           1        1           2        2           9        6           9        6
$1,600.........................................           1        1           1        1           2        2           8        5           8        5
$2,300.........................................           0        0           1        1           1        1           6        4           6        4
$2,800.........................................           0        0           1        1           1        1           5        4           5        4
$3,300.........................................           0        0           1        1           1        1           5        4           5        4
$10,000........................................           0        0           1        1           1        1           3        3           3        3
--------------------------------------------------------------------------------------------------------------------------------------------------------

    In the proposal, EPA evaluated whether the imposition of the rule's 
upwind emission reduction requirements could cause changes in operation 
of electric generating units in states not regulated under the 
proposal. EPA recognized that such changes could lead to increased 
emissions in those states, potentially affecting whether they would 
meet or exceed the 1 percent contribution thresholds used to identify 
linkages between upwind and downwind states. Such shifting of emissions 
between states may occur because of the interconnected nature of the 
country's energy system (including both the electricity grid as well as 
coal and natural gas supplies).
    Using updated emissions and air quality information developed for 
the final rule, EPA's IPM modeling found that of the states not covered 
in the final rule for PM2.5, Arkansas, Colorado, Louisiana, 
Montana, and Wyoming are all projected to have SO2 emission 
increases above 5,000 tons in 2014 with the rule in effect. EPA 
analysis shows the SO2 emission increases result from 
expected shifts to higher sulfur coal in these states. Using AQAT, a 
state-level assessment of these emission increases relative to the 
state specific contributions to downwind receptors (where available) 
indicates that projected increases in the SO2 emissions 
would not increase any of these states' contributions to an amount that 
would meet or exceed the 0.15 [mu]g/m\3\ or 0.35 [mu]g/m\3\ thresholds 
for annual and 24-hour PM2.5, respectively. For this reason, 
EPA has determined that it is not necessary to include these additional 
states in the Transport Rule as a result of the effects of the rule 
itself on SO2 emissions in uncovered states. See 
``Significant Contribution and State Emission Budgets Final Rule TSD'' 
in the docket for this rulemaking for more details.

D. Multi-Factor Analysis and Determination of State Emission Budgets

    EPA used the cost, emission, and air quality information described 
in the previous sections to perform its multi-factor analysis. By 
looking at different ``cost thresholds''--places where there was a 
noticeable change on the cost curve because emission reductions occur--
and examining the corresponding impact on air quality, EPA identified 
the amount of emissions that represent significant contribution to 
nonattainment and interference with maintenance within each state. 
After quantifying this amount of emissions, EPA established state 
``budgets'' which represent the remaining emissions for the state in an 
average year (step 4).
    For states covered by the rule for PM2.5, EPA calculated 
annual NOX and annual SO2 budgets. For states 
covered by the rule for ozone, EPA calculated ozone-season 
NOX budgets. This section explains the multi-factor 
assessment and how EPA used this assessment to determine state-specific 
budgets.
1. Multi-Factor Analysis (Step 3)
a. Overview
    As described in section VI.B, EPA examined how different cost 
thresholds impacted emissions in states with air quality contributions 
that meet or exceed specific air quality thresholds, as discussed in 
section V.D of this preamble. Section VI.C summarizes the estimated air 
quality impacts in 2014 of these emission levels at downwind receptors, 
including estimates of their nonattainment and maintenance status (see 
``Significant Contribution and State Emission Budgets Final Rule TSD'' 
for more details). From these two steps, EPA evaluated the interaction 
between upwind emissions at different cost levels and air quality at 
downwind receptors to identify ``significant cost thresholds.'' These 
cost thresholds are

[[Page 48256]]

based on air quality considerations (such as the cost at which the air 
quality assessment analysis projects large numbers of downwind site 
maintenance and nonattainment problems would be resolved) or cost 
criteria (such as a cost where large emissions reductions occur because 
a particular technology is widely implemented at that cost). EPA 
examined each cost threshold and then used a multi-factor assessment to 
determine which serve as cost thresholds that eliminate significant 
contribution to nonattainment and interference with maintenance for 
upwind states. Air quality considerations in the assessment include, 
for example, how much air quality improvement in downwind states 
results from upwind state emission reductions at different levels; 
whether, considering upwind emission reductions and assumed local (in-
state) reductions, the downwind air quality problems would be resolved; 
and the components of the remaining downwind air quality problem (e.g., 
whether it is a predominantly local or in-state problem, or whether it 
still contains a large upwind component). Cost considerations include, 
for example, how the cost per ton of emission reduction compares with 
the cost per ton of existing federal and state rules for the same 
pollutant; whether the cost per ton is consistent with the cost per ton 
of technologies already widely deployed (similar to the highly-cost-
effective criteria used in both the NOX SIP Call and CAIR); 
and what cost increase is required to achieve additional meaningful air 
quality improvement.
    The specific cost per ton thresholds selected as a basis for 
identifying significant contribution to nonattainment and interference 
with maintenance in this rulemaking apply only to the determinations 
made in this rule and do not establish any precedent for future EPA 
actions under section 110(a)(2)(D)(i)(I) or any other section of the 
CAA. EPA's selection of specific cost thresholds in the context of this 
rulemaking relies on current analyses of the cost of available emission 
reductions, the pattern of interstate linkages for pollution transport, 
and the downwind air quality impacts specifically related to the 1997 
ozone NAAQS, the 1997 annual PM2.5 NAAQS, and the 2006 24-
hour PM2.5 NAAQS. In addition and as explained below, the 
selection of the threshold for ozone-season NOX was 
influenced by the limited scope of this rule. Any or all of these 
variables used to identify specific cost thresholds are subject to 
change. Thus, EPA may use different cost thresholds in future actions, 
even if those actions relate to the same NAAQS addressed in this rule.
b. Cost Thresholds Examined and Selected for Ozone-Season 
NOX
    In the proposal, EPA examined various cost thresholds for ozone 
season NOX and identified a cost threshold with rapidly 
diminishing returns at $500/ton. EPA observed that moving beyond the 
$500 cost threshold up to a $2,500 cost threshold would result in only 
minimal additional ozone season NOX emission reductions and 
would likely bypass less expensive non-EGU emission reduction 
opportunities (75 FR 45281). EPA noted that for greater costs the 
curves did not include all available reductions as they do not include 
non-EGU reductions (75 FR 44286). In the proposal, EPA noted the timely 
promulgation and implementation of this rule is responsive to the 
Court's remand of CAIR, will accelerate critical air quality 
improvement, and more effectively address the mandate of CAA section 
110(a)(2)(D) to address significant contribution to nonattainment and 
interference with maintenance as expeditiously as practicable. EPA did 
not want to risk delaying air quality benefits available from EGU 
emission reductions, particularly those emission reductions which 
eliminate significant contribution to nonattainment and interference 
with maintenance for many receptors, while the Agency conducts 
additional analysis to support subsequent transport-related rulemakings 
including coverage of non-EGU sources (75 FR 45285).
    EPA received comments suggesting that it consider cost thresholds 
higher than $500/ton as reductions beyond the proposed $500/ton cost 
threshold were needed to fully resolve nonattainment and maintenance 
issues in downwind states analyzed at proposal. Some of these comments 
suggested EPA should include non-EGUs as they consider the higher cost 
thresholds, others suggested EPA continue to exclude non-EGU sources in 
this rulemaking.
    In response to those comments that suggested EPA explore higher 
cost thresholds because nonattainment and maintenance was not fully 
resolved, EPA first notes that CAA section 110 (a)(2)(D)(i)(I) only 
requires the elimination of emissions that significantly contribute to 
nonattainment or interfere with maintenance of the NAAQS in other 
states. Section 110(a)(2)(D)(i)(I) focuses exclusively on the transport 
component of nonattainment and maintenance problems. Section 
110(a)(2)(D)(i)(I) does not shift to upwind states the responsibility 
for ensuring that all areas in other states attain the NAAQS. As such, 
the mandate of section 110(a)(2)(D)(i)(I) is not to ensure that 
reductions in upwind states are sufficient to bring all downwind areas 
in to attainment, it is simply to ensure that all significant 
contribution to nonattainment and interference with maintenance is 
eliminated. Thus, the presence of residual nonattainment or maintenance 
areas does not, by itself, signify a failure to satisfy the 
requirements of 110(a)(2)(D)((i)(I).
    Furthermore, as noted in section VI.A, EPA is finalizing coverage 
only for the EGU emission source-sector category in this rulemaking. 
EPA has not included non-EGU sources in this final rulemaking. EPA 
remains convinced that timely promulgation and implementation of this 
rule is responsive to the Court's remand of CAIR.
    To the extent that significant contribution is not eliminated for 
the 1997 ozone NAAQS standard at the $500/ton cost threshold, EPA is 
not addressing in this rulemaking whether a cost threshold greater than 
$500/ton is justified for some upwind states and downwind receptors. 
EPA believes it can best serve these states where concerns persist 
regarding projected nonattainment or maintenance of the 1997 ozone 
NAAQS by quickly finalizing this rule and seeking further non-EGU 
reductions in subsequent rulemakings. Table VI.B-2 illustrates the 
small amount of EGU reductions available as cost threshold increases 
above $500/ton. The ozone-season NOX reductions available in 
the Transport Rule states between the $500/ton and $1,000/ton cost 
thresholds amount to less than 3,000 tons. EPA believes that 
potentially substantial non-EGU ozone-season NOX reductions 
become available approaching the $1,000/ton cost threshold. EPA 
emphasized this in the proposal, noting that the cost curves for ozone 
season NOX did not reflect all available reductions as they 
do not include non-EGU reductions (75 FR 45286). For these reasons, EPA 
did not consider cost thresholds greater than $500/ton.
    EPA did not consider cost thresholds below $500/ton for ozone-
season NOX. $500/ton is a reasonable threshold representing 
a significant amount of lowest-cost NOX emission reductions 
from EGUs, largely accruing from the installation of combustion 
controls, such as low-NOX burners, and constitutes a 
reasonable cost level for operation of existing NOX controls 
such as SCRs. EPA believes it would be

[[Page 48257]]

inappropriate for a state linked to downwind nonattainment or 
maintenance areas to stop operating existing pollution control 
equipment (which would increase their emissions and contribution). This 
is increasingly likely to occur at cost thresholds lower than $500/ton. 
Therefore, EPA did not find cost thresholds lower than $500/ton for 
ozone-season NOX to be reasonable for development of the 
Transport Rule cost curves.
    As discussed in section III of this preamble, EPA intends to 
finalize reconsideration of the March 2008 ozone NAAQS in the summer of 
2011 and to expeditiously propose a transport-related action to address 
any necessary upwind state control responsibilities with respect to 
that reconsidered NAAQS.
c. Cost Thresholds Examined and Selected for Annual NOX
    Following the assessment of the cost curves in section IV.B and the 
air quality modeling of the AQAT calibration scenario using CAMx, EPA 
identified a single cost threshold at $500/ton for annual 
NOX. Beyond requiring the year-round operation of existing 
post-combustion NOX controls and other reductions modeled at 
$500/ton threshold, EPA observed a limitation in available low-cost 
annual NOX reductions from EGUs. Approximately 7,000 tons of 
annual NOX reductions were available from EGUs between the 
$500/ton and the $1,000/ton cost thresholds (See Table VI.B.-1). 
Furthermore, above the $500/ton threshold, similar to ozone-season 
NOX cost curves, the annual NOX cost curves do 
not include all available reductions as they do not include non-EGU 
reductions. EPA analysis suggests that while NOX emission 
reductions lead to reductions in PM2.5, SO2 
reductions are generally more cost-effective than NOX 
reductions at reducing PM2.5 (75 FR 45281). In part, for 
these reasons, EPA's multi-factor assessment suggested that the $500/
ton cost threshold for annual NOX in concert with the cost 
thresholds identified for SO2 were the appropriate cost 
thresholds for eliminating significant contribution to nonattainment 
and interference with maintenance. EPA finds in the final Transport 
Rule that the $500/ton cost threshold for annual NOX, in 
concert with the SO2 cost threshold selected below, 
successfully eliminates significant contribution to nonattainment and 
interference with maintenance for the 1997 annual PM2.5 
NAAQS and the 2006 24-hour PM2.5 NAAQS in the states covered 
by this Rule for PM2.5.
    The reasons for not considering cost thresholds lower than $500/ton 
for annual NOX are the same as those identified for not 
doing so for ozone-season NOX. In addition to its 
PM2.5 reduction benefits, annual NOX control at 
the $500/ton threshold can help to reduce nitrate replacement in the 
atmosphere. As explained earlier, nitrate replacement happens when 
SO2 emissions reductions successfully reduce ammonium 
sulfate (a component of PM2.5) but provoke a 
PM2.5 rebound effect by freeing up additional ammonia to 
form ammonium nitrate (another component of PM2.5).
d. Cost Thresholds Examined and Selected for SO2
    EPA first assessed the downwind air quality impacts of emission 
reductions modeled at the $500/ton threshold in all states found to be 
linked to downwind sites for PM2.5 transport, as well as in 
the states hosting those downwind sites. The air quality assessment 
tool projected that those reductions do not fully resolve nonattainment 
and maintenance problems with the PM2.5 standards for 
certain areas to which the following states are linked: Illinois, 
Indiana, Iowa, Kentucky, Maryland, Michigan, Missouri, New Jersey, New 
York, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West 
Virginia, and Wisconsin. EPA proceeded to analyze available 2014 
emission reductions at higher cost thresholds from these states, 
collectively referred to as Group 1 states for SO2 control.
    For Group 2 states, the air quality assessment tool projected that 
the SO2 reductions at this first cost threshold assessed 
would resolve the nonattainment and maintenance problems for all of the 
areas to which the following states are linked: Alabama, Georgia, 
Kansas, Minnesota, Nebraska, South Carolina, and Texas. EPA thus finds 
that these states' significant contribution is eliminated at the $500 
per ton level in 2014; they are collectively referred to as Group 2 
states for SO2 control. Because their significant 
contribution is eliminated at this stringency of control, EPA did not 
analyze higher cost thresholds for Group 2 states.
    The states in Group 1 and Group 2 are rationally grouped 
considering air quality and cost. EPA determined that it would not be 
appropriate to assign the same cost threshold to Group 2 and Group 1 
states because a significantly lower cost threshold was sufficient to 
resolve air quality problems at all downwind receptors linked to the 
Group 2 states. Although states are linked to different sets of 
downwind receptors, EPA analysis indicated that the cost threshold 
needed to resolve downwind air quality problems varied only to a 
limited extent among states within Group 1 and among states within 
Group 2. It did, however, vary greatly between the Group 1 and Group 2 
states. The ruling of the DC Circuit in Michigan v. EPA, 213 F.3d 663, 
679-80 (D.C. Cir. 2000), accepting EPA's prior use of a transport 
remedy with uniform controls, supports EPA's decision to use a uniform 
cost threshold for a group of states.
    As discussed in section VI.B, the cost threshold for Group 1 states 
was examined at escalating levels in 2014 (it remained at $500/ton for 
Group 2 states). EPA examined emissions at SO2 cost 
thresholds of $500, $1,600, $2,300, $2,800, $3,300, and $10,000/ton for 
Group 1 states in 2014. The higher SO2 marginal costs were 
only imposed in Transport Rule states starting in 2014, by which time 
the advanced pollution control retrofits induced at those higher cost 
thresholds could be installed. (See section VI.D.2 for EPA's assessment 
and decisions regarding SO2 budget formation in Group 1 
states in 2014.)
    EPA observed some degree of additional air quality benefit at 
downwind receptors across all of the cost thresholds examined for 
SO2, but significant air quality outcomes were achieved at 
the $2,300/ton cost threshold. The $2,300/ton threshold is projected to 
resolve the last remaining nonattainment area for the annual 
PM2.5 standard (Liberty-Clairton),\46\ and it also is 
projected to resolve the nonattainment and maintenance problems with 
the 24-hour PM2.5 standard at 1 monitor in the Detroit area 
and resolve the maintenance problems in the Cleveland area. There were 
significant air quality improvements at this level in connection with 
widespread deployment of pollution control technology, while the cost 
impacts remained reasonable.
---------------------------------------------------------------------------

    \46\ AQAT results indicated that one receptor in the Liberty-
Clairton area continued to have maintenance problems with the annual 
PM2.5 standard. However, final air quality modeling 
results (described in section VIII.B) indicated that this 
maintenance problem was resolved for this receptor under the final 
Transport Rule.
---------------------------------------------------------------------------

    Moving beyond $2,300/ton to the $2,800/ton and $3,300/ton 
thresholds, EPA projected notably smaller air quality improvements 
compared to those projected when moving from the $1,600/ton threshold 
to the $2,300/ton threshold. EPA also projected no ultimate change in 
the 24-hour PM2.5

[[Page 48258]]

attainment status of the remaining nonattainment area (Liberty-
Clairton) or three remaining maintenance areas (Chicago,\47\ Detroit, 
and Lancaster).\48\ At the same time, the total program cost continued 
to increase by about the same interval at each of these thresholds as 
it had between the $1,600/ton and $2,300/ton thresholds. EPA thus 
observed a relatively lower cost-effectiveness of downwind 
PM2.5 control via upwind SO2 reductions beyond 
$2,300/ton for the receptors linked to Group 1 states. Table VI.D-1 and 
Figure VI.D-1 demonstrate this relationship between cost of EGU 
SO2 control and downwind PM2.5 concentration 
impacts, showing a sustained diminishing of cost effectiveness beyond 
the $2,300/ton threshold. The $2,300/ton threshold in this analysis is 
situated at the ``knee-in-the-curve'' area of cost-effectiveness for 
addressing downwind PM2.5 concentrations with SO2 
reductions, beyond which point the air quality gains per dollar spent 
on additional reductions are much smaller. This relationship is 
demonstrative of the economic potency of SO2 reductions at 
each cost threshold to address the PM2.5 concentrations at 
linked receptors in this analysis.
---------------------------------------------------------------------------

    \47\ This area is not currently designated as nonattainment for 
the 24-hour PM2.5 standard. EPA is portraying the 
receptors and counties in this area as a single 24-hour maintenance 
area based on the annual PM2.5 nonattainment designation 
of Chicago-Gary-Lake County, IL-IN.
    \48\ AQAT results indicated that two receptors in the Detroit 
area continued to have maintenance problems with the 24-hour 
PM2.5 standard. However, final air quality modeling 
results (described in section VIII.B) indicated that only one 
receptor continued to have maintenance problems in this area for 
this standard under the final Transport Rule.

          Table VI.D-1--Cost-Effectiveness of Group 1 State SO2 Reductions a for Downwind PM2.5 Control
----------------------------------------------------------------------------------------------------------------
                                                                                            Air quality cost-
                                        Additional system cost     Average PM2.5 air      effectiveness (average
          SO2 cost threshold              expended  (2007$,       quality improvement     [micro]g/m\3\ reduced
                                              billions)           ([micro]g/m\3\) \b\         per billion  $
                                                                                                expended)
----------------------------------------------------------------------------------------------------------------
$500.................................                     0.22                     3.27                    14.74
$1,600...............................                     0.82                     3.86                     4.70
$2,300...............................                     1.35                     4.22                     3.11
$2,800...............................                     1.94                     4.37                     2.25
$3,300...............................                     2.36                     4.50                     1.91
$10,000..............................                     3.61                     4.99                     1.38
----------------------------------------------------------------------------------------------------------------
\a\ Downwind PM2.5 improvement based on SO2 reductions from states ``linked'' to specific receptors. See section
  VI.C.
\b\ Measured as the reduction in maximum design value for the 24-hour PM2.5 NAAQS from AQAT base case to each
  SO2 threshold for receptors with remaining nonattainment and maintenance exceedances at the $500/ton
  threshold, averaged across these receptors.

  [GRAPHIC] [TIFF OMITTED] TR08AU11.000
  
    Furthermore, even at the $10,000/ton cost threshold, AQAT still 
projects Liberty-Clairton to face maintenance concerns with the annual 
PM2.5 standard and is projected to remain in nonattainment 
of the 24-hour PM2.5 standard, while the Chicago \49\ and 
Lancaster areas are still projected to have residual maintenance 
problems

[[Page 48259]]

with the 24-hour PM2.5 standard. EPA projected that even 
total elimination of EGU SO2 emissions (no matter the cost) 
would not be able to resolve either nonattainment of the 24-hour 
PM2.5 standard in the Liberty-Clairton area or the residual 
maintenance concerns with that standard in Lancaster County. EPA thus 
finds that other PM2.5 strategies, including local 
reductions of other PM2.5 precursors, are important to 
consider for remaining nonattainment and maintenance areas to seek 
further improvements in PM2.5 concentrations.
---------------------------------------------------------------------------

    \49\ This area is not currently designated as nonattainment for 
the 24-hour PM2.5 standard. EPA is portraying the 
receptors and counties in this area as a single 24-hour maintenance 
area based on the annual PM2.5 nonattainment designation 
of Chicago-Gary-Lake County, IL-IN.
---------------------------------------------------------------------------

    Considering both air quality and cost, EPA's multi-factor analysis 
indicated $2,300 per ton as an appropriate cost threshold for 
SO2 in the Group 1 states. EPA believes the analyzed cost 
thresholds lower than $2,300/ton were not appropriate for 
SO2 control in the Group 1 states under the Transport Rule 
for the following reasons:
     Downwind air quality impacts up to the $2,300 threshold 
are significant. Moving up to $2,300/ton successfully resolves all 
downwind nonattainment of the annual and 24-hour PM2.5 
standards except for the Liberty-Clairton receptor in Allegheny county 
with respect to 24-hour PM2.5, which EPA has noted is 
heavily influenced by a local source of organic carbon (75 FR 45281).
     Upwind emission reductions available up to $2,300/ton are 
highly cost-effective compared with similar regulations.
     The emission reductions up to this threshold are 
achievable with widespread deployment of controls that can be installed 
at power plants by 2014.
     As stated at proposal, EPA finds it reasonable to require 
a substantial level of control of upwind state emissions that 
significantly contribute to nonattainment or maintenance problems in 
another state. The $2,300/ton cost threshold is comparable to EPA's 
survey of local non-EGU SO2 reduction opportunities in the 
PM2.5 NAAQS RIA, which range in cost from just above $2,300/
ton to over $16,000/ton (2007 $). EPA thus finds it reasonable to seek 
EGU SO2 reductions up to $2,300/ton (rather than at a lower 
cost threshold) in the states linked to receptors with ongoing 
attainment and maintenance concerns with the PM2.5 NAAQS.
    EPA believes the analyzed cost thresholds above $2,300/ton were not 
appropriate for SO2 control in the Group 1 states under the 
Transport Rule for the following reasons:
     As noted above, AQAT suggests reductions up to $2,300/ton 
were able to resolve all projected downwind nonattainment of the annual 
and 24-hour PM2.5 NAAQS, with the sole exception of 
projected nonattainment of the 24-hour PM2.5 standard at a 
receptor in Liberty-Clairton. It is well-established that, in addition 
to being impacted by regional sources, the Liberty-Clairton area is 
significantly affected by local emissions from a sizable coke 
production facility and other nearby sources, leading to high 
concentrations of organic carbon in this area.\50\ EPA finds that the 
remaining PM2.5 nonattainment problem is predominantly local 
and therefore does not believe that it would be appropriate to 
establish a higher cost threshold solely on the basis of this projected 
ongoing nonattainment of the 24-hour PM2.5 standard at the 
Liberty-Clairton receptor.
---------------------------------------------------------------------------

    \50\ http://www.epa.gov/pmdesignations/2006standards/final/TSD/tsd_4.0_4.3_4.3.3_r03_PA_2.pdf.
---------------------------------------------------------------------------

     Approximately 70 percent of base case SO2 
emissions from Group 1 states were eliminated at the $2,300/ton cost 
threshold, leaving a decreasing amount of emission reductions available 
at each increased cost threshold beyond $2,300/ton.
     Additional EGU SO2 reductions available from 
EGUs beyond the $2,300/ton threshold level realize significantly less 
improvement in downwind PM2.5 concentrations per dollar 
spent to impact receptors linked to Group 1 states. In other words, the 
cost-effectiveness of controlling EGU emissions in Group 1 states to 
improve downwind PM2.5 concentrations at the linked 
receptors is notably diminished beyond the $2,300/ton threshold in this 
analysis. See Figure VI.D-1.
     EGUs are by far the largest source category for 
SO2 emissions. This analysis shows that reductions of EGU 
SO2 emissions up to the $2,300/ton cost threshold were 
significantly more cost-effective for improving downwind 
PM2.5 concentrations than further such reductions (beyond 
the $2,300/ton cost threshold) would be to address the remaining 
PM2.5 maintenance concerns. EPA's analysis also shows that 
these maintenance concerns cannot be fully resolved even with complete 
elimination of all remaining EGU SO2 emissions, no matter 
the cost. EPA finds that other PM2.5 precursor emission 
reductions, particularly those from local sources will be critical for 
states in these remaining areas to consider for controlling 
PM2.5 concentrations with respect to maintenance of the 2006 
24-hour PM2.5 NAAQS.
    In summary, the appropriate cost thresholds for each state were 
identified through the multi-factor assessment. This assessment 
included both cost and air quality considerations. As explained above, 
the ozone-season NOX threshold was determined to be $500/ton 
for all states required to reduce ozone-season NOX, with 
residual nonattainment and maintenance concerns to be addressed in a 
future rulemaking addressing a broader set of source categories for 
additional cost-effective reductions. For PM2.5, the 
appropriate cost threshold for each state was determined to be either 
the level at which nonattainment and maintenance issues were completely 
resolved in downwind states to which the state is linked, the level 
where remaining nonattainment and maintenance issues are primarily 
local, or where we found greatly diminished improvements in air quality 
occurring if EPA moved further up the cost curve. This assessment 
yielded a cost threshold of $2,300/ton on SO2 for Group 1 
states starting in 2014 ($500/ton in 2012), a cost threshold of $500/
ton on SO2 for Group 2 states, and a cost threshold of $500/
ton on annual NOX for all states required to reduce 
emissions for purposes of the annual or 24-hour PM2.5 NAAQS 
in this rule.
    As explained above, none of these specific cost thresholds 
establish any precedent for the cost per ton stringency of reductions 
EPA may require in future transport-related rulemakings; these specific 
cost thresholds are based on current analyses of air quality and cost 
of emission reductions with respect to the NAAQS considered in this 
rulemaking and thus would not be relevant to future rulemakings (which 
would consider updated information) or rulemakings with respect to 
different NAAQS. In particular, EPA acknowledges that additional action 
EPA will require in a subsequent rulemaking to address significant 
contribution to nonattainment and interference with maintenance of the 
2008 ozone NAAQS (once reconsideration is finalized) is very likely to 
require a higher cost per ton stringency of ozone-season NOX 
control applied to a broader set of source categories from upwind 
states than found to be appropriate for this rulemaking.
2. State Emission Budgets (Step 4)
a. Budget Methodology
    EPA used the multi-factor assessment to identify, for each state, 
the cost threshold that should be used to quantify that state's 
significant contribution. As described above, in the context of this 
rulemaking EPA identified a cost threshold of $500/ton for ozone-season 
NOX control for all states required to reduce ozone-season

[[Page 48260]]

NOX emissions for purposes of the 1997 ozone NAAQS in this 
rule. EPA also identified a cost threshold of $500/ton for annual 
NOX control for all states required to reduce annual 
NOX emissions for purposes of the annual or 24-hour 
PM2.5 NAAQS in this rule. Finally, EPA identified a cost 
threshold of $500/ton of SO2 starting in 2012 for all states 
required to reduce SO2 emissions for purposes of the annual 
or 24-hour PM2.5 NAAQS in this rule, and $2,300/ton for the 
Group 1 states starting in 2014.
    EPA used these cost thresholds from the multi-factor analysis to 
quantify each state's emissions that significantly contribute to 
nonattainment or interfere with maintenance downwind. For example, for 
a Group 1 state, EPA modeling of the cost threshold conveys emission 
reductions available in each covered state from operation of existing 
pollution controls as well as all emission reductions available at cost 
thresholds of $500/ton for annual NOX in 2012 and 2014, 
$500/ton for SO2 in 2012, and $2,300/ton for SO2 
in 2014. The total SO2 and NOX projected at these 
cost levels in that state in those years represents that state's 
emissions once significant contribution to nonattainment or 
interference with maintenance downwind for the relevant 
PM2.5 NAAQS has been eliminated.

                        Table VI.D-2--Example of Emission Reductions and Budget Formation in Pennsylvania for Annual SO2 and NOXa
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                          Remaining
                                                                                     Final cost         Base case       emissions at        Emissions
                                                                                      threshold     emissions (1,000   cost thresholds     eliminated
                                                                                                          tons)         (1,000 tons)      (1,000 tons)
--------------------------------------------------------------------------------------------------------------------------------------------------------
A                                               B...............................                 C                 D                 E                 F
--------------------------------------------------------------------------------------------------------------------------------------------------------
2012..........................................  SO2.............................              $500               493               279               215
                                                NOX.............................               500               129               120                 9
2014..........................................  SO2.............................             2,300               507               112               395
                                                NOX.............................               500               132               119                13
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Note: In this table, emissions are shown for fossil-fuel-fired EGUs > 25 MW (i.e., those units likely covered by the Transport Rule). Table VI.D.2
  illustrates how budgets are derived from the elimination of significant contribution for the state of Pennsylvania. Column C illustrates the cost
  thresholds applied in the costing run that was ultimately identified as the final cost threshold in the multi-factor analysis. Column D shows the base
  case emissions for the identified pollutant in the identified time period. Column E shows the emission levels that result when the cost thresholds
  identified in column C are applied. Because this is the cost threshold identified through the multi-factor analysis and the point where all
  significant contribution to nonattainment and interference with maintenance has been addressed for the PM2.5 NAAQS--state budgets are based on these
  emission levels. The final column illustrates the emission reductions for the state in an average year (before accounting for variability).

    EPA's modeling of a state's SO2 and annual 
NOX emission levels (from fossil-fired EGUs > 25 MW) at the 
relevant cost thresholds in each state reflect that state's emissions 
from covered sources after the removal of significant contribution to 
nonattainment and interference with maintenance of the PM2.5 
NAAQS considered in this rulemaking. As these state emission levels 
reflect the removal of significant contribution and interference with 
maintenance, they are reasonable levels on which to determine state 
budgets. Consequently, EPA based state budget levels on the state level 
emissions that remained at the cost threshold. Each state's budget 
corresponds to its emission level following the elimination of 
significant contribution to nonattainment and interference with 
maintenance in an average year (before taking year-to-year variability 
into account, as discussed in section VI.E below). Therefore, the 
implementation and realization of these budgeted emission levels leads 
to the elimination of significant contribution to nonattainment and 
interference with maintenance and EPA meets the statutory mandate of 
section 110(a)(2)(D)(i)(I) with respect to the 1997 annual 
PM2.5 NAAQS and the 2006 24-hour PM2.5 NAAQS.
    EPA's establishment of state budgets for ozone-season 
NOX control follow the same methodology as described above 
for SO2 and annual NOX. Implementation of these 
ozone-season NOX budgets reflects the elimination of 
significant contribution to nonattainment and interference with 
maintenance of the 1997 ozone NAAQS for 15 states, whereas 11 other 
states' ozone-season NOX budgets reflect meaningful progress 
toward (but may not reflect full completion of) this elimination under 
the mandate of section 110(a)(2)(D)(i)(I). See section III for lists of 
states.
    This approach to basing budgets on projected state level emissions 
used in the multi-factor analysis is identical to the approach used in 
the proposal for determining 2014 SO2 budgets for Group 1 
states. EPA is extending this approach more broadly in the final 
Transport Rule to create state budgets for ozone-season NOX, 
annual NOX, and SO2 in all relevant states in 
both 2012 and 2014. In the proposal EPA used a more complex approach 
based on a comparison of historic and projected unit-level emissions 
(further adjusted for operation of existing controls) in each state to 
create 2012 state budgets for ozone-season NOX, annual 
NOX, and Group 2 SO2. At the time of proposal, 
EPA believed that historic 2009 emissions data were in some cases more 
representative of expected emissions in 2012 than pure modeling 
projections made at the time (75 FR 45290).
    However, following the proposal EPA has made significant updates to 
the IPM model for projecting EGU emissions, including specifically the 
adoption of 2009 historic data into its modeling parameters directly. 
EPA also received substantial public input following the proposal on 
the model's assumptions and representation of individual units, which 
allowed EPA to improve its 2012 and 2014 emission projections for 
states under the cost thresholds considered. These modeling updates 
diminish the concerns EPA expressed at proposal that 2009 historic data 
may have offered for some states a better proxy for 2012 emissions than 
model projections, particularly now that EPA is incorporating 2009 data 
directly in its updated modeling projections. Given these updates to 
the model in response to public comment, EPA believes it is more 
appropriate for the final rule to use a consistent approach based on 
projected state level emissions for all state budgets, as was done for 
Group 1 SO2 budgets in 2014 at proposal. EPA received 
significant comment supporting the use of the model to

[[Page 48261]]

project state-level emissions for creating budgets in this manner. EPA 
also received comments that criticized the proposal's methodology for 
2012 budgets for lack of transparency, unnecessary complexity, and 
inconsistency with the state-level emission projections used in the air 
quality modeling. EPA's decision for the final Transport Rule to 
consistently apply across all pollutants the budget methodology 
originally used for Group 1 SO2 budgets in 2014 addresses 
those concerns.
    This budget methodology for the final rule uses projected state-
level emissions in 2012 and 2014 to set emission budgets for those 
years on relevant pollutants for that state to control under the 
Transport Rule. EPA's modeling projects that some states have 2014 
emissions that are lower than their 2012 projected emissions even as 
the same cost threshold (e.g., $500/ton) is applied in both years. This 
occurs in the annual NOX, ozone-season NOX, and 
Group 2 SO2 program. As such, EPA's application of this 
budgeting methodology results in a tightening of budgets in states 
whose projected emissions of that budgeted pollutant decline from 2012 
to 2014 as the cost threshold is held constant.
    There are two primary variables that explain the decrease in 
emissions for some states between 2012 and 2014 as the cost threshold 
remains constant over both time periods. First, even though the cost 
threshold is constant between 2012 and 2014 for the programs noted 
above, the cost threshold for SO2 Group 1 increases in 2014. 
This higher cost threshold for Group 1 SO2 results in 
obvious reductions in SO2 emissions in the Group 1 states, 
but also may lower the cost of certain related NOX 
reductions in those states as well such that they become newly 
available within the $500/ton threshold. For example, if a state 
increases natural gas generation in response to the higher 
SO2 cost threshold, such action also yields additional 
annual and ozone-season NOX emission reductions that are 
cost-effective at the $500/ton NOX threshold. Where the cost 
curve modeling shows such additional cost-effective NOX 
reductions in tandem with SO2 control, EPA is therefore 
reducing those states' 2014 annual NOX and ozone-season 
NOX budgets accordingly, so that those budgets accurately 
reflect remaining emissions from covered sources in those states after 
the elimination of all emissions that can be reduced up to the relevant 
cost thresholds (e.g., $500/ton).
    Second, some of these additional reductions are driven by non-
Transport Rule variables. These are reductions that occur due to state 
rules, consent decrees, and other planned changes in generation 
patterns that occur after 2012, but during or prior to 2014. For 
example, EPA modeling reflects emission reduction requirements under 
provisions of a Georgia state rule that go into effect after 2012 but 
before 2014. These requirements involve the installation and operation 
of specific advanced pollution controls. These source-specific 
requirements under a legal authority unrelated to the Transport Rule 
result in sharp reductions in Georgia's baseline emission projections 
between 2012 and 2014. Even though the cost threshold for 
NOX and for SO2 in Georgia is $500/ton in both 
2012 and 2014, EPA believes it is important to establish separate 
NOX and SO2 budgets that accurately reflect the 
emissions remaining in Georgia (and other states experiencing similar 
reductions) after the elimination of emissions that can be reduced up 
to the Transport Rule remedy's cost thresholds (e.g., $500/ton) (see 
Table VI.D.3). It illustrates a notable decrease between the 2012 and 
2014 state budgets for NOX and SO2 in Georgia 
that is largely driven by state rule requirements. If EPA did not 
adjust 2014 budgets to account for other emission reductions that would 
occur even in the baseline, other sources within the state would be 
allowed to increase their emissions under the unadjusted Transport Rule 
budgets to offset the emission reductions planned under other 
requirements such as state rules. Therefore, to prevent the Transport 
Rule from allowing such offsetting of emission reductions already 
expected to occur between 2012 and 2014, EPA is establishing separate 
budgets for 2012 and 2014 in the final Transport Rule to capture 
emission reductions in each state that would occur for non-Transport 
Rule-related reasons (i.e., in the base case) during that time.
    EPA's modeling also projects that other states would slightly 
increase emissions from 2012 to 2014 even at the same cost threshold, 
such as $500/ton. There are two primary variables that explain the 
increase in emissions for these states between 2012 and 2014. These 
increases are generally small in magnitude. For annual and ozone season 
NOX, they occur as a byproduct of small changes in dispatch 
related to changes in non-Transport Rule factors (e.g., higher demand 
in 2014). For SO2, they primarily occur in Group 2 states 
and, in addition to the reasons given above, are influenced by some 
generation shifting from Group 1 to Group 2 states as the Group 1 
states begin to face a higher cost threshold in 2014. EPA believes that 
allowing for such emission growth in covered states beyond 2012 would 
be inconsistent with the Transport Rule's identification and 
elimination of significant contribution to nonattainment and 
interference with maintenance beginning in 2012. Therefore, for any 
covered state whose emissions of a relevant pollutant are projected to 
increase from 2012 to 2014 under the relevant cost thresholds selected 
in the multi-factor analysis described above, EPA is finalizing that 
state's 2014 emission budget to maintain the same level of the 2012 
emission budget, thereby disallowing such an emission increase that is 
inconsistent with the 110(a)(2)(D)(i)(I) mandate. Tables VI.D-3 and 
VI.D-4 below list state emission budgets.\51\
---------------------------------------------------------------------------

    \51\ These budgets include minor technical corrections to 
SO2 budgets in three states (KY, MI, and NY) that were 
made after the impact analyses for the final rule were conducted. 
EPA conducted sensitivity analysis confirming that these differences 
do not meaningfully alter any of the Agency's findings or 
conclusions based on the projected cost, benefit, and air quality 
impacts presented for the final Transport Rule. The results of this 
sensitivity analysis are presented in Appendix F in the final 
Transport Rule RIA.

                Table VI.D-3--SO2 and Annual NOX State Emission Budgets for Electric Generating Units Before Accounting for Variability *
                                                                         [Tons]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                  SO2                                 NOX
                                                                      Group      -----------------------------------------------------------------------
                                                                                      2012-2013      2014 and beyond      2012-2013      2014 and beyond
--------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama.......................................................                 2           216,033           213,258            72,691            71,962
Georgia.......................................................                 2           158,527            95,231            62,010            40,540

[[Page 48262]]

 
Illinois......................................................                 1           234,889           124,123            47,872            47,872
Indiana.......................................................                 1           285,424           161,111           109,726           108,424
Iowa..........................................................                 1           107,085            75,184            38,335            37,498
Kansas........................................................                 2            41,528            41,528            30,714            25,560
Kentucky......................................................                 1           232,662           106,284            85,086            77,238
Maryland......................................................                 1            30,120            28,203            16,633            16,574
Michigan......................................................                 1           229,303           143,995            60,193            57,812
Minnesota.....................................................                 2            41,981            41,981            29,572            29,572
Missouri......................................................                 1           207,466           165,941            52,374            48,717
Nebraska......................................................                 2            65,052            65,052            26,440            26,440
New Jersey....................................................                 1             5,574             5,574             7,266             7,266
New York......................................................                 1            27,325            18,585            17,543            17,543
North Carolina................................................                 1           136,881            57,620            50,587            41,553
Ohio..........................................................                 1           310,230           137,077            92,703            87,493
Pennsylvania..................................................                 1           278,651           112,021           119,986           119,194
South Carolina................................................                 2            88,620            88,620            32,498            32,498
Tennessee.....................................................                 1           148,150            58,833            35,703            19,337
Texas.........................................................                 2           243,954           243,954           133,595           133,595
Virginia......................................................                 1            70,820            35,057            33,242            33,242
West Virginia.................................................                 1           146,174            75,668            59,472            54,582
Wisconsin.....................................................                 1            79,480            40,126            31,628            30,398
                                                                                 -----------------------------------------------------------------------
    Grand Total...............................................  ................         3,385,929         2,135,026         1,245,869         1,164,910
                                                                                 -----------------------------------------------------------------------
    Group 1 Total.............................................  ................         2,530,234         1,345,402                NA                NA
                                                                                 -----------------------------------------------------------------------
    Group 2 Total.............................................  ................           855,695           789,624                NA                NA
--------------------------------------------------------------------------------------------------------------------------------------------------------
Note: These state emission budgets apply to emissions from electric generating units covered by the Transport Rule Program. Group 1/Group 2 designations
  are only relevant for SO2 emissions budgets.
* The impact of variability on budgets is discussed in section VI.E.

    The District of Columbia is not covered by the final Transport 
Rule. As discussed in section V.D of this preamble and as done for the 
Transport Rule proposal, EPA combined contributions projected in the 
air quality modeling from Maryland and the District of Columbia to 
determine whether those jurisdictions collectively contribute to any 
downwind nonattainment or maintenance receptor in amounts equal to or 
greater than the 1 percent thresholds. This modeling confirmed that the 
combined contributions exceed the air quality threshold at downwind 
receptors for the ozone, annual PM2.5, and 24-hour 
PM2.5 NAAQS considered. Both Maryland and the District of 
Columbia are therefore linked to these receptors.\52\ However, the 
District of Columbia is not included in the Transport Rule because, in 
the second step of EPA's significant contribution analysis, we 
concluded that there are no emission reductions available from EGUs in 
the District of Columbia at the cost thresholds deemed sufficient to 
eliminate significant contribution to nonattainment and interference 
with maintenance of the NAAQS considered at the linked receptors. At 
the time of this rulemaking, EPA finds only one facility with units 
meeting the Transport Rule applicability requirements in the District 
of Columbia. EPA's projections do not show any generation from this 
facility to be economic under any scenario analyzed (including the base 
case), and the facility's owners have also announced plans to retire 
its units in early 2012.\53\ Therefore, this unit is projected to have 
zero emissions in 2012. As such, the total SO2 and 
NOX emissions in the District of Columbia for EGUs that meet 
the Transport Rule applicability requirements is also projected to be 
zero. It follows therefore, that EPA did not identify any emission 
reductions available at any of the cost thresholds considered in the 
final rule's multi-factor analysis to identify significant contribution 
to nonattainment and interference with maintenance. For this reason, 
EPA concludes that no additional limits or reductions are necessary, at 
this time, in the District of Columbia to satisfy the requirements of 
section 110(a)(2)(D)(i)(I) with respect to the 1997 ozone, the 1997 
PM2.5 and the 2006 PM2.5 NAAQS. EPA is therefore 
neither establishing budgets nor finalizing any FIPs for the District 
of Columbia in this rule.
---------------------------------------------------------------------------

    \52\ It is important to note that Maryland's modeled 
contributions in isolation were greater than the 1 percent threshold 
for all three of the NAAQS considered at all of the same receptors 
for which Maryland and DC were ``linked,'' and therefore EPA would 
have considered Maryland ``linked'' to the same set of downwind 
receptors even if the Agency had treated Maryland's contributions 
and the District of Columbia's contributions separately.
    \53\ The future retirement status of this D.C. facility was also 
supported by its inclusion on PJM's future deactivation list. PJM 
further suggested that reliability issues related to their 
retirement are expected to be resolved by next year in time for its 
planned retirement date. (See PJM pending deactivation request in TR 
Docket.)

   Table VI.D-4--Ozone Season NOX State Emission Budgets for Electric
          Generating Units Before Accounting for Variability *
                                 [Tons]
------------------------------------------------------------------------
                                                               2014 and
                                                   2012-2013    beyond
------------------------------------------------------------------------
Alabama.........................................      31,746      31,499
Arkansas........................................      15,037      15,037
Florida.........................................      27,825      27,825
Georgia.........................................      27,944      18,279
Illinois........................................      21,208      21,208

[[Page 48263]]

 
Indiana.........................................      46,876      46,175
Kentucky........................................      36,167      32,674
Louisiana.......................................      13,432      13,432
Maryland........................................       7,179       7,179
Mississippi.....................................      10,160      10,160
New Jersey......................................       3,382       3,382
New York........................................       8,331       8,331
North Carolina..................................      22,168      18,455
Ohio............................................      40,063      37,792
Pennsylvania....................................      52,201      51,912
South Carolina..................................      13,909      13,909
Tennessee.......................................      14,908       8,016
Texas...........................................      63,043      63,043
Virginia........................................      14,452      14,452
West Virginia...................................      25,283      23,291
                                                 -----------------------
    Total.......................................     495,314     466,051
------------------------------------------------------------------------
Note: These state emission budgets apply to emissions from electric
  generating units covered by the Transport Rule Program. Group 1/Group
  2 designations are only relevant for SO2 emissions budgets.
* The impact of variability on budgets is discussed in section VI.E.

    EPA notes that the NOX budgets for five states linked to 
downwind ozone receptors in the final Transport Rule are equal to their 
projected 2012 base case emissions. The five states are Arkansas, 
Indiana, Louisiana, Maryland, and Mississippi. These states are among 
those found to meet or exceed the 1 percent contribution threshold for 
the 1997 ozone NAAQS at downwind receptors and are thus ``linked'' to 
downwind receptors. EPA therefore evaluates, in the second step of its 
significant contribution analysis, what emission limits are necessary 
to ensure that all emissions that constitute the state's significant 
contribution to nonattainment and interference with maintenance are 
prohibited. As explained above, EPA decided to require from all such 
states all reductions available at the $500/ton cost threshold. The 
five states identified above do not appear to show EGU ozone-season 
NOX reductions at the $500/ton cost threshold relative to 
the 2012 base case projections (which do not take into account 
reductions to be made in other states as a result of this rule). 
Therefore, EPA conducted further analysis to evaluate whether such 
reductions were available in these states and whether emission limits 
are necessary to prohibit these states from significantly contributing 
to downwind nonattainment or interfering with maintenance of the 1997 
ozone NAAQS in other states. (See the docket to this rulemaking for the 
IPM run titled TR--uncontrolled--ozone--states--Final.'')
    Specifically, EPA projected those states' ozone-season 
NOX emissions if all other linked states (but not these five 
states) were to make all available reductions at the $500/ton 
threshold. That analysis revealed that if emission limits were not 
established for these five states, ozone-season NOX 
emissions in each of the states would increase (beyond the 2012 base 
case emission projections), due to interstate shifts in electricity 
generation that cause ``emissions leakage'' in uncovered states. These 
increases would result in each state's emissions being above the level 
associated with the prohibition of all emissions that can be eliminated 
at the $500/ton threshold. EPA thus determined that it is necessary to 
establish emission limits for these states at the $500/ton level. These 
limits, although equal to the state's 2012 projected base case 
emissions, are necessary to prohibit all emissions that can be 
controlled at the $500/ton cost threshold. In other words, the 
significant contribution to nonattainment and interference with 
maintenance addressed by the ozone FIPs for these states is the 
difference between these states' projected emissions if they were not 
covered under the Transport Rule (but other states were), and their 
emissions after all emissions that can be eliminated at $500/ton are 
prohibited.
    In addition, EPA notes that four of these five states (Arkansas, 
Indiana, Louisiana, and Mississippi) are linked to receptors in either 
the Houston or Baton Rouge areas, which are projected to continue 
facing nonattainment or maintenance concerns with the 1997 ozone NAAQS, 
respectively. To allow these states to increase emissions above base 
case projections would erode the measurable progress toward eliminating 
significant contribution to nonattainment and interference with 
maintenance secured by achieving ozone-season NOX reductions 
in the other states linked to these receptors. Furthermore, as 
discussed in section III, EPA may require additional reductions in 
these states to fully address significant contribution to nonattainment 
and interference with maintenance with respect to the 1997 ozone NAAQS 
in a future rulemaking to be proposed after finalizing reconsideration 
of the 2008 ozone NAAQS.
b. Relationship of Group 1 and Group 2 States for SO2 
Control
    In the Proposal, EPA chose not to allow sources in Group 1 states 
to use Group 2 SO2 allowances for compliance, and likewise 
not to allow sources in Group 2 states to use Group 1 SO2 
allowances for compliance at any time. The preamble clearly states, 
``With regard to interstate trading, the two SO2 stringency 
tiers would lead to two exclusive SO2 trading groups. That 
is, states in SO2 Group 1 could not trade with states in 
SO2 Group 2'' (75 FR 45216). No such distinction or 
limitation exists for NOX allowance trading.
    EPA received significant public comment both in support and 
opposition to the two distinct SO2 trading programs. Those 
in opposition noted that the variability limits imposed at the state 
level made the compliance restrictions between the two groups 
unnecessary. Commenters also noted that it may unfairly penalize 
sources that are part of the same airshed, but are on opposite sides of 
a state boundary. Those in favor of the separate SO2 
compliance programs noted that it would reduce the probability of a 
state exceeding its variability limit. Allowing the use of Group 1 or 
Group 2 allowances for compliance between the two SO2 
programs would potentially encourage Group 1 states to purchase 
allowances instead of making reductions necessary to eliminate 
significant contribution. Group 1 states are states that need continued 
reductions (beyond the $500/ton threshold) to eliminate their 
significant contribution to nonattainment and interference with 
maintenance. Group 2 states have already eliminated their significant 
contribution to nonattainment and interference with maintenance at the 
$500/threshold. So to allow Group 1 or Group 2 allowances to be used 
interchangeably for compliance between the two SO2 groups 
would be to allow the shifting of reductions from areas where they are 
needed to eliminate significant contribution to nonattainment and 
interference with maintenance to areas where they are not needed to 
eliminate the prohibited emissions. EPA also agrees that allowing for 
trading between the two groups in the remedy finalized in this action 
would increase risk of a state exceeding its variability limit. For 
these reasons, EPA is finalizing this rulemaking with the same 
prohibition on SO2 trading between Group 1 and Group 2 
states that was defined in the proposal. Further, EPA clarifies that 
while trading of allowances (i.e.,

[[Page 48264]]

buying, selling, and banking) is allowed without restriction, it is 
specifically the surrender of SO2 allowances for compliance 
that is limited. As mentioned earlier, a source in a Group 1 state can 
only use SO2 allowances allocated to Group 1 states for 
compliance with the SO2 trading program. Likewise, a source 
in a Group 2 state can only use SO2 allowances allocated to 
Group 2 states for compliance with the SO2 trading program.
c. Ozone-Season Budgets
    EPA established the ozone-season NOX budgets in a 
similar manner to the annual NOX and SO2 budgets 
by using the state level emissions from the cost threshold that 
reflected the removal of significant contribution to nonattainment and 
interference with maintenance. Ozone-season budgets were based on the 
state level emissions from fossil-fuel-fired units greater than 25 MW 
observed at this cost threshold. As described in section VI.B, all cost 
thresholds examined reflected the final Transport Rule geography and 
the marginal costs were applied accordingly. Therefore, for an ozone-
only state like Florida, the state level emissions would only reflect 
an ozone-season cost threshold of $500/ton in the final cost curves for 
2012 and 2014. For a state subject to both annual and ozone-season 
programs, the marginal cost curves would reflect a $500/ton 
NOX cost year round, a $500/ton SO2 cost in 2012 
and the $2,300/ton SO2 cost starting in 2014 if a Group 1 
state.
(1) Length of Ozone Season
    (a) Proposed Rule. For purposes of determining ozone-season budgets 
in the proposed rule, EPA defined the ozone season based on a 5 month 
period (May 1 through September 30). This 5 month ozone season was 
consistent with the approach taken by the OTAG, the NOX SIP 
Call, and CAIR. EPA requested comment on whether EPA should base final 
rule budgets on a longer season, such as March through October.
    (b) Public Comments. Several commenters supported continuing with 
the May through September time period. One commenter supported 
continuing with this time period, but argued that EPA should consider 
lengthening the ozone season for future efforts. One commenter 
questioned the concept of ozone season budgets and recommended EPA 
focus on sources with greater emissions on high ozone days.
    (c) Final rule. For the final rule, EPA has retained the approach 
in the proposed rule, as commenters broadly supported the proposal's 
ozone-season duration and ozone-season NOX limitations. 
Notably, many Transport Rule states covered for PM2.5 
reductions will have sources with annual NOX controls that 
are likely to keep operating year round to address PM2.5 and 
ozone. EPA believes that experience from ozone-season NOX 
trading has consistently shown that the emission measures taken to 
comply with ozone-season budgets provide emission reductions throughout 
the ozone-season, including the highest ozone days. (See NOX 
Budget Trading Program and CAIR Program progress reports in the docket 
to this rulemaking or at http://www.epa.gov/airmarkets/progress/nbp08.html and http://www.epa.gov/airmarkets/progress/CAIR_09/CAIR09.html.) However, EPA believes that there is merit in future 
Agency actions addressing ozone transport in considering strategies to 
target high ozone days more specifically.
d. Summary of Cost Thresholds and Final Budgets for PM2.5 
and Ozone
    Summary of methodology. In summary, EPA determined that 
SO2 emissions that could be reduced for $2,300/ton in 2014 
should be considered a state's significant contribution to 
nonattainment and interference with maintenance, unless EPA determined 
that a lesser reduction would fully resolve the nonattainment and/or 
maintenance problem for all the downwind receptors to which a 
particular state might be linked. For these Group 2 states EPA is 
determining that a lesser reduction of SO2, based on the 
amount of SO2 reductions that can be reasonably achieved by 
2012 is appropriate. This level is defined by the reductions observed 
in the $500/ton cost threshold. EPA also determined that all states 
linked to downwind PM2.5 nonattainment and maintenance 
problems should be required to achieve those emission reductions that 
can be reasonably achieved by 2012. Finally, EPA determined that all 
states linked to downwind PM2.5 nonattainment and 
maintenance problems should, by 2012, remove all NOX 
emissions that can be reduced for $500/ton and run all existing 
controls in 2012.
    For ozone-season NOX, EPA determined that all states 
linked to downwind ozone and nonattainment and maintenance problems 
should be required to achieve those ozone-season emission reductions 
associated with a cost threshold of $500 per ton. Additionally, EPA 
examined final 2012 and 2014 budgets based on state level emissions at 
$500 cost threshold.
    The budget formation methodology finalized in this action responds 
to concerns about state budgets expressed by commenters on the 
Transport Rule proposal. EPA requested comment on the four step 
approach used to determine significant contribution and determine 
budgets in the proposal. Some commenters noted that the state level 
emissions from the cost thresholds used to determine significant 
contribution to nonattainment and interference with maintenance did not 
match the state level emissions allowed by the final budgets. The 
concern was that the state level emissions that reflected the 
elimination of significant contribution in the AQAT analysis, in 
particular for NOX, were less than the emissions allowed by 
the final budgets. The result would be an implementation that did not 
quite fully eliminate the significant contribution to nonattainment and 
interference with maintenance defined in the rule. The proposed budgets 
not matching the levels reflected in the proposed costing runs were an 
artifact of the budget formation process that relied on a combination 
of historic and projected data. While EPA noted this process resulted 
in state budgets that ``reflected'' EGU emissions at $500/ton, it was 
not always consistent with the EGU emissions at $500/ton in the costing 
runs as the commenters noted. By using the cost curves to determine 
both significant contribution to nonattainment and interference with 
maintenance--and state budgets--in the final rule, EPA addresses the 
commenter's concerns about any inconsistency between the two in the 
proposal.
    Some commenters expressed concern that the Transport Rule would 
result in state budgets that were in some cases higher than those 
established in CAIR. Commenters suggested that this would be 
inconsistent with requirements or the spirit of certain CAA provisions 
aimed at preventing backsliding, i.e., sections 110(l), 172(e), and 
193. However, the DC Court of Appeals rejected the state budgets in 
CAIR as arbitrary and capricious and not consistent with CAA section 
110(a)(2)(D)(i)(I) (North Carolina, 531 F.3d 918 and 921) and remanded 
CAIR to EPA to promulgate a new rule replacing CAIR and consistent with 
the Court's decision (North Carolina, 550 F.3d 1178). As discussed 
elsewhere in this section, on remand EPA developed new, final state 
budgets that address the Court's concerns and meet section 
110(a)(2)(D)(i)(I) requirements.
    Although some state budgets under the final rule are higher than 
those

[[Page 48265]]

under CAIR, this does not violate either the letter or the spirit of 
CAA provisions aimed at backsliding. In particular, CAA section 110(l) 
provides that the Administrator may not approve a plan revision that 
would ``interfere with any * * * applicable requirement'' of the CAA. 
42 U.S.C. 7410(l). Because the Court reversed and remanded CAIR with 
instructions to ``remedy'' the rule's ``fundamental flaws'' (including 
specifically the state budgets found to be unlawful (North Carolina, 
550 F.3d 1178), it is difficult to see how new state budgets replacing 
unlawful budgets and meeting section 110(a)(2)(D)(i)(I) requirements 
could be viewed as interfering with requirements of the CAA. Indeed, 
the commenters' approach would severely limit EPA's ability to meet the 
Court's mandate to develop a new rule consistent with section 
110(a)(2)(D)(i)(I). See North Carolina, 531 F.3d 921 (explaining that 
EPA may not require ``some states to exceed the mark'' of eliminating 
their significant contribution). Further, the other CAA sections cited 
by the commenters (section 172(e), addressing circumstances where the 
Administrator relaxes a NAAQS, and section 193, addressing the 
treatment of requirements promulgated before the November 15, 1990, 
enactment date for the 1990 Amendments to the Clean Air Act) are not 
applicable here.
    Additionally, while the CAIR budgets may have been tighter than 
Transport Rule state budgets for a couple of states, the sum of state 
budgets that were subject to both CAIR and the Transport Rule is lower 
under the Transport Rule for the annual programs. Moreover, the 
carryover of the large Title IV allowance bank in CAIR allowed for a 
great deal more emissions within any given state than is permitted 
under the Transport Rule.

E. Approach to Power Sector Emission Variability

1. Introduction to Power Sector Variability
    Variability is an inherent aspect of the production and delivery of 
electricity. It follows that variations in state emissions are not only 
a result of variations in the level of emission control, but also are 
caused by the inherent variability in power generation. The state 
budgets do not account for this latter source of variability at the 
state level. Emission variability is built into the design of power 
systems, which use a wide mix of power generation sources with varying 
use and emission patterns to ensure reliability in electric power 
generation. Variations in weather, demand due to changes in the level 
of economic activity, the portion of electric generation that is 
fossil-fuel-fired, the length and number of outages at power generation 
units, and other factors, can lead to significant variations in the 
load levels of different power generation sources. Variations in the 
load levels of sources in any given state cause variations in the level 
of emissions in that state. Thus, EPA believes it is appropriate, in 
this rule, to take into account the variations that are caused by 
inherent variability in power generation. More specifically, variations 
in these external variables can cause significant fluctuations in state 
emissions, even when action has been taken to prohibit all emissions 
within a state that significantly contribute to nonattainment or 
interfere with maintenance in another state. For this reason, EPA 
considers variability when determining the state specific requirements 
in this rule. EPA does so by developing variability limits and 
assurance levels for each state, as described in this section, that are 
consistent with the statutory mandate of CAA section 
110(a)(2)(D)(i)(I).
    Loads on a power system, and thus on power generation sources in a 
given state that are on the power system, vary over every time 
interval, changing not only in the short term and seasonally, but also 
annually. As noted above, load patterns and levels are determined by a 
multiplicity of factors, including weather, economic activity, the 
portion of electric generation that is fossil-fuel-fired, and the 
length and number of outages at power generation units, which vary over 
time. In particular, weather obviously varies not just from season-to-
season but also from year-to-year, and even small changes in annual 
weather patterns can affect how the power system and power generation 
sources on the power system operate during a year. For example, load, 
and the resulting use of generation sources on an interconnected grid 
to meet load, depend not only on how hot a summer day is, but also on 
where a heat wave occurs and how long it lasts. Similarly, a relatively 
cold winter that drives up winter load may also change what generation 
sources are used to address the increased demand for heat. Thus, the 
pattern of generation may shift geographically as a weather pattern 
moves across the country. Because weather and other factors affecting 
loads, and the patterns of generation used to meet loads, vary over 
time and from state to state, the resulting level of emissions also 
varies over time and from state to state.
    This variability in emissions is not a result of variation in 
emission rates, emission controls, or emission control strategies, but 
instead is a result of the inherent variability in power generation. 
Patterns of generation change to ensure demand for electricity is met 
and to ensure continued reliability of the power system. This results 
in temporal and geographic fluctuations in emissions. In the final 
Transport Rule, like the proposed rule, EPA explicitly takes account of 
these changing patterns of generation and the resultant variability in 
power sector emissions.
    As discussed previously, EPA identified a specific amount of 
emissions that must be prohibited by each state to meet the 
requirements of CAA section 110(a)(2)(D)(i)(I). EPA also developed 
state baseline emissions for power generation sources based on 
projections of state emissions in an average year before the 
elimination of prohibited emissions, and state budgets for power 
generation sources based on projections of state emissions in an 
average year after the elimination of such emissions. However, because 
of the inherent variability in state-level baseline emissions--
resulting from the inherent variability in loads and power system and 
power generation source operations--state-level emissions will 
fluctuate from year-to-year even after all significant contribution to 
nonattainment and interference with maintenance that EPA identified in 
this final rule are eliminated. In an above average year, emissions may 
exceed the state budgets which are based on an analysis of projected 
emissions in an average year. EPA believes that, because baseline 
emissions are variable for reasons unrelated to the degree of emission 
control in a state and emissions after the elimination of all 
significant contribution to nonattainment and interference with 
maintenance are therefore also variable, it is appropriate to take this 
variability into account in developing the remedy for meeting the 
requirements of CAA section 110(a)(2)(D)(i)(I). The variability limits 
and assurance levels in the final rule account for this inherent 
variability, while ensuring that emissions within each state that 
significantly contribute to nonattainment or interfere with maintenance 
in another state are prohibited. EPA believes this approach is both 
reasonable in that it reflects the operation of the power system 
generation in order to maintain electric reliability and consistent 
with the statutory mandate of CAA section 110(a)(2)(D)(i)(I). For these 
reasons, EPA

[[Page 48266]]

is finalizing variability limits for each state budget to identify the 
range of emissions that EPA believes is likely to occur in each state 
following the elimination of all the state's significant contribution 
to nonattainment and interference with maintenance.
    As discussed above, the air quality-assured trading remedy's state-
specific budgets represent each state's emissions in an average year 
after elimination of significant contribution to nonattainment and 
interference with maintenance. Because actual base case emissions are 
likely to vary from projected base case emissions, this remedy 
incorporates provisions that account for such variability. While the 
primary purpose of this remedy is to eliminate significant contribution 
and interference with maintenance, EPA believes variability limits also 
satisfy several other objectives. The remedy provides the flexibility 
to deal with real-world variability in the operation of the power 
system through air quality-assured trading and reduces costs of 
compliance with emission reduction requirements, while still providing 
assurance for downwind states that significant contribution to 
nonattainment and interference with maintenance by upwind states will 
be eliminated. EPA believes the limited fluctuation in state level 
emissions that this approach permits is consistent with the statutory 
mandate of section 110(a)(2)(D)(i)(I) because some geographic and 
temporal shifting of emissions necessarily results from the inherent 
variability in power generation and is caused by factors unrelated to 
the degree of emission control, such as weather, economic activity, and 
unit availability. Far from excusing any state from addressing 
emissions within the state that significantly contribute to 
nonattainment or interfere with maintenance in other states, these 
variability limits ensure that the system can accommodate the inherent 
variability in the power sector while ensuring that each state 
eliminates the amount of emissions within the state, in a given year, 
that must be eliminated to meet the statutory mandate of section 
110(a)(2)(D)(i)(I).
    Moreover, the structure of the program, which achieves the required 
emission reductions through limits on the total number of allowances 
allocated, assurance provisions, and penalty mechanisms, ensures that 
the variability limits only allow the amount of temporal and geographic 
shifting of emissions that is likely to result from the inherent 
variability in power generation, and not from decisions to avoid or 
delay the installation of necessary controls. Under the remedy, an 
individual state can have emissions up to its budget plus the 
variability limit. However, the requirement that all sources hold 
allowances covering emissions, and the fact that those allowances are 
allocated based on state-specific budgets without variability, ensure 
that the total emissions from the states do not exceed the sum of the 
state budgets. The remedy, therefore, ensures both that total emissions 
do not exceed the total of the state budgets and that the required 
emission reductions occur in each state.
    This section describes how EPA calculated variability limits for 
each state to achieve this goal.
2. Transport Rule Variability Limits
    EPA performed analyses using historical data to demonstrate that 
there is year-to-year variability in base case emissions (even when 
emission rates for all units are held constant) and to quantify the 
magnitude of this variability.
    The focus of the analysis is on quantifying the magnitude of the 
inherent year-to-year variability in state-level EGU emissions 
independent of measures taken to control those emissions (and thus due 
only to changes in electricity generation within each state). EPA used 
this analysis to set variability limits as part of the remedy to ensure 
that states are eliminating their significant contribution to 
nonattainment and interference with maintenance to protect air quality.
    As discussed in detail below, EPA is finalizing the Transport Rule 
with 1-year variability limits calculated using a modified approach 
from the one described in the proposal. EPA is not including the 
proposal's 3-year variability limits in the final Transport Rule. EPA 
received comments that the 3-year variability limits increased program 
costs and diminished compliance flexibility without delivering any 
additional air quality benefits. EGU owners and operators expressed 
concern that 3-year variability limits would be impracticable to 
implement and that the 1-year variability limits themselves would be 
adequately stringent to ensure elimination of significant contribution 
to nonattainment and interference with maintenance in each state.
    After further consideration, EPA has concluded that 3-year 
variability limits would be unnecessary, would be difficult to 
anticipate, and would not have a measurable impact on air quality 
benefits. EPA has determined that annual limits are sufficient to 
eliminate significant contribution to nonattainment and interference 
with maintenance in all upwind states while accommodating the 
historically observed year-to-year fluctuation in state-level EGU 
emissions even at the same rate of emissions control in a given state.
    In the proposal, EPA used statistical methods to derive the 3-year 
variability limit directly from the 1-year variability limit, meaning 
that the two are statistically equivalent in the long run under certain 
statistical assumptions. Primarily, these assumptions were that the 
variation in electric demand around the budget is random from year-to-
year and that, when the annual emissions are averaged over a multi-year 
time period, the average emissions per year will equal the state's 
budget. The first assumption was also made in the assessment of the 
historical year-to-year variation in heat input in developing the 1-
year limit (see section 2 of the ``Power Sector Variability Final Rule 
TSD'' for more details). Regarding the second assumption, since the 
state-by-state emission budgets are based on the availability of 
emission reductions at an equal marginal cost level, EPA expects the 
sources in each of the upwind states to make these cost-effective 
reductions and to meet the emission budgets each year, on average.
    Since the 3-year variability limit was based on average year-to-
year variability over a longer time horizon, EPA notes that a random 
ordering of those years could yield 2 above-average years in a row. If, 
by chance, a third above-average year were to follow, the state could 
face violation of the 3-year limit, even if over a time period longer 
than 3 years, that state would never have exceeded the statistically-
equivalent 1-year variability limit and its annual emissions would have 
averaged to the level of its budget. Effectively, this means that 
imposing a multi-year variability limit would erode the 1-year 
variability limit's ability to accommodate historically observed year-
to-year variability in state-level EGU emissions (due only to 
generation changes), and it would do so without providing any 
additional air quality benefits or protection for downwind areas (since 
the average emissions over the long time horizon equal the level of the 
budget).
    For more details about the relationship between the 1- and 3-year 
limits, see the discussions in section 3 of the ``Power Sector 
Variability'' TSD from the proposed Transport Rule, which describes the 
derivation of the 3-year limit from the 1-year variability and section 
3 of the ``Power Sector Variability Final Rule TSD'', which describes 
the results of a numerical

[[Page 48267]]

simulation showing that the 1- and 3-year limits are statistically 
indistinguishable and, thus, redundant over the course of the program 
to accommodate year-to-year variability.
    While EPA expects the yearly emissions in each state, on average, 
to equal the level of the budgets, EPA also estimated the air quality 
impacts of 5, 10, 15, and 20 percent emission variability using the air 
quality assessment tool, which is presented in section 4 of the ``Power 
Sector Variability Final Rule TSD.'' That analysis shows that year-to-
year fluctuations of up to 20 percent in SO2 emissions from 
upwind states linked to a given downwind receptor do not undermine the 
ability of the Transport Rule programs to resolve nonattainment or 
maintenance concerns at that receptor. The analysis presented in the 
TSD focuses on SO2 emissions and was designed to examine the 
sensitivity of downwind air quality to upwind EGU emission levels. The 
share of total SO2 emitted by EGUs is significantly larger 
than the share of total NOX emitted by EGUs. For example, in 
the states for which EPA modeled base case contributions of these 
pollutants, EGUs accounted for 74 percent of total SO2, 14 
percent of total annual NOX, and 15 percent of total ozone-
season NOX emissions. Therefore, when varying EGU emissions 
only, downwind air quality would be most sensitive to upwind variations 
in SO2, because relative variations in EGU SO2 
emissions have a greater impact on total SO2 emissions than 
the same relative variation in EGU NOX emissions would have 
on total NOX emissions affecting downwind air quality. 
Because the Transport Rule only affects upwind emissions from EGU 
sources, downwind air quality would be more sensitive to variability in 
upwind state SO2 emissions under this rule than variability 
in upwind state NOX emissions under this rule (given that 
the rule affects a smaller scope of total NOX emissions 
compared to the scope affected of total SO2 emissions). 
Thus, EPA chose to analyze the ``worst-case'' potential downwind air 
quality impacts from year-to-year variability above upwind state 
SO2 budgets, and EPA therefore believes that its findings 
from this analysis are valid for ascertaining the potential downwind 
air quality impacts from variation at those levels in both 
SO2 and NOX under the Transport Rule programs.
    Furthermore, because the state budgets are based directly on IPM 
modeling of electric generation when cost-effective emission reductions 
have been achieved, sources within each state should have the same 
incentive to meet that budget, on average, in any given year. 
Additional EPA analysis supports the claim that states would be no more 
likely to exceed 1-year variability limits without the 3-year limits 
than with the 3-year limits. See the ``Power Sector Variability Final 
Rule TSD'' for more details on this statistical analysis. Finally, 
because the state budgets (and thus the total amount of allowances 
available) are fixed and every covered source must hold allowances 
covering its emissions, it is not feasible for all, or even many, 
states to repeatedly exceed their budgets.
    The approach calculated the standard deviation in state-level heat 
input from units expected to be covered by the final Transport Rule 
over an 11-year time period (2000 through 2010), from which the 95th 
percent confidence level was calculated. EPA divided this value by the 
mean to get the percentage variation in heat input. The two-tailed 95th 
percent confidence level is the equivalent of the 97.5 percent upper 
(single-tailed) confidence level. This approach yielded an average 
year-to-year heat input variability for each state, as a proxy for 
historic year-to-year variability in state-level EGU emissions while 
holding emission rates constant. The result, expressed as a percentage, 
conveys the maximum degree to which EGU emissions at the state level 
may be expected with 95th percent confidence to vary around a given 
target (i.e., budget) from year-to-year, on average, based on the 
statistical analysis of historic heat input over the 2000 through 2010 
time period.
    From the state-by-state variability calculations, EPA identified a 
single variability level (percentage) for each of the annual and ozone-
season programs based on the historic variability measured at units in 
covered states on an annual basis and an ozone-season basis, 
respectively. In the proposal, EPA ``identified a single set of 
variability levels * * * to apply to all states in order to make the 
application of the variability limits straightforward rather than 
developing state-by-state percentage variability values'' (75 FR 
45293). In the final rule, EPA is taking the straightforward approach 
of identifying a single set of variability levels to apply to all 
states because EPA has determined that it is reasonable to afford all 
states under the Transport Rule programs the extent of measured 
historic variability experienced by any Transport Rule state during 
2000 through 2010. In the variability analysis for the final rule, EPA 
identified Tennessee as having the highest measured historic 
variability of annual heat input of 18 percent, and Virginia as having 
the highest measured historic variability of ozone-season heat input of 
21 percent. Because the percentage of variability in Tennessee on an 
annual basis and in Virginia on an ozone-season basis are reasonably 
likely to occur in each of the other states in the future, EPA believes 
it is appropriate to apply an 18 percent annual variability limit to 
all states covered by the annual SO2 and NOX 
programs and a 21 percent ozone-season variability limit to all states 
covered by the ozone-season NOX program.\54\
---------------------------------------------------------------------------

    \54\ The six states in the supplemental proposal for inclusion 
in the Transport Rule's ozone-season NOX program have 
measured historic ozone-season variability that would be adequately 
covered by this final rule's ozone-season NOX variability 
level (21 percent). Please see the ``Power Sector Variability Final 
Rule TSD'' for more details.
---------------------------------------------------------------------------

    EPA's analysis of historic heat input variability in multiple 
states over the 2000 to 2010 baseline yields a range of potential year-
to-year variability values for state-level EGU emissions. As discussed 
above, any one state's measured variability (in this case, from 2000 to 
2010) is due to a multiplicity of factors. These factors include, but 
are not limited to, variation in weather, variation in demand due to 
increased or decreased level of economic activity, variation in the 
portion of electric generation that is fossil-fuel-fired, and variation 
in the length and number of outages at power generation units, and 
these individual factors may sometimes act in concert and may other 
times be offsetting.
    The mix and levels of factors present in a state from year-to-year 
can lead to variation of state-level emissions above and below the 
level for the state under average conditions. Because the levels of the 
various factors are difficult to predict on a year-to-year basis for an 
individual state, the resulting variability in state-level emissions is 
difficult to predict. Moreover, because the electric generation, 
transmission, and distribution system in the eastern half of the U.S. 
is highly integrated, year-to-year variation in these factors in one 
state can cause year-to-year variability in state-level emissions both 
in that state and in other states on the system. For example, increased 
demand due to extreme weather or increased economic activity in one 
state can be met through increased generation and emissions in a number 
of states.
    Because these factors can vary year-to-year in every state in ways 
that are difficult to predict and can affect other states, EPA 
maintains that the maximum variability measured in one state for a 
discrete period (2000-2010) is

[[Page 48268]]

reasonably likely to occur in the future in any of the states in the 
region. Consequently, EPA believes that it is reasonable to use the 
maximum historic percentage variability figure as a proxy for the 
percentage variability that any of the states is likely to experience 
in the future. Although EPA is therefore using a uniform percentage 
figure for variability, EPA applies that percentage figure to each 
state-specific budget so that variability in tons of emissions is 
determined on a state-specific basis. That state-specific number is 
used in determining whether the assurance provisions and penalty are 
triggered in the specific state. EPA also believes that it is 
appropriate to accommodate this potential future variability at the 
state level if and only if it can be accommodated without undermining 
the programs' beneficial impacts on downwind air quality that eliminate 
significant contribution to nonattainment or interference with 
maintenance of the NAAQS assessed in this rulemaking (see the ``Power 
Sector Variability Final Rule TSD'' for more information on this 
analysis). The Transport Rule identifies and quantifies, on a state-by-
state basis, the emissions in each state that significantly contribute 
to nonattainment or interfere with maintenance in another state. This 
is done by analyzing specific air pollution linkages between each 
upwind state and each downwind maintenance or nonattainment receptor. 
Nonetheless, it is clear from the air quality analyses that the air 
quality outcome at a given downwind receptor is a function of the 
cumulative emissions from all upwind states and the receptor's home 
state. Once the Transport Rule emission reduction requirements are 
implemented in all states subject to the programs, EPA's analysis shows 
that the impact on a downwind receptor of any single upwind state's 
year-to-year fluctuation of up to 20 percent in SO2 
emissions would be so limited as to not disturb that receptor's ability 
to maintain or attain the NAAQS analyzed in this rulemaking. Therefore, 
to the extent that such variability has been measured in historic data 
in any state subject to the Transport Rule programs, it is reasonable 
to provide for potential future variability in Transport Rule states 
within the scope of what EPA's analysis shows to preserve downwind air 
quality gains achieved by the Transport Rule programs.
    The approach to establishing variability limits in the final rule 
modifies the approach from the proposed rule in two ways. First, EPA is 
applying only a percentage variability limit to each budget in the 
final rule, whereas the proposed rule applied the greater of a 
percentage or an absolute tonnage variability limit to each budget. EPA 
explained in the proposal that it was necessary to impose both a 
percentage and a tonnage limit due to the inclusion of ``states with 
small numbers of units where expected variability would be more 
pronounced in percentage terms'' (75 FR 45293). However, the states 
with the smallest numbers of units included at proposal (such as 
Connecticut and the District of Columbia) are not covered by any of the 
final Transport Rule's programs. In the final rule's variability 
analysis, Tennessee has the highest measured annual variability 
percentage and Virginia has the highest measured ozone-season 
variability percentage. Both of these states have a sufficient number 
of units for the percentage variability findings to be representative 
of variability in all of the Transport Rule states; therefore, it is 
not necessary to impose a tonnage limitation in the final rule.
    Second, EPA has expanded the historic baseline of the variability 
analysis to consider heat input data from 2000 through 2010, as 
compared to 2002 through 2008 at proposal, and EPA has also expanded 
the dataset to include all units expected to be covered by the final 
Transport Rule's programs. EPA received a number of comments that the 
proposal's variability limits were too stringent in part because they 
relied on too short a historical baseline that failed to capture the 
full extent of long-run year-to-year variability. EPA agrees with these 
comments and believes that the historic baseline modification described 
above supports variability limits in the final rule that are a better 
approximation of future potential year-to-year variability in state-
level EGU emissions around the budgets as a function of inherent 
variability in baseline state-level EGU operations. EPA believes the 
2000 through 2010 historic baseline supports a more accurate 
approximation of year-to-year variability in state-level EGU operations 
than previously measured on a 2002 through 2008 baseline.
    Some commenters expressed the view that allowing variability limits 
in addition to state budgets undermines the requirements of CAA section 
110(a)(2)(D)(i)(I) to eliminate significant contribution to 
nonattainment and interference with maintenance of the NAAQS in 
downwind states. EPA disagrees with these comments. As explained above, 
EPA finds that year-to-year variability is an inherent characteristic 
of power sector emissions whether or not such emissions are controlled 
by state budgets; the future year-to-year variability is a component of 
the sector's emissions baseline before emission reductions are 
required. As done for proposal, EPA has analyzed the impact of allowing 
emissions from upwind states in a given year to rise above the budgets 
but within the variability limits allowed in the final rule. This 
analysis shows that emission fluctuations around the budgets but within 
the variability limits will not undermine the downwind air quality 
gains achieved by the implementation of the Transport Rule budgets, and 
therefore the variability limits cannot be said to undermine the 
elimination of significant contribution to nonattainment or 
interference with maintenance achieved under the Transport Rule 
programs. Based on historical data and projected air quality impacts, 
the Agency believes that states will have sufficient flexibility and 
room to operate within the final rule's variability limits while 
addressing all emissions identified as significantly contributing to 
nonattainment or interfering with maintenance in other states.

F. Variability Limits and State Emission Budgets: State Assurance 
Levels

    As explained above, EPA applied the variability levels on a state-
by-state basis to calculate specific emission budgets with variability 
limits. The state budget plus the variability limit is also called the 
``state assurance level.'' Table VI.F-1 shows final state budgets, 
variability limits, and assurance levels by state for SO2 
emissions. Table VI.F-2 shows final state budgets, variability limits, 
and assurance levels by state for annual NOX emissions. 
Table VI.F-3 shows final state budgets, variability limits, and 
assurance levels by state for ozone-season NOX emissions.

[[Page 48269]]

                                 Table VI.F-1--State Budgets, Variability Limits, and Assurance Levels for SO2 Emissions
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                              Emission budget  (tons)       Emission variability  limit     State emissions  assurance
                                                         --------------------------------             (tons)                       level (tons)
                                                                                         ---------------------------------------------------------------
                                                             2012-2013       2014 and                        2014 and                        2014 and
                                                                              beyond         2012-2013        beyond         2012-2013        beyond
--------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama.................................................         216,033         213,258          38,886          38,386         254,919         251,644
Georgia.................................................         158,527          95,231          28,535          17,142         187,062         112,373
Illinois................................................         234,889         124,123          42,280          22,342         277,169         146,465
Indiana.................................................         285,424         161,111          51,376          29,000         336,800         190,111
Iowa....................................................         107,085          75,184          19,275          13,533         126,360          88,717
Kansas..................................................          41,528          41,528           7,475           7,475          49,003          49,003
Kentucky................................................         232,662         106,284          41,879          19,131         274,541         125,415
Maryland................................................          30,120          28,203           5,422           5,077          35,542          33,280
Michigan................................................         229,303         143,995          41,275          25,919         270,578         169,914
Minnesota...............................................          41,981          41,981           7,557           7,557          49,538          49,538
Missouri................................................         207,466         165,941          37,344          29,869         244,810         195,810
Nebraska................................................          65,052          65,052          11,709          11,709          76,761          76,761
New Jersey..............................................           5,574           5,574           1,003           1,003           6,577           6,577
New York................................................          27,325          18,585           4,919           3,345          32,244          21,930
North Carolina..........................................         136,881          57,620          24,639          10,372         161,520          67,992
Ohio....................................................         310,230         137,077          55,841          24,674         366,071         161,751
Pennsylvania............................................         278,651         112,021          50,157          20,164         328,808         132,185
South Carolina..........................................          88,620          88,620          15,952          15,952         104,572         104,572
Tennessee...............................................         148,150          58,833          26,667          10,590         174,817          69,423
Texas...................................................         243,954         243,954          43,912          43,912         287,866         287,866
Virginia................................................          70,820          35,057          12,748           6,310          83,568          41,367
West Virginia...........................................         146,174          75,668          26,311          13,620         172,485          89,288
Wisconsin...............................................          79,480          40,126          14,306           7,223          93,786          47,349
--------------------------------------------------------------------------------------------------------------------------------------------------------
Note: Budgets, limits, and assurance levels apply to each state's emissions from covered sources, as defined by this final rule, only.

                             Table VI.F-2--State Budgets, Variability Limits, and Assurance Levels for Annual NOX Emissions
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                              Emission budget  (tons)       Emission variability  limit     State emissions  assurance
                                                         --------------------------------             (tons)                       level (tons)
                                                                                         ---------------------------------------------------------------
                                                             2012-2013       2014 and                        2014 and                        2014 and
                                                                              beyond         2012-2013        beyond         2012-2013        beyond
--------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama.................................................          72,691          71,962          13,084          12,953          85,775          84,915
Georgia.................................................          62,010          40,540          11,162           7,297          73,172          47,837
Illinois................................................          47,872          47,872           8,617           8,617          56,489          56,489
Indiana.................................................         109,726         108,424          19,751          19,516         129,477         127,940
Iowa....................................................          38,335          37,498           6,900           6,750          45,235          44,248
Kansas..................................................          30,714          25,560           5,529           4,601          36,243          30,161
Kentucky................................................          85,086          77,238          15,315          13,903         100,401          91,141
Maryland................................................          16,633          16,574           2,994           2,983          19,627          19,557
Michigan................................................          60,193          57,812          10,835          10,406          71,028          68,218
Minnesota...............................................          29,572          29,572           5,323           5,323          34,895          34,895
Missouri................................................          52,374          48,717           9,427           8,769          61,801          57,486
Nebraska................................................          26,440          26,440           4,759           4,759          31,199          31,199
New Jersey..............................................           7,266           7,266           1,308           1,308           8,574           8,574
New York................................................          17,543          17,543           3,158           3,158          20,701          20,701
North Carolina..........................................          50,587          41,553           9,106           7,480          59,693          49,033
Ohio....................................................          92,703          87,493          16,687          15,749         109,390         103,242
Pennsylvania............................................         119,986         119,194          21,597          21,455         141,583         140,649
South Carolina..........................................          32,498          32,498           5,850           5,850          38,348          38,348
Tennessee...............................................          35,703          19,337           6,427           3,481          42,130          22,818
Texas...................................................         133,595         133,595          24,047          24,047         157,642        1 57,642
Virginia................................................          33,242          33,242           5,984           5,984          39,226          39,226
West Virginia...........................................          59,472          54,582          10,705           9,825          70,177          64,407
Wisconsin...............................................          31,628          30,398           5,693           5,472          37,321          35,870
--------------------------------------------------------------------------------------------------------------------------------------------------------
Note: Budgets, limits, and assurance levels apply to each state's emissions from covered sources, as defined by this final rule, only.

[[Page 48270]]

                          Table VI.F-3--State Budgets, Variability Limits, and Assurance Levels for Ozone-Season NOX Emissions
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                              Emission budget  (tons)       Emission variability  limit     State emissions  assurance
                                                         --------------------------------             (tons)                       level (tons)
                                                                                         ---------------------------------------------------------------
                                                             2012-2013       2014 and                        2014 and                        2014 and
                                                                              beyond         2012-2013        beyond         2012-2013        beyond
--------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama.................................................          31,746          31,499           6,667           6,615          38,413          38,114
Arkansas................................................          15,037          15,037           3,158           3,158          18,195          18,195
Florida.................................................          27,825          27,825           5,843           5,843          33,668          33,668
Georgia.................................................          27,944          18,279           5,868           3,839          33,812          22,118
Illinois................................................          21,208          21,208           4,454           4,454          25,662          25,662
Indiana.................................................          46,876          46,175           9,844           9,697          56,720          55,872
Kentucky................................................          36,167          32,674           7,595           6,862          43,762          39,536
Louisiana...............................................          13,432          13,432           2,821           2,821          16,253          16,253
Maryland................................................           7,179           7,179           1,508           1,508           8,687           8,687
Mississippi.............................................          10,160          10,160           2,134           2,134          12,294          12,294
New Jersey..............................................           3,382           3,382             710             710           4,092           4,092
New York................................................           8,331           8,331           1,750           1,750          10,081          10,081
North Carolina..........................................          22,168          18,455           4,655           3,876          26,823          22,331
Ohio....................................................          40,063          37,792           8,413           7,936          48,476          45,728
Pennsylvania............................................          52,201          51,912          10,962          10,902          63,163          62,814
South Carolina..........................................          13,909          13,909           2,921           2,921          16,830          16,830
Tennessee...............................................          14,908           8,016           3,131           1,683          18,039           9,699
Texas...................................................          63,043          63,043          13,239          13,239          76,282          76,282
Virginia................................................          14,452          14,452           3,035           3,035          17,487          17,487
West Virginia...........................................          25,283          23,291           5,309           4,891          30,592          28,182
--------------------------------------------------------------------------------------------------------------------------------------------------------
Note: Budgets, limits, and assurance levels apply to each state's emissions from covered sources, as defined by this final rule, only.

    See section VII.E for the discussion of how variability limits and 
state assurance levels are used in the implementation of assurance 
provisions for the air quality-assured trading programs.

G. How the State Emission Reduction Requirements Are Consistent With 
Judicial Opinions Interpreting the Clean Air Act

    The methodology described in this notice quantifies states' 
significant contribution to nonattainment and interference with 
maintenance in a manner that is consistent with the decisions of the DC 
Circuit. As discussed previously, the DC Circuit has issued two 
significant decisions addressing the requirements of 
110(a)(2)(D)(i)(I). The first opinion largely upheld the NOX 
SIP Call, Michigan, 213 F.3d 663, and the second found significant 
flaws in CAIR, North Carolina, 531 F.3d. 896. In both cases, the Court 
considered aspects of the methodology used by EPA to identify emissions 
that, pursuant to section 110(a)(2)(D)(i)(I), must be eliminated due to 
their impact on air quality in downwind states. EPA believes that the 
methodology used in this final rule is consistent with both opinions 
and rectifies the flaws the North Carolina court identified with the 
methodology used in CAIR. The methodology used for this rule relies on 
state-specific data to analyze each individual state's significant 
contribution, uses air quality considerations in addition to cost 
considerations to identify each state's significant contribution, and 
gives independent meaning to the ``interference with maintenance'' 
prong. This methodology is then applied in a reasonable manner 
consistent with the relevant judicial opinions.
    In North Carolina, the Court held that EPA's approach to evaluating 
significant contribution was inadequate because, by evaluating only 
whether emission reductions were highly cost effective ``at the 
regional level assuming a trading program'', it failed to conduct the 
required state-specific analysis of significant contribution. See id. 
at 907. EPA, the Court concluded, ``never measured the `significant 
contribution' from sources within an individual state to downwind 
nonattainment areas.'' Id. The Court did not, however, disturb the air-
quality-based methodology used by EPA to identify the states with 
contributions large enough to warrant further consideration.
    For this rule, EPA uses a first step similar to that used in CAIR 
to identify the states with relatively large contributions. However, in 
contrast to CAIR, it then uses a state-specific analysis. Instead of 
identifying a single emission level that could be achieved by the 
application of highly cost effective controls in the region, EPA 
determines, on a state-by-state basis, what reductions could 
effectively be achieved by sources in each state. EPA's new approach 
does not, as the CAIR methodology did, establish a regional cap on 
emissions that is then divided into state budgets that set the emission 
reduction requirements for each state. Instead, EPA develops, for each 
covered state, emission budgets based on the reductions achievable at a 
particular cost per ton in that particular state, taking into account 
the need to ensure reliability of the electric generating system. The 
selected cost/ton levels reflect consideration of both cost factors and 
air quality factors including the estimated impact of upwind states' 
emissions on each downwind receptor.
    In addition, in developing this approach, EPA was guided by the 
Court's holdings regarding the use of cost to identify significant 
contribution. Specifically, the Court held in Michigan that EPA could 
``in selecting the `significant' level of `contribution' under section 
110(a)(2)(D)(i)(I), choose a level corresponding to a certain reduction 
in cost.'' North Carolina, 531 F.3d at 917 (citing Michigan, 213 F.3d 
at 676-77). This holding also supported the Court's conclusion in 
Michigan that it was acceptable for EPA to apply a uniform cost-
criterion across states. See Michigan, 213 F.3d at 679. In the CAIR 
case, the Court rejected EPA's analysis, not because it relied on cost 
considerations to identify significant contribution, but because it 
found that EPA had failed to draw the significant contribution line at 
all. See North Carolina, 531 F.3d at 918 (``* * * here EPA did not draw 
the [significant contribution] line at all. It simply verified sources 
could meet the SO2 caps with controls EPA dubbed `highly

[[Page 48271]]

cost-effective.' ''). The holdings in Michigan regarding the use of 
cost and a uniform cost-criterion across states were left undisturbed. 
See, e.g., North Carolina, 531 F.3d at 917 (explaining that in Michigan 
the Court held that ``EPA may `after [a state's] reduction of all [it] 
could * * * cost-effectively eliminate[],' consider `any remaining 
contribution insignificant''). In fact, the Court acknowledged that, 
based on the Michigan holdings, the measurement of a state's 
significant contribution need not ``directly correlate with each 
state's individualized air quality impact on downwind nonattainment 
relative to other upwind states.'' North Carolina, 531 F.3d at 908.
    For these reasons, EPA determined that it was appropriate in this 
rulemaking to consider the cost of controls to determine what portion 
of a state's contribution is its ``significant contribution.'' However, 
EPA also heeded the North Carolina Court's warning that ``EPA can't 
just pick a cost for a region, and deem `significant' any emissions 
that sources can eliminate more cheaply.'' North Carolina,, 531 F.3d at 
918. Thus, in this rulemaking, EPA departs from the practice used in 
the NOX SIP Call and in CAIR of evaluating, based solely on 
the cost of control required in other regulatory environments, what 
controls would be considered ``highly-cost-effective.'' Instead, as 
part of its determination of a reasonable cost per ton for upwind state 
control, EPA evaluates the air quality impact of reductions at various 
cost levels and considers the reasonableness of possible cost 
thresholds as part of a multi-factor analysis.
    In addition, the methodology used in this rulemaking gives 
independent meaning to the interfere with maintenance prong of section 
110(a)(2)(D)(i)(I). In North Carolina, the Court concluded that CAIR 
improperly ``gave no independent significance to the `interfere with 
maintenance' prong of section 110(a)(2)(D)(i)(I) to separately identify 
upwind sources interfering with downwind maintenance.'' North Carolina, 
531 F.3d at 910. EPA rectified this flaw in this rulemaking by 
separately identifying downwind ``nonattainment sites'' and downwind 
``maintenance sites.'' EPA decided to consider upwind states' 
contributions not only to sites that EPA projected would be in 
nonattainment, but also to sites that, based on the historic 
variability of their emissions, EPA determined may have difficulty 
maintaining the relevant standards. The specific mechanism EPA used to 
implement this approach is described in detail in section V.C, 
previously. For annual PM2.5, this approach identified 16 
maintenance sites in addition to the 32 nonattainment sites identified 
in the analysis of nonattainment receptors. For 24-hour 
PM2.5 this approach identified 38 maintenance sites in 
addition to the 92 nonattainment sites identified in the analysis of 
nonattainment receptors. For ozone it identified 16 maintenance sites 
in addition to the 11 ozone nonattainment sites identified.
    EPA applied this methodology using available information and data 
to measure the emissions from states in the eastern United States that 
significantly contribute to nonattainment or interfere with maintenance 
in downwind areas with regard to the 1997 and 2006 PM2.5 
NAAQS and the 1997 ozone NAAQS. Although EPA has not completely 
quantified the total significant contribution of these states with 
regard to all existing standards, EPA has determined, on a state-
specific basis, that the emissions prohibited in the FIPs are either 
part of or constitute the state's significant contribution to 
nonattainment and interference with maintenance. Thus, elimination of 
these emissions will, at a minimum, make measurable progress towards 
satisfying the section 110(a)(2)(D)(i)(I) prohibition on significant 
contribution to nonattainment and interference with maintenance.

VII. FIP Program Structure To Achieve Reductions

A. Overview of Air Quality-Assured Trading Programs

    EPA is finalizing an air quality-assured trading remedy that is 
substantially similar to the preferred trading remedy presented in the 
proposal. Key differences from the preferred trading remedy in the 
proposal include:
     Recalculated state budgets and variability limits (i.e., 
state assurance levels) based on updated modeling;
     Simplified variability limits for 1-year application only;
     Revised allocation methodology for existing and new units 
and revised new unit set-asides for new units in Transport Rule states 
and new units potentially locating in Indian country;
     Changed start of assurance provisions to 2012 and 
increased assurance provision penalties; and
     Removed opt-in provisions.
    In the final rule, as in the proposed rule, EPA is promulgating 
FIPS to require SO2 and NOX reductions from power 
plants in jurisdictions \55\ that contribute significantly to 
nonattainment in, or interfere with maintenance by, a downwind area 
with respect to the 1997 ozone NAAQS, the 1997 annual PM2.5 
NAAQS, and/or the 2006 24-hour PM2.5 NAAQS. These FIPs 
establish state-specific emission control requirements using state 
budgets starting in 2012, with a second phase of SO2 
reductions in some states in 2014. Section IV explains EPA's authority 
to issue FIPs.
---------------------------------------------------------------------------

    \55\ Alabama, Arkansas, Florida, Georgia, Illinois, Indiana, 
Iowa, Kansas, Kentucky, Louisiana, Maryland, Michigan, Minnesota, 
Mississippi, Nebraska, New Jersey, New York, North Carolina, Ohio, 
Pennsylvania, South Carolina, Tennessee, Texas, Virginia, West 
Virginia, and Wisconsin. As discussed in section III, in a separate 
notice, EPA is proposing to include Iowa, Kansas, Michigan, 
Missouri, Oklahoma, and Wisconsin in the ozone-season NOX 
requirements.
---------------------------------------------------------------------------

    The air quality-assured trading remedy in the final rule allows 
interstate trading to account for variability in the electricity 
sector, but also includes assurance provisions to ensure that the 
necessary emission reductions occur within each covered state. The 
assurance provisions restrict EGU emissions within each state to the 
state's budget plus the variability limit and ensure that every state 
is making reductions to eliminate the significant contribution to 
nonattainment and interference with maintenance that EPA has 
identified. While EPA proposed to impose these assurance provisions 
starting in 2014, the final rule implements these provisions starting 
in 2012 (see section VII.E of this preamble). Additionally, the final 
FIPs include penalty provisions adequate to ensure that the state 
budget with the variability limit will not be exceeded.
    In the final rule, as in the preferred trading remedy discussed in 
the proposed rule, state-specific emission budgets without the 
variability limits are used to determine the number of emission 
allowances allocated to sources in each state. An EGU source is 
required to hold one SO2 or one NOX allowance, 
respectively, for every ton of SO2 or NOX emitted 
during the control period. Banking of allowances for use or trading in 
future years is allowed.
    The final rule establishes four interstate trading programs, each 
starting in 2012: two for annual SO2, one for annual 
NOX, and one for ozone-season NOX. One 
SO2 trading program is for sources in states (referred to as 
SO2 Group 1) that need to make larger reductions to 
eliminate their significant contribution, while the second is for 
sources in states (referred to as SO2 Group 2) that need to 
make smaller reductions. A source in a Group 1 state can only use 
SO2 allowances allocated to Group 1 states for compliance 
with

[[Page 48272]]

the SO2 trading program. A source in a Group 2 state can 
only use SO2 allowances allocated to Group 2 states for 
compliance with the SO2 trading program. For compliance in 
the annual NOX and ozone-season NOX trading 
programs respectively, sources may use annual NOX and ozone-
season NOX allowances allocated for any state, even if that 
state is in a different group for SO2 than the source's 
state. Four sets of new emission allowances based on the new state-
specific budgets without variability are allocated to sources, one set 
for each of the four trading programs. Each state has the option of 
replacing these FIPs with state rules. EPA believes that this remedy 
meets the concerns raised by the Court in the 2008 North Carolina 
decisions which remanded CAIR to EPA.
    In the proposed rule, EPA took comment on all aspects of the 
preferred trading remedy and on two alternative regulatory options: (1) 
intrastate trading; and (2) direct control. EPA also took comment on a 
trading ratios approach.
    Comments on the Preferred Trading Remedy: The great majority of 
public comments supported the preferred trading remedy. Most of these 
commenters voiced their support for the broadest possible trading 
mechanism because it allows for the most cost-effective implementation 
of any emission controls. Commenters noted that flexibility is always 
needed in the early years of new programs. Further, commenters favoring 
the preferred remedy agreed with EPA that, by using state-specific 
control budgets and allowing for interstate trading, the preferred 
remedy provided electricity generators the flexibility to undertake the 
most cost-effective reductions while assuring that the resulting 
reductions occur within the individual states.
    Some commenters that supported the preferred remedy felt that, 
while not ideal, the interstate trading remedy was preferable to the 
alternative options of intrastate trading or direct control. Many 
commenters that supported the preferred remedy felt that the intrastate 
trading remedy and direct control remedy options offer minimal 
flexibility from a compliance perspective. They stated that this lack 
of flexibility would unnecessarily increase the cost of emission 
reductions.
    Other commenters who generally support the preferred remedy cited 
concerns about the level of complexity in the assurance provisions. One 
commenter surmised that the preferred option creates significant risk 
where a company could unexpectedly find itself in a noncompliance 
situation due to the after-the-fact variability analysis. Another said 
that the rule's features needlessly reduce the system's efficiency and 
increase complexity. These commenters generally preferred unlimited 
trading, noting that EPA has proven success with Title IV, the 
NOX SIP Call, and CAIR unlimited interstate trading programs 
and that allowing unrestricted interstate trading would increase 
flexibility to meet reduction goals and minimize increases in power 
costs.
    EPA is finalizing the preferred trading remedy for the following 
reasons. EPA believes this approach is the most cost-effective and 
practical way to comply with the Court decision in North Carolina to 
ensure that all emissions in a given state that EPA has identified as 
significantly contributing to downwind nonattainment or interfering 
with maintenance are eliminated. The vast majority of public commenters 
agree. In addition, this approach provides the most flexibility for 
sources while meeting the Clean Air Act requirements and protecting 
public health. As a result, potential innovations and resulting cost 
savings are more likely to be found and implemented. Based on 
historical experience (see the Transport Rule proposal, 75 FR 45315), 
EPA has shown that the results offered by a flexible trading approach 
(e.g., flexible compliance choices, incentives to reduce emissions 
early and in the highest emitting areas, 100 percent compliance with 
requirements) are substantial. A large number of commenters have 
corroborated this assessment. As summarized in the proposal, EPA 
believes that the preferred trading remedy will allow source owners to 
choose among several compliance options to achieve required emission 
reductions in the most cost-effective manner, such as installing 
controls, changing fuels, reducing utilization, buying allowances, or 
any combination of these actions. Interstate trading with assurance 
provisions provides additional regulatory flexibility that promotes the 
power sector's ability to operate as an integrated, interstate system 
and to provide electric reliability.
    Comments on Intrastate Trading: A few commenters favored the first 
alternative, intrastate trading. One commenter who favored intrastate 
trading stated that many power plants have avoided investment in 
pollution controls by buying allowances from other plants, affecting 
local air quality improvement. EPA notes that this Transport Rule aims 
to address emissions from one state that significantly contribute to 
nonattainment or interfere with maintenance of certain NAAQS in other 
states. Local air quality issues are directly addressed by other 
provisions in the Clean Air Act.
    Several commenters raised concerns about the intrastate trading 
approach. Some stated, as EPA noted in the proposal, that the 
intrastate trading option would be more resource intensive, more 
complex, less flexible, and potentially more susceptible to market 
manipulation than the other options. In addition, some commenters felt 
that this alternative would provide less flexibility to ensure electric 
reliability than the preferred approach, resulting in greater private 
costs to the power sector and greater social costs for consumers.
    EPA is not finalizing the intrastate trading option for the 
following reasons. As EPA expressed in the proposal and as commenters 
have agreed, the intrastate trading option would be more resource 
intensive (both for EPA and for sources), more complex, less flexible, 
and potentially more susceptible to market manipulation than the 
preferred trading approach that EPA is finalizing. The intrastate 
trading option would be more costly and less transparent due to the 
large number of trading programs that would be operated simultaneously 
and the large number of annual auctions that would be held every year 
to address the issues of market power within states. This option would 
also result in a greater burden for participants operating EGUs in 
multiple states.
    Comments on Direct Control Option: Several commenters favored the 
second alternative, direct control. One commenter stated that direct 
control--allowing no trading--was the option best aligned with the 2008 
Court decisions. EPA disagrees with this comment for the reasons given 
below and because, as explained in this rule, EPA believes the air 
quality-assured trading remedy finalized today is consistent with the 
decisions of the DC Circuit in North Carolina.
    Some commenters, who support direct control, voiced concerns that 
the other emission trading approaches would disadvantage poor and 
minority communities or allow increased emission impacts in 
neighborhoods near power plants. EPA notes that a direct control 
approach would not require controls on all plants in a state, but only 
on a sufficient number to address the transport requirements under 
section 110(a)(2)(d)(i)(I) that this rule addresses, and therefore 
would not necessarily mandate controls on each neighborhood power 
plant.
    In addition, EPA has conducted an analysis of the effects of the 
Transport

[[Page 48273]]

Rule on environmental justice and other vulnerable communities. We 
concluded that, similar to our experience with the Acid Rain 
Program,\56\ many environmental justice communities are expected to see 
large health benefits, and none are expected to experience any 
disbenefits, from implementing an air quality-assured trading program. 
The results of this analysis are presented in section XII of this 
preamble and Chapter 5 of the RIA for this rule. In addition, the CAA 
provides flexibility for state and local authorities to impose stricter 
limits on sources to address specific local air quality concerns. Such 
limits are independent of the requirements in this rule, and compliance 
with Transport Rule requirements in no way excuses a source from 
complying with other CAA or state law requirements.
---------------------------------------------------------------------------

    \56\ See http://www.epa.gov/airmarkets/resource/docs/ejanalysis.pdf and Ringquist, Evan J. 2011. ``Trading Equity for 
Efficiency in Environmental Protection? Environmental Justice 
Effects from the SO2 Allowance Trading Program.'' Social 
Science Quarterly 92(2):297-323
---------------------------------------------------------------------------

    Several commenters raised concerns with the direct control 
approach. One commenter felt that issues with electricity market 
reliability could occur during high electricity demand periods if 
sources ceased operations due to approaching their emission rate 
limitations under a direct control remedy. Another commenter was 
concerned that applying emission rates under a direct control remedy to 
small municipal units would cause disproportionate impacts on power 
plants where pollution control is more expensive. Other commenters 
cited concerns that EPA's proposed within-state company-wide averaging 
provision in the direct control proposed alternative (designed to allow 
some flexibility for sources) would place companies with fewer units at 
a disadvantage compared to companies with more units. EPA generally 
agrees with the commenters concerns and has decided not to finalize the 
direct control remedy for the following reasons. EPA modeling projects 
that the direct control alternative would result in fewer emission 
reductions and higher costs compared to the air quality-assured trading 
remedy. EPA analysis indicates that it is not necessary to implement a 
direct control approach in order to protect vulnerable and sensitive 
populations or environmental justice communities. Also, the direct 
control approach would result in fewer compliance options because a 
direct control approach would directly regulate individual sources by 
setting unit-level emission rate limits. This lack of flexibility could 
lead to potential increases in reliability risks in the electric power 
system and fewer opportunities for potential technological innovations 
that reduce emissions further and/or lower costs. For these reasons, 
EPA believes that this approach is inferior to the air quality-assured 
trading remedy.
    Other Comments: A handful of commenters mentioned the trading 
ratios approach, though none favored it as a viable alternative. One 
commenter said the trading ratios approach was not consistent with CAA 
section 110(a)(2)(D) requirements that reductions in emissions occur in 
particular geographic locations. Other commenters agreed that it was 
administratively unworkable and would be difficult to implement due to 
the complexity and variety of meteorological conditions. EPA generally 
concurs with the commenters. In the proposal, EPA noted that it would 
not be possible under this approach, as contemplated, to include 
enforceable legal requirements to ensure that a specific state's 
emissions remain below a specified level or to ensure that a specific 
amount of reductions occur within a particular state. EPA specifically 
requested comment on whether a ratios trading program could be designed 
to provide such legal assurances. Of the few comments received, none 
offered such a solution. For these reasons, EPA is not finalizing this 
approach.
    Some commenters offered additional suggestions, such as: 
unrestricted trading; using different authorities in the CAA to address 
interstate transport such as section 110(k)(5) and section 126; and an 
approach that would replace the assurance provisions by a system using 
both emission allowances usable (as well as bankable) in any state and 
assurance allowances usable (but not bankable) in only the state for 
which they would be issued. While EPA appreciates the thoughtful and 
constructive comments, we did not find any of these suggestions 
improved our ability to address interstate transport under CAA section 
110(a)(2)(D)(i)(I), in line with the Court decision, in an 
administratively practical way.
    Several commenters liked the idea of establishing unit-by-unit 
short-term and long-term performance standards/emission rates but 
suggested adding an overlaid cap and trade program. EPA believes the 
air quality-assured trading remedy finalized today is consistent with 
the decisions of the Court in North Carolina and will ensure the 
reductions necessary to meet statutory requirements.
    For the 2012-2013 period, EPA took comment on whether the assurance 
provisions are needed, since the state-specific budgets would be based 
on known air pollution controls and the penalty provisions would be 
adequate to ensure that the budget, including a variability limit, 
would not be exceeded. Further, EPA proposed to use two variability 
limits: a 1-year limit, based on the year-to-year variability in 
emissions relative to the proposed budgets; and a 3-year limit based on 
the variability in a 3-year average relative to the proposed budget.
    Based on comments on the assurance provisions (see section VII.E of 
this preamble) and variability limits (see section VI.E.2 of this 
preamble), EPA is finalizing the Transport Rule with state budgets plus 
variability limits and assurance provisions starting in 2012 for all of 
the trading programs. EPA sees an immediate need to ensure that 
emissions within a state do not exceed the state budget plus the 
variability limitation in order to comply with the Court's opinion. 
Further, commenters stated that the 3-year variability limit increased 
costs and unnecessarily complicated the trading programs. As explained 
in section VI.E.2, EPA is finalizing the 1-year variability limit 
starting in 2012, but not the 3-year limit.

B. Applicability

    The applicability provisions in the final rule are, except as 
discussed herein, essentially the same as in the proposed rules and for 
each of the Transport Rule trading programs.
    Under the general applicability provisions of the proposed rule, 
the Transport Rule trading programs would cover fossil-fuel-fired 
boilers and combustion turbines serving--on any day starting November 
15, 1990 or later--an electrical generator with a nameplate capacity 
exceeding 25 MWe and producing power for sale, with the exception of 
certain cogeneration units and solid waste incineration units.
    EPA requested comment on whether a more recent year should be used 
instead. The proposed use of the November 15, 1990 date was consistent 
with the use of 1990 as the beginning of the historical period for 
which owners and operators would generally be required to have 
information about their units for purposes of determining whether the 
units were covered by the Transport Rule trading programs. Because unit 
information is generally compiled and retained on a calendar year 
basis, EPA believes that, for the general applicability provisions, it 
is preferable to use January 1, rather than November 15. In determining 
which

[[Page 48274]]

year should be used as the reference year in the general applicability 
provisions, EPA considers several factors.
    First, in order for owners and operators, and EPA, to be able to 
determine which units are subject to the Transport Rule trading 
programs, EPA believes that the reference year should not be so far in 
the past that the unit information necessary to make applicability 
determinations is not readily available. This particularly becomes an 
issue in cases of older units that have changed ownership over time. 
EPA found, in making some applicability determinations under the CAIR 
trading programs, that some older units with ownership changes had 
difficulty obtaining information back as far as twenty or more years. 
Using January 1, 1990 as the reference date in the general 
applicability provisions could effectively require some owners and 
operators to retain unit information going back as far as 20 years. As 
a point of contrast, under the title V permitting rules, owners and 
operators are generally required to retain data for 5 years. See 40 CFR 
70.6(a)(3)(B).
    Second, EPA also believes that the reference year used in the 
applicability provisions should be far enough in the past that the unit 
information on which applicability determinations are based provides a 
full picture of the nature of the unit and its operations over time, 
such as the types of fuels combusted at the unit and whether the unit 
has produced electricity for sale.
    Third, EPA considers whether selecting a different reference year 
for the applicability provisions than the one in the proposed rule 
dramatically changes what units will be covered by the Transport Rule 
trading programs. In this case, EPA believes, based on available 
information about the units potentially subject to the Transport Rule, 
that using a somewhat later year than the one in the proposed rule will 
likely have little effect on what units are covered. Balancing these 
factors, EPA concludes that it is reasonable to use January 1, 2005, 
rather than November 15, 1990, in the general applicability provisions 
in the final rule.
    In the final rule, EPA is taking the same approach with regard to 
defining whether a boiler or combustion turbine is considered to be 
``fossil-fuel-fired'' as the one used in the proposal. Under the 
proposed rule, a unit was considered to be ``fossil-fuel-fired'' if it 
combusts any amount of fossil fuel at any time in 1990 or later. For 
the same reasons that EPA decided to use January 1, 2005 in the general 
applicability provisions, and in order to have a consistent reference 
year in all applicability-related provisions, the final rule defines a 
``fossil-fuel-fired'' unit as one that combusts any amount of fossil 
fuel in 2005 or later.
    EPA notes that the final Transport Rule allows a state to submit a 
SIP revision (an abbreviated or full SIP) under which the state may--in 
addition to making certain types of changes concerning allowance 
allocations in the Transport Rule trading programs--expand the general 
applicability provisions of the Transport Rule NOX Ozone 
Season Trading Program to cover fossil-fuel-fired boilers and 
combustion turbines serving--at any time starting January 1, 2005 or 
later-- a generator with a nameplate capacity as low as 15 MWe 
producing power for sale. The exemptions, discussed below, for 
cogeneration units and solid waste incineration units still will 
continue to apply.
    Cogeneration unit exemption. Under the final rule (as well as the 
proposed rule) certain cogeneration units or solid waste incinerators 
are exempt from the FIP requirements. In particular, the final rule 
includes an exemption for a unit that qualifies as a cogeneration unit 
throughout the later of 2005 or the first 12 months during which the 
unit first produces electricity and continues to qualify through each 
calendar year ending after the later of 2005 or that 12-month period 
and that meets the limitation on electricity sales to the grid. In 
order to meet the definition of ``cogeneration unit'' in the final 
rules, a unit (i.e., a fossil-fuel-fired boiler or combustion turbine) 
must be a topping-cycle or bottoming-cycle that operates as part of a 
``cogeneration system,'' which is defined as an integrated group of 
equipment at a source (including a boiler, or combustion turbine, and a 
steam turbine generator) designed to produce useful thermal energy for 
industrial, commercial, heating, or cooling purposes and electricity 
through the sequential use of energy. A topping-cycle unit is a unit 
where the sequential use of energy results in production of useful 
power first and then, through use of reject heat from such production, 
in production of useful thermal energy. A bottoming-cycle unit is a 
unit where the sequential use of energy results in production of useful 
thermal energy first and then, through use of reject heat from such 
production, in production of useful power. In order to qualify as a 
cogeneration unit, a unit also must meet certain efficiency and 
operating standards.
    In the proposed rule, a unit would have to qualify as a 
cogeneration unit and meet the limitation on electricity sales starting 
the later of 1990 or the year when the unit begins operating. EPA 
requested comment on whether a more recent year should be used. For the 
reasons discussed above concerning the reference year used in the 
general applicability provisions and in order to have a consistent 
reference year in all applicability-related provisions, EPA concludes 
that it is reasonable to use 2005, rather than 1990, in the 
cogeneration unit exemption provisions in the final rule. Consequently, 
the final rule provides that the requirements to qualify as a 
cogeneration unit and to meet the electricity sales limitation start no 
earlier than 2005.
    In the final rule, EPA also clarifies that the electricity sales 
limitation under the exemption is applied in the same way whether a 
unit serves only one generator or serves more than one generator. In 
both cases, the total amount of electricity produced annually by a unit 
and sold to the grid cannot exceed the greater of one-third of the 
unit's potential electric output capacity or 219,000 MWhr. This is 
consistent with the approach taken in the Acid Rain Program (40 CFR 
72.7(b)(4)), where the cogeneration unit exemption originated. EPA 
believes that this clarification is needed to ensure that a unit 
serving, for example, two generators would not have a limit on sales of 
electricity to the grid that would be different (i.e., twice as high) 
from the limit for a unit serving only one generator with the same 
total nameplate capacity as the first unit's two generators.
    EPA also took comment on whether efficiency standards should be 
applied on a system-wide basis to bottoming-cycle units (where useful 
thermal energy is produced before useful power is produced), as they 
are for topping-cycle units (where useful thermal energy is produced 
after useful power) and whether to exclude, from the requirement to 
meet the operating and efficiency standards, calendar years during 
which a cogeneration unit does not operate at all. Several commenters 
argued EPA should apply efficiency standards to both types of units. 
EPA agrees that applying efficiency standards on a system-wide basis to 
both bottoming-cycle and topping-cycle units is reasonable because EPA 
sees no technical reason to distinguish between the two types of units 
in this instance. EPA further agrees with commenters that excluding 
calendar years in which the cogeneration unit does not operate at all, 
i.e., does not combust any fuel, from the requirements to meet 
operating and efficiency standards is also reasonable. For such a year, 
the unit would not produce any useful thermal

[[Page 48275]]

energy or useful power and therefore could not meet the minimum output 
requirements in the operating and efficiency standards, but the unit 
also would not have any emissions. For these reasons, the final rule 
expressly provides that the operating and efficiency standards do not 
have to be met for a calendar year throughout which a unit did not 
operate at all.
    Solid waste incineration unit exemption. The final rule also 
includes an exemption for a unit that qualifies as a solid waste 
incineration unit during the later of 2005 or the first 12 months 
during which the unit first produces electricity, that continues to 
qualify throughout each calendar year ending after the later of 2005 or 
that 12-month period each year thereafter, and that meets the 
limitation on fossil-fuel use. In contrast, the exemption for solid 
waste incineration units in the proposed rule distinguished between 
units commencing operation before January 1, 1985 and those commencing 
operation on or after that date. A unit commencing operation before 
January 1, 1985 would be exempt if it qualified as a solid waste 
incineration unit starting the later of 1990 or the year when it began 
producing electricity and its average annual fuel consumption of non-
fossil fuels exceeded 80 percent of total heat input during 1985-1987 
and during any three consecutive calendar years after 1990. A unit 
commencing operation on or after January 1, 1985 would be exempt if it 
qualified as a solid waste incineration unit starting the later of 1990 
or the year when it began producing electricity and its average annual 
fuel consumption of non-fossil fuel exceeded 80 percent of total heat 
input for the first 3 calendar years of operation and for any 3 
consecutive calendar years thereafter.
    In the proposal, EPA requested comment on whether it would be 
problematic to obtain sufficiently detailed information about unit 
operation potentially as far back as 1985-1987 and 1990, and whether 
the fuel consumption standard for each unit should be limited to more 
recent years. For the reasons discussed above concerning the reference 
year used in the general applicability provisions and in order to have 
a consistent reference year for all applicability-related provisions, 
EPA concludes that it is reasonable to use 2005, rather than 1990, in 
the solid waste incineration unit exemption in the final rule. In 
particular, EPA notes that the proposed provisions for units commencing 
operation before January 1, 1985 and for units commencing operation on 
or after January 1, 1985 could require some owners and operators to 
retain unit information going back more than 20 years before the 
promulgation of this final rule. Further, EPA believes that removing 
the distinction between units commencing operation during these two 
periods, and referencing somewhat later years as the earliest years for 
which information on fossil-fuel consumption is required, will result 
in the exemption still being based on sufficient data to provide a full 
picture of the nature and operation of the units involved. EPA also 
believes, based on available information about the units potentially 
subject to the Transport Rule, that this approach will not 
significantly change which units qualify for the exemption. 
Consequently, the final rule removes the distinction based on whether a 
solid waste incineration unit commences operation before January 1, 
1985 or on or after January 1, 1985. In order to be exempt, the unit 
must qualify as a solid waste incineration unit during the later of 
2005 or the first 12 months during which the unit first produces 
electricity, must continue to qualify throughout each calendar year 
ending after the later of 2005 or that 12-month period, and must meet 
the limitation on fossil-fuel use on a 3-year average basis during the 
first 3 years of operation starting no earlier than 2005 and every 3 
years of operation thereafter.
    Opt-in units. EPA is not finalizing the opt-in provisions that were 
discussed in the Transport Rule proposal. EPA proposed opt-in 
provisions to allow non-covered units to voluntarily opt in to any of 
the proposed Transport Rule trading programs and receive allocations 
reflecting 70 percent of the unit's emissions before opting in. These 
allowances were above the state-specific budgets developed under the 
Transport Rule to eliminate a state's significant contribution to 
nonattainment and interference with maintenance. In theory, an opt-in 
unit that makes reductions below its baseline and sells the freed-up 
allowances is effectively substituting its new, lower-cost reductions 
for higher-cost reductions otherwise required by a covered EGU, with 
the result that the state's significant contribution is still 
eliminated but at a lower total program cost.
    EPA notes that theoretical benefits anticipated from allowing opt-
ins did not materialize in prior trading programs with opt-in 
provisions. The Acid Rain Program has about 23 opt in units; the 
NOX Budget Trading Program had five opt-in units; and no 
units opted into the CAIR programs. As a group, these opt-in units 
neither eased the achievement of required emission reductions in past 
trading programs, nor reduced overall program costs.
    In the proposal, EPA requested comment on the opt-in provisions, 
specifically regarding: What are the benefits of and concerns about 
including opt-in provisions; how to ensure units are not credited for 
emission reductions the units would have made anyway; whether the 
proposed 30 percent reduction (i.e., application of the 70 percent 
multiplier to baseline emissions) or some other percentage reduction, 
or no reduction, should be applied to the baseline emission rate used 
in determining allocations; and whether any additional percentage 
reduction (such as 45 percent) should be applied to SO2 
Group 1 opt-in units in Phase II to reflect the stricter limits for 
covered units.
    Some commenters argued that increasing the Transport Rule budgets 
for opt-ins would undermine the goal of CAA section 110(a)(2)(D)(i)(I) 
to eliminate a state's significant contribution to nonattainment and 
interference with maintenance. One commenter stated that it does not 
favor allowing sources that are not subject to the emission reduction 
requirements to be issued allowances that would increase the overall 
state emission budgets, due to the uncertainty that any reductions made 
by such units would be surplus, verifiable, permanent and enforceable. 
This could compromise the integrity of the EGU emission reduction 
requirements of the Transport Rule and jeopardize assurance that a 
state's significant contribution would be eliminated, as required by 
the Court in North Carolina. Other commenters claim that, while no 
cheap tons are available from non-EGUs and EPA is right not to require 
non-EGU reductions, EPA should nonetheless allow non-EGUs to choose 
voluntarily to be covered by opting in.
    As mentioned previously, the final Transport Rule does not include 
any opt-in provisions either in the FIPs or in the provisions allowing 
modification or replacement of the FIPs through submission of trading 
program provisions in SIPs. EPA has several reasons for not adopting 
provisions to allow opt-in units. First, as mentioned above, 
historically, very few units have opted in. As of 2010, 28 units out of 
more than 4,700 covered units (23 units out of a total of about 3,600 
covered units in the Acid Rain Program and 5 units out of a total of 
about 2,600 covered units in the NOX SIP Call) have opted in 
to EPA trading programs over the past 15 years. In the Acid Rain 
Program, 3 of the units opted in and

[[Page 48276]]

then, effective for 2005, opted out. Four of the units opted in, 
immediately shut down, and continue to receive allowance allocations. 
Four of the units opted in and continue to operate and receive 
allowance allocations. Finally, 12 of the units opted in, after CAIR 
was finalized, in order to receive allowances usable for compliance in 
the CAIR SO2 trading program. Because CAIR will be replaced 
by this Transport Rule, EPA anticipates that these 12 units will opt 
out of the Acid Rain Program. In the NOX Budget Trading 
Program, 3 plants with 5 opt-in units received allocations between 2003 
and 2008.
    Moreover, EPA has determined that the inclusion of opt-in units in 
the Transport Rule trading programs would undermine the rule's 
objective of addressing emissions in each state that significantly 
contribute to nonattainment or interfere with maintenance in other 
states. As explained above, EPA has established budgets plus 
variability limits that states must meet to ensure that the significant 
contribution to nonattainment and interference with maintenance 
identified by EPA is addressed. If EPA were to allow opt-ins, and if 
any opt-in unit were to receive an allocation of allowances for 
emissions that would be reduced even if the units did not opt in, then 
the inclusion of that opt-in unit in the program would allow the 
sources covered by the Transport Rule to emit in excess of the budget 
plus variability limit with no new, offsetting reduction in emissions. 
For example, after a unit would opt in, process or fuel changes made 
for economic reasons (rather than due to any regulatory requirements), 
or installation of new emission controls or fuel-switching conducted to 
meet future, non-Transport Rule regulatory requirements, could result 
in emission reductions that would have occurred ``anyway'' (i.e., even 
if the unit had not opted in), and the opt-in unit would be allocated 
allowances for the portion of its baseline emissions that would be 
removed by these ``anyway'' reductions. Allocations above the cap to 
opt-in units making ``anyway'' emission reductions would convert these 
reductions into extra allowances (i.e., authorizations to emit) usable 
by covered EGUs to meet their requirements to hold allowances for 
emissions. Because the extra EGU emissions authorized by these extra 
allowances would not be offset by any new emission reductions by the 
opt-in units, this could threaten a state's ability to eliminate the 
significant contribution to nonattainment and interference with 
maintenance identified by EPA in the final rule. Also, opt-in units, 
which are allocated allowances outside the state budget for covered 
units, could increase the possibility that a state's total emissions 
would exceed the state budget plus variability and thus that the 
assurance provisions would be triggered.
    This problem of allocating allowances for emissions that would have 
been reduced anyway is illustrated by the recent promulgation of the 
final rule, National Emission Standards for Hazardous Air Pollutants 
for Major Sources: Industrial, Commercial, and Institutional Boilers 
and Process Heaters (76 FR 15608 (March 21, 2011)) (``final Boiler MACT 
rule''), which requires certain industrial, commercial, and 
institutional boilers to meet maximum achievable control technology 
(MACT) standards for emissions of specified hazardous air pollutants, 
such as hydrogen chloride (HCL) and mercury (Hg). Some of the control 
technologies that can be used to meet these standards will also provide 
significant reductions of SO2 emissions. For example, a 
boiler may use a wet scrubber or the combination of a dry sorbent 
injection system and a fabric filter (among other options) to meet the 
applicable HCL standard or may use a wet scrubber or a combination of 
activated carbon injection and a fabric filter (among other options) to 
meet the applicable Hg standard. See 76 FR 15614 (describing testing 
and compliance requirements when such controls are used to meet these 
standards); and Memo from Brian Shrager to Amanda Singleton and Graham 
Gibson, Revised Methodology for Estimating Cost and Emissions Impacts 
for Industrial, Commercial and Institutional Boilers and Process 
Heaters National Emissions Standards for Hazardous Air Pollutants--
Major Source (February 11, 2011), Document ID EPA-HQ-OAR-2009-0491-4036 
(section 3.1, describing control options for HCL and Hg control). In 
fact, EPA estimated that the new standards would result in emission 
reductions of not only the hazardous air pollutants directly subject to 
the standards, but also in other air pollutants such as SO2. 
Specifically, EPA projected that compliance with the final Boiler MACT 
rule standards will result in about 431,000 tons of annual 
SO2 reductions from existing boilers subject to the final 
Boiler MACT rule. This will comprise on average about a 46 percent 
reduction in SO2 emissions for this group of boilers. Coal- 
and oil-fired boilers--which are the boilers likely to have the most 
uncontrolled SO2 emissions and so would be the most likely 
types of units to consider opting into the Transport Rule trading 
programs if opting-in were allowed--are projected to reduce about 
409,000 tons of annual SO2 as a result of complying with the 
final Boiler MACT rule, or about a 50 percent reduction in 
SO2 emissions. See Memo from Brian Shrager to Amanda 
Singleton and Graham Gibson, Appendix B-1, (where column CE represents 
baseline SO2 emissions and column CH represents 
SO2 reductions resulting from the final Boiler MACT rule 
compliance). The amount of offsetting SO2 increases 
projected to result from final Boiler MACT rule compliance, e.g., from 
additional fuel being combusted to generate electricity to operate 
emission controls, is minor. See 76 FR 15651 (Table 4) and 15653 
(showing projected total SO2 reductions for all boilers and 
process heaters of about 442,000 tons and net SO2 reductions 
of about 440,000 tons).
    Consequently, a boiler subject to the final Boiler MACT rule may 
install a wet acid gas scrubber or a bag house in order to meet the HCL 
or Hg standard applicable to boilers under the final Boiler MACT rule 
and thereby achieve SO2 emission reductions. If that boiler 
were to opt in to one of the Transport Rule SO2 trading 
programs during the year before installing these controls to comply 
with the final Boiler MACT rule, then the boiler would be allocated 
allowances for the unit's current tons of SO2 emissions and 
would not need to use these allowances for compliance under the 
Transport Rule once the final Boiler MACT-related controls were 
installed. The allowances allocated to the boiler would be additional 
allowances above the Transport Rule trading budget for the state where 
the boiler was located. As a result, the boiler would have freed-up 
allowances above the state trading budget that represent reductions 
that the boiler would have made anyway (i.e., even if the boiler had 
not opted in) and that could be sold to EGUs covered by the Transport 
Rule. In effect, the opting-in of the boiler would result in the 
conversion of the boiler's SO2 reductions from the final 
Boiler MACT rule into increased emissions above the state trading 
budget from EGUs subject to the Transport Rule.
    Commenters addressed this issue. For instance, one commenter 
suggested that SO2 reductions made by a boiler under the 
final Boiler MACT rule should be eligible for opt-in provision 
allowances under the Transport Rule trading programs. Another commenter 
stated that, given the uncertainty that reductions made by opt-in units 
would be surplus, verifiable, permanent, and enforceable, opt-in 
provisions could

[[Page 48277]]

compromise the integrity of the EGU emission reductions.
    For the reasons explained above, EPA agrees with the latter 
commenter. Further, EPA notes that none of the commenters supporting 
adoption of the opt-in provisions suggested any revision to the 
proposed opt-in provisions that would address this problem. While the 
proposed opt-in provisions would limit an opt-in unit's allocation for 
a control period by calculating the allocation using the lesser of the 
unit's pre-opt-in SO2 emission rate or the most stringent 
SO2 emission rate applicable in that control period, this 
would not address SO2 rate reductions that are not directly 
required by the final Boiler MACT rule but that are a secondary result 
of using and operating certain emission controls installed to comply 
with the HCL or Hg standards under the final Boiler MACT rule. Because 
the secondary SO2 reductions will vary depending on the type 
of controls installed and on the extent to which the controls are used, 
and a boiler may use a combination of emission controls and other 
approaches to reduce HCL or Hg emissions (such as fuel switching), EPA 
believes that it is highly unlikely that opt-in provisions could 
prevent allocation for ``anyway'' emission reductions resulting from 
compliance with the final Boiler MACT rule. EPA therefore believes that 
the final Boiler MACT rule provides a concrete example of why adoption 
of opt-in provisions could undermine the rule's objective of addressing 
emissions in each state that significantly contribute to nonattainment 
or interfere with maintenance in other states. EPA notes that the final 
Boiler MACT rule, of course, is simply one example of how allocations 
for ``anyway'' reductions could occur and undermine the statutory 
requirements of the Transport Rule.

C. Compliance Deadlines

1. Alignment With NAAQS Attainment Deadlines
    The compliance dates in the final Transport Rule are aligned with 
the attainment deadlines for the relevant NAAQS and consistent with the 
charges given to EPA by the Court in North Carolina. EPA proposed to 
require, and the final rule requires, compliance by 2014 with an 
initial phase of reductions in 2012.\57\ Sources are required to comply 
with annual SO2 and NOX requirements by January 
1, 2012 and January 1, 2014 for the first and second phases, 
respectively. Similarly, sources are required to comply with ozone-
season NOX requirements by May 1, 2012, and by May 1, 2014. 
In selecting these dates, EPA was mindful of the NAAQS attainment 
deadlines which require reductions as expeditiously as practicable and 
no later than specified dates (see 42 U.S.C. 7502(a)(2)(A) (general 
attainment dates); 42 U.S.C. 7511(a)(1) (attainment dates for ozone 
nonattainment areas)), and also mindful of the court's instruction to 
``decide what date, whether 2015 or earlier, is as expeditious as 
practicable for states to eliminate their significant contributions to 
downwind nonattainment.'' North Carolina, 531 F.3d at 930.
---------------------------------------------------------------------------

    \57\ For the annual programs, sources are required to have, by 
March 1, 2013, sufficient allowances in their accounts to cover 
their 2012 emissions. For the ozone-season program, they must have 
allowances in their accounts by December 1, 2012 to cover 2012 
ozone-season emissions. The state budgets which determine the number 
of allowances allocated to units in each state become more stringent 
for some states in 2014.
---------------------------------------------------------------------------

    1997 PM2.5 NAAQS Attainment Deadlines. For all areas 
designated as nonattainment with respect to the 1997 PM2.5 
NAAQS, the deadline for attaining that standard is as expeditious as 
practicable but no later than April 2010 (5 years after designation), 
with a possible extension to no later than April 2015 (10 years after 
designation).\58\ Many areas have already come into attainment by the 
April 2010 deadline due in part to reductions achieved under CAIR. The 
fact that the 2010 deadline will have passed before the Transport Rule 
is finalized emphasizes the importance of obtaining reductions as 
expeditiously as practicable. In addition, reductions achieved in 
upwind states by the 2014 emissions year will help downwind states 
demonstrate attainment by the April 2015 deadline.
---------------------------------------------------------------------------

    \58\ Section 172(a)(2) of the Clean Air Act provides that the 
attainment dates for areas designated nonattainment with a NAAQS 
shall be the date by which attainment can be achieved as 
expeditiously as practicable, but no later than 5 years from the 
date of designation. This section also allows the Administrator to 
extend the attainment date to the extent she determines appropriate, 
for a period no greater than 10 years from the date of designation 
as nonattainment, considering the severity of nonattainment and the 
availability and feasibility of pollution control measures. 
Designations for the 1997 PM2.5 NAAQS became effective on 
April 5, 2005. Designations for the 2006 24-hour PM2.5 
NAAQS became effective on December 14, 2009.
---------------------------------------------------------------------------

    2006 PM2.5 NAAQS Attainment Deadlines. For all areas 
designated as nonattainment with respect to the 2006 24-hour 
PM2.5 NAAQS, the attainment deadline must be as expeditious 
as practicable but no later than December 2014. Areas that fail to meet 
that deadline can request an extension to as late as December 2019.
    Upwind emission reductions achieved by the 2014 emissions year will 
help meet the December 2014 attainment deadline. In addition, the first 
phase of reductions in 2012 will help many areas attain in a more 
expeditious manner.
    Further, a deadline of January 1, 2014 also provides adequate and 
reasonable time for sources to plan for compliance with the Transport 
Rule and install any necessary controls. EPA believes that this 
deadline is as expeditious as practicable for the installation of the 
controls, if any, needed for compliance with the 2014 state emission 
budgets. (See further discussion in section V.C.2.)
    1997 Ozone NAAQS Attainment Deadlines. Ozone nonattainment areas 
must attain permissible levels of ozone ``as expeditiously as 
practicable,'' but no later than the date assigned by EPA in the ozone 
implementation rule. 40 CFR 51.903. The areas designated nonattainment 
in 2004 with respect to the 1997 8-hour ozone NAAQS in the eastern 
United States were assigned maximum attainment dates effectively 
corresponding to the end of the 2006, 2009, and 2012 ozone seasons. The 
maximum attainment deadlines for the 1997 standard run from the June 
15, 2004 effective date of designation for that standard. The time 
periods are based on the time periods provided for these 
classifications in section 181 of the Act, 45 U.S.C. 7511(a). However, 
instead of running from the 1990 date of enactment of the CAA as 
specified in section 181, our regulation provides that they run from 
the date of designation. An area's maximum attainment date is based on 
its nonattainment classification--that is, whether it is classified as 
a marginal, moderate, serious, severe, or extreme ozone nonattainment 
area. Marginal areas have three years from designation to attain the 
standard. Moderate, serious, severe, and extreme areas have 6, 9, 15, 
and 20 years, respectively. The maximum attainment deadlines associated 
with the 1997 ozone standards are June 15, 2007 for marginal areas, 
June 15, 2010 for moderate areas, and June 15, 2013 for serious areas. 
Because the actual deadline occurs in the middle of an ozone season, 
data from that ozone season is not considered when determining whether 
the area has attained by the deadline. Thus, these maximum attainment 
deadline dates effectively correspond with the end of the 2006, 2009, 
and 2012 ozone seasons. Reductions achieved or air quality improvements 
realized after those dates will not help the areas meet their maximum 
attainment deadlines.
    Many areas have already attained the standard due in part to CAIR, 
federal

[[Page 48278]]

mobile source standards, and other local, state, and federal measures. 
Other areas, however, have been reclassified to a higher classification 
either because they failed to attain by their attainment date or 
because the state requested reclassification to avoid missing an 
attainment date. Those that have not yet attained the standard now have 
maximum attainment dates ranging from June 2011 (these are the moderate 
areas that have been granted a 1-year extension due to clean data for 
the 2009 ozone season) to June 2024. The areas classified as 
``serious'' nonattainment areas have a June 2013 maximum attainment 
deadline. Areas that missed their earlier deadlines and have been 
reclassified as ``severe'' or ``extreme'' nonattainment areas now have 
maximum nonattainment deadlines of June 2019 and June 2024 
respectively. As explained above, an area with a June 2013 deadline 
would need to attain based on ozone data from the 2010-2012 ozone 
seasons, an area with a June 2019 deadline would need to attain based 
on ozone data from the 2016-2018 ozone seasons, and an area with a June 
2024 deadline would need to attain based on ozone data from the 2021-
2023 ozone seasons.
    The Transport Rule's first phase of reductions in 2012 will help 
the remaining areas with June 2013 maximum attainment deadlines attain 
the 1997 8-hour ozone NAAQS by their deadline. If EPA determines that 
an area failed to attain by the 2013 deadline, the area would be 
reclassified to severe and would be subject to the more stringent 
emission control requirements that apply to the severe classification. 
The reductions will also help areas with later deadlines attain as 
expeditiously as practicable and improve air quality in those areas.
    2012 Interim Compliance Deadline. EPA is requiring an initial phase 
of reductions starting in 2012. These reductions are necessary to 
ensure that significant contribution to nonattainment and interference 
with maintenance are eliminated as expeditiously as practicable and in 
time to help states meet their attainment deadlines. As the court 
emphasized in North Carolina, the significant contribution to 
nonattainment and interference with maintenance from upwind states must 
be eliminated as expeditiously as practicable to help downwind states 
to achieve attainment as expeditiously as practicable as required by 
the CAA. Further, reductions are needed by 2012 to help states attain 
before the June 2013 maximum attainment date for ``serious'' ozone 
nonattainment areas, to ensure states attain as soon after the original 
April 2010 attainment deadline for the 1997 PM2.5 NAAQS, and 
to help states attain before the December 2014 attainment deadline for 
the 2006 PM2.5 NAAQS.
    In addition, because this final rule will replace CAIR, EPA could 
not assume that after this rule is finalized, EGUs would continue to 
emit at the reduced emission levels achieved by CAIR. Instead, it is 
the emission reduction requirements in the proposed FIPs that will 
determine the level of EGU emissions in the eastern United States. For 
this reason also, EPA concludes that it is appropriate to require an 
initial phase of reductions by 2012 to ensure that existing and planned 
SO2 and NOX controls operate as anticipated.
    Addressing the Court's Concern about Timing. As directed by the 
Court in North Carolina, 531 F.3d 896, and as described previously, EPA 
established the compliance deadlines in the Transport Rule based on the 
respective NAAQS attainment requirements and deadlines applicable to 
the downwind nonattainment and maintenance sites.
    The 2012 deadline for compliance with the limits on ozone-season 
NOX emissions is necessary to ensure that states with June 
2013 maximum attainment deadlines get the assistance needed from upwind 
states to meet those deadlines. The 2012 deadline for compliance with 
the limits on annual NOX and annual SO2 emissions 
is necessary to ensure attainment as expeditiously as practicable in 
areas which failed to attain by the 2010 attainment deadline for the 
1997 PM2.5 NAAQS and had to request an extension to 2015.
    Similarly, the 2014 deadline for compliance with the limits on 
annual NOX and annual SO2 emissions is necessary 
to ensure that downwind states get the benefit of upwind reductions 
prior to the December 2014 maximum attainment deadline for the 2006 
PM2.5 NAAQS. It is also necessary to ensure reductions occur 
in time to assist with attainment in downwind areas that received the 
maximum 5-year extension of the 5-year attainment deadline for the 1997 
PM2.5 NAAQS (taking into account the need for reductions by 
2014 to demonstrate attainment by April 2015).
    The 2012 compliance deadline for the first-phase of annual 
NOX and annual SO2 emission reductions will 
assure the reductions are achieved as expeditiously as practicable. A 
significant amount of the emissions identified as significantly 
contributing to nonattainment or interfering with maintenance in other 
states can be eliminated by 2012. EPA believes it is appropriate to do 
so in light of the court's direction to EPA to ensure states eliminate 
such emissions as expeditiously as practicable. North Carolina 531, 
F.3d at 930. Given the time needed to design and construct scrubbers at 
a large number of facilities, EPA believes the 2014 compliance date is 
as expeditious as practicable for the full quantity of SO2 
reductions necessary to fully address the significant contribution to 
nonattainment and interference with maintenance. Requiring reductions 
in transported pollution as expeditiously as practicable, as well as 
within maximum deadlines, helps to promote attainment as expeditiously 
as practicable. This is consistent with statutory provisions that 
require states to adopt SIPs that provide for attainment as 
expeditiously as practicable and within the applicable maximum 
deadlines.
b. Public Comments and EPA Responses
    EPA received numerous comments on the proposed compliance dates. A 
number of commenters supported EPA's compliance schedule and rationale. 
Other commenters supported extending the compliance deadlines to later 
dates.
    Many commenters questioned the technical feasibility of achieving 
the required reductions by the 2012 and 2014 dates. EPA's responses to 
those comments are discussed below in section VII.C.2.
    Other commenters provided policy and legal arguments for allowing 
states to develop SIP alternatives to the FIP, and to build time for 
that SIP development and review process into the compliance schedule. 
For example, some commenters asserted that the requirement in the CAA 
for providing reductions ``as expeditiously as practicable'' must be 
balanced with CAA provisions allowing states to develop state 
implementation plans prior to EPA imposing FIPs. EPA responses to those 
comments are discussed in section X.
    Some commenters suggested that EPA had the ability to leave CAIR in 
place for a transition period, and by doing this EPA could allow for a 
longer compliance period for this rule. EPA does not believe it would 
be appropriate, in light of the Court's decision in North Carolina, to 
establish a lengthy transition period to the rule that will replace 
CAIR. Although the Court decided on rehearing to remand CAIR without 
vacatur, the Court stressed its prior decision that CAIR was deeply 
flawed and EPA's obligation to remedy those flaws. North Carolina, 550

[[Page 48279]]

F.3d 1176. Although the Court did not set a definitive deadline for 
corrective action, the Court took care to note that the effectiveness 
of its opinion would not be delayed ``indefinitely'' and that 
petitioners could bring a mandamus petition if EPA were to fail to 
modify CAIR in a manner consistent with its prior opinion. Id. Given 
the Court's emphasis on remedying CAIR's flaws expeditiously, EPA does 
not believe it would be appropriate to establish a lengthy transition 
period to the rule which is to replace CAIR.
    As relates to PM2.5, EPA received a number of comments 
on its proposal to include a 2012 deadline to ensure that emission 
reductions needed to reduce PM2.5 be achieved ``as 
expeditiously as practicable.'' Some commenters supported EPA's 2012 
deadline. Other commenters believed that it was unnecessary and 
unwarranted for EPA to impose emission reduction requirements in 
advance of the 2014 attainment date. In light of the 2014 five-year 
attainment date for the 2006 PM2.5 NAAQS (with a possible 
extension to 2019), and the possible extension to April 2015 for the 
1997 PM2.5 NAAQS, these commenters believed EPA's 2012 
emission reduction requirements for annual PM2.5 and 
NOX were not necessary. EPA disagrees with these commenters, 
for a number of reasons. First, EPA notes (supported by commenters) 
that there is a clear statutory obligation to attain ``as expeditiously 
as practicable.'' Second, EPA notes that there are feasible reductions 
available by 2012. Third, EPA believes that the substantial health and 
environmental benefits achieved by the rule underscore the importance 
of achieving the reductions as soon as possible.
    With respect to ozone, some commenters noted that the proposed rule 
required ozone reductions by 2012 for states impacting areas which 
EPA's analysis shows will attain the 1997 ozone NAAQS by 2014 without 
further controls. Those commenters questioned the importance of getting 
reductions in such states and whether the 2012 deadline is necessary. 
EPA disagrees with those comments. Except for Houston, all ozone areas 
within the region addressed by this rule have attainment dates no later 
than 2013. In effect, this means that emission reductions needed to 
attain the 1997 ozone NAAQS must be in place by the 2012 ozone season. 
EPA believes that if there are reductions available by 2012, and those 
emission reductions have in fact been identified, it is appropriate and 
necessary to ensure that those reductions are in place.
2. Compliance and Deployment of Pollution Control Technologies
    The power industry will undertake a diverse set of actions to 
comply with the Transport Rule at the start of 2012 and another set of 
actions when companies in Group 1 states comply with more stringent 
SO2 budgets at the start of 2014. In 2012, the industry will 
largely meet the rule's NOX requirements by: Operating an 
extensive existing set of combustion and post-combustion controls on 
fossil fuel-fired generators; dispatching lower emitting units more 
often; and installing and operating a limited amount of relatively 
simple NOX pollution controls in states not previously 
subject to CAIR. For the SO2 requirements, EPA anticipates 
at a minimum that coal-fired generators will operate the substantial 
capacity of advanced pollution controls already in place or scheduled 
for 2012 use; some units will also elect to burn lower-sulfur coals; 
and the fleet will increase dispatch from lower-sulfur-emitting units 
as well as from natural gas-fired generators. EPA provides a more 
detailed explanation below of how fuel switching to lower sulfur coals 
factored in to the design of the final Transport Rule.
    By 2014, EPA's budgets under the Transport Rule will sustain 
previous NOX and SO2 reductions as well as 
account for reductions from additional advanced NOX and 
SO2 controls that are driven by other state and federal 
requirements. In addition to these reductions, companies in Group 1 
states are also projected to add a limited amount of advanced 
SO2 controls in 2014 that will be discussed below.
    EPA's expectations are supported by the IPM analysis reported in 
this rule's RIA (see Chapter 7). Notably, since EPA has established a 
cap and trade control system for lowering NOX and 
SO2 emissions, individual owners and operators of covered 
units have some flexibility in meeting the program's requirements as 
needed and are free to find alternative ways to comply. The RIA clearly 
shows a viable known pathway for owners and operators to comply at 
reasonable costs, although it is not the only compliance pathway 
possible under this flexible regulation that could deliver the emission 
reductions required under the rule. Notably, by 2014 and beyond, the 
power industry may also augment the projected compliance efforts with 
programs aimed at improving energy efficiency.
    Table VII.C.2-1--shows EPA's projection of the amount of existing 
coal-fired generating capacity in gigawatts (GW) that may retrofit 
various systems for compliance with this rule.

                           Table VII.C.2-1--Projected Potential Air Pollution Control (APC) Retrofits for Transport Rule \59\
--------------------------------------------------------------------------------------------------------------------------------------------------------
     Capacity retrofitted by              Wet FGD                 Dry FGD                   DSI                     SCR            LNB/OFA  improvements
--------------------------------------------------------------------------------------------------------------------------------------------------------
January 1, 2012.................  ......................  ......................  ......................  ......................  10 GW
January 1, 2014.................  5.7 GW................  0.2 GW................  3.0 GW................  0 GW..................
--------------------------------------------------------------------------------------------------------------------------------------------------------

    EPA received proposal comments expressing a concern about the 
feasibility of deploying retrofit air pollution control (APC) 
technologies in the time frames available between the final date of 
this rule and the compliance dates. As discussed below, EPA believes 
that it is feasible for the electric power sector and its APC supply 
chain to either make most of the projected retrofits in time to meet 
the 2012 and 2014 compliance deadlines, or to comply by other means.
---------------------------------------------------------------------------

    \59\ GW: Gigawatts of capacity retrofitted; FGD: Flue gas 
desulfurization (SO2 control); DSI: Dry sorbent injection 
(SO2 control); SCR: Selective catalytic reduction 
(NOX control); LNB/OFA: Low-NOX burner and/or 
overfire air (NOX controls).
---------------------------------------------------------------------------

a. 2012 Power Industry Compliance
    EPA's analysis of emission reductions available in 2012 assumes 
year-round operation of existing post-combustion pollution controls in 
states covered for PM2.5 and ozone-season operation of 
NOX post-combustion controls in states covered for ozone. 
EPA also modeled emission reductions available in 2012 at the $500/ton 
threshold for SO2, $500/ton for annual NOX, and 
$500/ton for ozone-season NOX.
    For SO2, EPA believes that reductions associated with 
the following methods of control are available and will be used

[[Page 48280]]

as compliance strategies to meet the 2012/2013 budgets: (1) Operation 
of existing controls year-round in PM2.5 states, (2) 
operation of scrubbers that are currently scheduled to come online by 
2012, (3) some sources switching to lower-sulfur coal (see section 
VII.C.2.c that follows), and (4) changes in dispatch and generation 
shifting from higher emitting units to lower emitting units. EPA 
modeling and selection of a $500/ton cost threshold includes all 
existing and planned controls operating year round (items 1 and 2). It 
also reflects an amount of coal switching and generation shifting that 
can be achieved for $500/ton. This set of expected actions was 
confirmed in the detailed modeling of EPA's final remedy in the RIA and 
can be reviewed there.
    The power sector is already strongly positioned to achieve the 
Transport Rule state budgets presented in section VI.D through at least 
three distinct strategies. First, the sector will optimize its use of 
the large proportions of advanced pollution controls already present 
throughout the fleet. Second, the sector will take advantage of the 
substantial new pollution control technology that is already on the way 
for deployment by 2012. Third, the remainder of the fleet will flexibly 
adopt the most economic low-emitting fuel mix available at each unit to 
deliver cost-effective emission reductions complementing the reductions 
achieved from optimized use of the fleet's pollution control 
technology. The state maps in Chapter 7 of this rule's Regulatory 
Impact Analysis demonstrate how these emission reduction strategies for 
2012 will build off of the sector's historic trend toward cleaner 
generation profiles. Also, the detailed unit-level projection files 
from EPA's IPM power sector modeling of the Transport Rule remedy 
(found in the docket for this rulemaking) show how EGUs adopt these 
strategies to not only reach the 2012 budgets, but in fact in many 
states overcomply with the budgets and build up a bank of allowances 
under the programs for future flexibility.
    The following paragraphs illustrate the degree to which the 
existing fleet is already prepared to adopt these emission reductions 
in 2012 in order to attain the required emission reductions for 
SO2, annual NOX, and ozone-season NOX 
under the Transport Rule. More specifically, the illustrative 
paragraphs demonstrate emission reduction pathways for coal capacity to 
optimize or increase operation of existing control technology, timely 
implement existing plans to bring additional control technology on 
line, and to cost-effectively make use of lower-emitting fuel 
alternatives.
    Of the 240 GW of coal capacity in the Transport Rule region covered 
for fine particles, approximately 110 GW--more than 45 percent--had 
existing advanced pollution control for SO2 already in place 
in 2010, including scrubbers (FGD), dry sorbent injection (DSI), or 
circulating fluidized bed boilers. Of this controlled coal capacity, 
EPA expects a significant portion will improve emission rates through 
either increased use of control technology and/or additional fuel 
switching. EPA notes that an additional 39 GW of advanced 
SO2 controls in the region are scheduled to come online over 
the 2010-2012 timeframe and will also assist in meeting 2012 emission 
reduction requirements. Thus, by 2012 more than half of affected coal 
capacity--152 GW--will be operating with advanced SO2 
control equipment. Additionally, EPA expects approximately 40 GW of 
uncontrolled coal capacity in the region to take advantage of the 
existing coal supply infrastructure, possibly switching coal use or 
coal blending behaviors to make cost-effective reductions in 
SO2 emission rates where economic to respond to the 
Transport Rule 2012 emission reduction requirements.
    EPA notes that approximately 136 GW of the 240 GW--more than 56 
percent--of coal capacity in the Transport Rule region covered for fine 
particles had existing advanced pollution control for NOX 
already in place in 2010, including selective catalytic reduction 
(SCR), selective non-catalytic reduction (SNCR), or circulating 
fluidized bed boilers. Of this capacity, EPA anticipates a significant 
portion will improve their NOX emission rate through 
increased operation of these existing controls. Additionally, EPA notes 
that an additional 21 GW of SCR and 4 GW of enhanced combustion 
controls (including low-NOX burners and overfire air) are 
scheduled to come online in the region during the 2010-2012 timeframe, 
bringing the total region's coal capacity operating with NOX 
emission reduction technology to 158 GW (more than 65 percent of total 
coal capacity in the Transport Rule fine particle region). EPA also 
projects that approximately 13 GW of coal capacity will make some 
reduction in their NOX emission rates by enhancing 
performance of existing combustion controls or SNCR, or by fuel 
switching.
    In the Transport Rule states covered under the ozone-season 
program, approximately 145 GW of the 260 GW (more than 55 percent) of 
coal capacity had existing NOX control technology in place 
in 2010. EPA expects a significant portion of that capacity to achieve 
emission reductions during the 2012 ozone-season through improved 
operation of SCR. Additionally, in the Transport Rule ozone region 
there will be approximately 21 GW of additional advanced NOX 
control installations and 7 GW of additional combustion control 
improvements or installations coming online during the 2010 to 2012 
time frame. EPA projects that 17 GW of coal capacity in the Transport 
Rule ozone region will reduce NOX emission rates by 
enhancing performance of existing combustion controls or SNCR or by 
fuel switching.
    For NOX, EPA has also concluded that it is appropriate 
to require reductions through a limited amount of combustion control 
improvements, and in some cases, retrofits such as low-NOX 
burners (LNB) and/or overfire air (OFA). EPA recognizes that the 6-
month time frame between rule finalization and start of the first 
compliance period would not allow for the installation of a major post-
combustion NOX control such as SCR. Assumed improvements and 
retrofits for the January 1, 2012 deadline for annual NOX 
reductions therefore only involve the much simpler LNB/OFA control 
modifications or installations. Alternatively, some plant owners might 
choose to achieve NOX reductions in a similar time period 
through an even simpler retrofit--SNCR.\60\
---------------------------------------------------------------------------

    \60\ David L. Wojichowski, SNCR System--Design, Installation, 
and Operating Experience http://www.netl.doe.gov/publications/proceedings/02/scr-sncr/wojichowski-1.pdf.
---------------------------------------------------------------------------

    Although the improvements, and in some cases, installation of 
combustion controls would be an economic means of achieving emission 
reductions, these specific controls are not required for compliance 
purposes under the final Transport Rule remedy. Individual sources may 
comply through other measures (such as purchasing additional 
allowances) in the event that it takes more than 6 months for 
installation of a given combustion control. The vast majority of 
covered sources already have combustion controls installed; therefore, 
the NOX reductions associated with these incremental control 
improvements and installations are small.

[[Page 48281]]

    Based on the Transport Rule's geography, EPA estimates that 
approximately 10 GW of coal-fired units may improve, and in some cases, 
install LNB/OFA specifically in reaction to the Transport Rule 
NOX caps. EPA reflects the effects of these installations in 
the 2012 annual and ozone-season NOX budgets, which would 
yield reductions of approximately 28,000 tons of annual NOX 
and 14,000 tons of ozone-season NOX. EPA assumes these 
controls are cost effective at $500/ton and that they should be 
incentivized through budgets given the 2013 attainment deadline for 
ozone areas classified as ``serious.'' Once installed, LNB/OFA operates 
any time the boiler is fired and thus yields NOX reductions 
beyond the ozone season alone.
    In the proposal's LNB technical support document,\61\ EPA observes 
that LNB and/or OFA installations, burner modifications, or other 
NOX reduction controls would likely have to be installed 
during fall 2011 or spring 2012 outages in order to achieve significant 
reductions for 2012. While this 6-month schedule is aggressive, 
industry has shown that it can be met. For example, Limestone Electric 
Generating Station Unit 2, an 820 MW tangentially-fired lignite unit, 
was retrofitted with Foster Wheeler's Tangential Low NOX 
(TLN3) system in less than six months, including engineering, 
fabrication, delivery and installation.\62\ Harlee Branch Unit 4, a 535 
MW cell-fired unit, was retrofitted with Riley Power's low-
NOX Dual Air Zone CCV burners on a similar schedule.\63\ 
These are tangentially-fired and wall-fired units, respectively, 
representative of the unit types that might make LNB/OFA improvements 
for compliance with this rule. Although such 6-month schedules can be 
achieved on some units, under favorable circumstances, historical 
projects suggest a more typical schedule would be 12 to 16 months for 
the contractor's portion of the work.\64\ A plant owner's project 
planning and procurement work in advance of a contract award would 
typically involve several additional months. On the other hand, there 
are other approaches that can also be implemented in a short time frame 
to achieve significant NOX reduction. As mentioned above, 
relatively simple SNCR systems can be installed quickly; and the re-
tuning or upgrading of existing combustion control systems can often 
provide significant NOX reductions and can be performed 
quickly.\65\
---------------------------------------------------------------------------

    \61\ Technical Support Document (TSD) for the Transport Rule, 
Docket ID No. EPA-HQ-OAR-2009-0491, Installation Timing for Low 
NOX Burners (LNB).
    \62\ R. Pearce, J. Grusha, Reliant Energy Tangential Low 
NOX System at Limestone Unit 2 Cuts Texas Lignite, PRB 
and Pet Coke NOX, http://www.fwc.com/publications/tech_papers/files/tp_firsys_01_02.pdf.
    \63\ B. Courtemanche, et al., Reducing NOX Emissions 
and Commissioning Time on Southern Company Coal Fired Boilers With 
Low NOX Burners and CFD Analysis, http://www.babcockpower.com/pdf/t-182.pdf.
    \64\ M. O'Donnell, Babcock & Wilcox Company, (personal 
communication with EPA staff, February 22, 2011).
    \65\ N.C Widmer, et al., Coal Power, October 8, 2009, http://www.coalpowermag.com/ops_and_maintenance/Zonal-Combustion-Tuning-Systems-Improve-Coal-Fired-Boiler-Performance_226.html.
---------------------------------------------------------------------------

    As stated above, EPA believes that LNB/OFA modifications or 
retrofits would be possible during the 6-month interim between rule 
signature and the start of the first compliance period, particularly 
for those ``early movers'' who have initiated LNB projects based on the 
proposed rule. However, as shown in Table VII.C.2-2, below, even if all 
LNB modifications or installations are delayed until the beginning of 
the 2012 ozone season, the reductions only represent 1 percent of most 
covered states' annual NOX budgets, and no more than 11 
percent of any affected state's annual NOX budget. Under 
such a scenario, these delayed reductions would still be well within 
the 18 percent variability limit applied to each state's annual 
NOX budget. In light of this limited consequence and the 
supporting material above, EPA includes LNB-driven NOX 
reductions in both annual and ozone-season NOX budgets for 
2012.

 Table VII.C.2-2--Earliest Reductions Assumed From LNB Installations in the Transport Rule States Subject to the
                                              Annual NOX Program *
----------------------------------------------------------------------------------------------------------------
                                                             NOX reductions                        Percent of
                                                                from LNB                          budget met by
                                                             operation from   Annual NOX state    earliest LNB
                                                              January-April    budget  (tons)      reductions
                                                                 (tons)                             (percent)
----------------------------------------------------------------------------------------------------------------
Georgia...................................................               646            62,010                 1
Iowa......................................................               567            38,335                 1
Kansas....................................................             2,131            30,714                 7
Minnesota.................................................             2,303            29,572                 8
Nebraska..................................................             3,008            26,440                11
                                                           -----------------------------------------------------
    Region-wide Total.....................................             8,656         1,245,869                 1
----------------------------------------------------------------------------------------------------------------
* Based on EPA IPM Analysis of Final Transport Rule.

b. 2014 Power Industry Compliance
    EPA projects that compliance with 2014 requirements for 
NOX will result largely from operation of existing and 
future controls required by state and other federal requirements, as 
well as the appropriate dispatch of the electric generation fleet. EPA 
does not project additional NOX pollution control retrofits 
aside from about 10 GWs of combustion control improvements or retrofits 
projected for the 2012 compliance period. To comply with the rule's 
SO2 requirements, EPA projects that the power industry will 
rely on existing controls, operate newly installed advanced controls 
necessary for other binding state and federal requirements, rely more 
on relatively lower sulfur coals, and dispatch lower-emitting 
generation units. In Group 1 states, industry is projected to increase 
switching to lower sulfur coals and install a limited amount of 
additional scrubbers and other advanced pollution control technology. 
EPA's assessment of the industry's ability to install SO2 
pollution controls in 2014 and undertake the projected coal switching 
follows below.
    EPA's modeling of least-cost compliance with the state budgets 
under the Transport Rule projects approximately 5.9 GW of FGD systems 
and lesser amounts of other technologies will be retrofitted by 2014

[[Page 48282]]

for compliance with the Transport Rule.66 67 EPA's schedule 
assumptions for these larger more complex projects were developed in an 
earlier study and mentioned in the proposal: 27 months for retrofitted 
wet FGD and 21 months for SCR.\68\ Note that a dry FGD system, due to 
its relatively simpler configuration and lesser cost, would typically 
take somewhat less time to retrofit than wet FGD.
---------------------------------------------------------------------------

    \66\ Nearly all of the 5.9 GW of FGD retrofits are comprised by 
some 12 units at 7 plants (Beckjord, Muskingum River, Homer City, 
Rockport, Kammer, Danskammer, and Will County).
    \67\ As noted elsewhere in this preamble, the projected impacts 
of this final rule presented in the preamble do not reflect minor 
technical corrections to SO2 budgets in three states (KY, 
MI, and NY) and assumed preliminary variability limits that were 
smaller than the variability limits finalized in this rule. EPA 
conducted sensitivity analysis factoring in these corrections; the 
results of this analysis include a small increase of about 700 MW of 
additional wet FGD retrofit projected for 2014. This projected 
additional retrofitting capacity is already required to retrofit 
under a consent decree and should therefore have already conducted 
advanced retrofit planning. EPA therefore believes that this 
incremental projected retrofit behavior (factoring in the technical 
corrections made after the main impact analyses were conducted) is 
feasible by 2014 for the same reasons presented in this section 
regarding the projected retrofit behavior from the main analysis of 
the final rule.
    \68\ EPA, Engineering and Economic Factors Affecting the 
Installation of Control Technologies for Multipollutant Strategies; 
EPA-600/R-02/073 October 2002.
---------------------------------------------------------------------------

    As discussed below, EPA believes that its schedule assumptions 
remain reasonable expectations for sources that have completed most of 
their preliminary project planning and can quickly make commitments to 
proceed. These schedules do not include the extensive time that some 
plant owners might spend in making a decision on whether or not to 
retrofit. They do include the time needed to make a final confirmation 
of the type of technology to be used at a particular site, to prepare 
bid requests, award contracts, perform engineering, obtain construction 
and operating permits (in parallel with project activities), perform 
construction, tie-in to the existing plant systems, and perform 
integrated systems testing.
    EPA received comments on the proposed rule indicating that some 
past single-unit APC retrofits had considerably longer schedules, with 
a few exceeding 48 months. EPA engineering staff have extensive 
experience with power plant and APC system design, construction, and 
operation. Based on that experience, EPA can observe that in the 
absence of a compelling deadline or major economic incentive, many 
large project schedules are considerably longer than necessary. Given 
further observations as explained below, EPA believes it is reasonable 
to expect that almost all future APC retrofits can be completed far 
more quickly than they were in recent history. EPA's perspective on 
this matter derives in part from a comparison of longer APC schedules 
(as provided by some commenters) to the project schedule for an entire 
new coal-fired unit, including its APC systems. Springerville Unit 3, 
for example, is a new 400 MW subbituminous coal-fired unit with SCR and 
dry FGD that became operational in July 2006, some 33 months after the 
turnkey engineering-construction contractor was given a notice to 
proceed with engineering.\69\ Springerville was clearly on an 
accelerated schedule, as its original planned schedule was about 38 
months. Another example is Dallman Unit 4, a high-sulfur bituminous 
coal-fired 200 MW unit with SCR, fabric filter, wet FGD, and wet ESP. 
Dallman Unit 4 was first synchronized in May 2009, several months ahead 
of schedule, and about 36 months after its turnkey contractor placed 
initial major equipment orders.\70\ The main point here is that recent 
APC project schedules, and those of large complex power projects, can 
be significantly accelerated. Because the scope and complexity of the 
work involved for an entire new coal unit and its APC systems is 
perhaps five times greater than that of a retrofit wet FGD system 
alone, EPA believes it is reasonable to expect that even the most 
complex retrofit APC project can be significantly accelerated as well. 
Additional factors are discussed below that further support the 
feasibility of installing by 2014 the 5.9 GW of FGD retrofits projected 
for this rule.
---------------------------------------------------------------------------

    \69\ Best Coal-fired Projects, Springerville Unit 3 Expansion 
Project, Power Engineering, November 2006, http://www.powergenworldwide.com/index/display/articledisplay/282547/articles/power-engineering/volume-111/issue-1/features/projects-of-the-year.html.
    \70\ http://www.cwlp.com/electric_division/generation/Dallman%204%20Power%20Plant%20of%20the%20Year.pdf.
---------------------------------------------------------------------------

    Although IPM modeling provides reliable estimates on a regional 
basis, and cannot be as accurate at the level of individual plants or 
units, it is informative and relevant to consider IPM's plant level 
projections in this case. Although the IPM-projected retrofits named 
below may not actually occur, IPM projects that they would be economic 
and would allow industry to meet the tighter SO2 emission 
standards in Group 1 states in 2014. EPA notes that the owners of the 
particular plants mentioned below (Duke Energy, AEP, Edison 
International) are large, experienced, versatile utilities that have 
done considerable advance planning and should also have above-average 
flexibility to comply with state budgets across their fleets. EPA would 
expect such owners to have relatively little difficulty in permitting 
and financing FGD retrofits.
    Of the Transport Rule-related FGD retrofits, 0.2 GW is projected to 
use dry FGD, which EPA expects to be simpler and quicker to install 
than wet FGD. Half of the 5.9 GW (Muskingum, Rockport) has already been 
committed under consent decrees to add controls or retire; \71\ and EPA 
reasonably believes that significant preliminary project planning work 
has already been done for those projects. An additional 1,200 MW (Homer 
City) had completed project planning and was ready to proceed in 2007, 
before putting the project on hold.\72\ The latter plant is now facing 
EPA legal action and the possibility of a required expeditious FGD 
retrofit.\73\ Thus, of the 5.9 GW of projected FGD retrofits resulting 
from this rule, nearly 75 percent appears to be in good position for an 
early start of construction, and over 3 GW of that would be bringing 
forward already committed compliance start dates.
---------------------------------------------------------------------------

    \71\ http://www.epa.gov/compliance/resources/decrees/civil/caa/americanelectricpower-cd.pdf.
    \72\ http://www.businesswire.com/news/home/20060731005193/en/Contractors-Selected-Install-Emissions-Control-System-Pennsylvania.
    \73\ http://www.epa.gov/Compliance/resources/complaints/civil/caa/homercity-cp.pdf.
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    Any of the above mentioned potential retrofits or any other unit 
that might choose to retrofit FGD for a January 2014 compliance date 
will likely have to use various methods to accelerate the project 
schedule. Such methods could include the use of parallel permitting, 
overtime and/or two-shift work schedules during construction, and 5- or 
6-day work weeks instead of the 4-day x 10-hour schedules often used to 
minimize cost when time is not of the essence. Increased use of offsite 
modularization and pre-fabrication of APC components could also shorten 
schedules and reduce job hours.
    EPA believes that the January 1, 2014 compliance date is as 
expeditious as practicable for the sources installing large, complex 
control systems. The following additional observations support EPA's 
expectation that the limited 5.9 GW of FGD retrofits can be realized in 
the 30 month interim between rule signature and the start of 2014:
     There are documented instances of large, complex wet FGD 
retrofits being deployed in less than 30-months (excluding the time for 
owners' project

[[Page 48283]]

planning). Examples are Killen Station Unit 2,\74\ and Asheville Unit 
1.\75\
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    \74\ Black & Veatch, http://www.bv.com/News_3_Publications/News_Releases/2005/0503.aspx (start), http://www.bv.com/wcm/press_release/07252007_9767.aspx (completion).
    \75\ PowerGenWorldwide, Projects of the Year, January 1, 2007, 
http://www.powergenworldwide.com/index/display/articledisplay/282547/articles/power-engineering/volume-111/issue-1/features/projects-of-the-year.html.
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     In 2009 the APC supply chain deployed more than six times 
more GW capacity of FGD and SCR controls than the 5.9 GW of FGD that 
would be deployed by 2014 under this Rule.
     The APC supply chain has seen a 2-year decline in 
deployments since its peak in 2009, but in 2011 is nonetheless putting 
into service about three times more GW capacity of FGD and SCR controls 
than the 5.9 of FGD that would be deployed under this Rule.
     Because the supply chain has been in decline, but remains 
quite active, there are now adequate supply chain resources available 
that can be quickly reengaged to support a rapid deployment of 5.9 GW 
of FGD.
    EPA recognizes that the installation of any amount of scrubbers in 
this short time frame will require aggressive action by plant owners 
and that the owners who can meet this schedule will already have done 
their project planning and will be ready to place orders. An example of 
such ``early movers'' was seen in the power sector's anticipation of 
CAIR. EPA data indicate that solely CAIR-driven FGD and SCR deployments 
of about 6 GW occurred within two and one-half years after CAIR's 
finalization in mid-2005, showing that at least 20 percent of the total 
CAIR-only controls effort through a 2010 compliance date was 
sufficiently planned for installation to start before or immediately 
upon finalization of the rule. EPA reasonably expects that similar 
advance planning has already been done for units that would retrofit 
under this rule.
    In the event that a particular control installation requires 
additional time into 2014 to come online, EPA believes compliance would 
not be jeopardized given the ability of sources to purchase allowances 
during that time. This approach could be supported by some sources with 
FGD that have the ability to increase their SO2 removal 
above historic rates, perhaps through relatively low cost upgrades to 
improve scrubber effectiveness, or by operating scrubbers at higher 
chemistry ratios. The ability of sources to temporarily or permanently 
substitute dry DSI for FGD serves as another backstop for any 
feasibility issues regarding FGD. Note that the updated modeling for 
this rule projects the addition by 2014 of about 3 GW of DSI for 
SO2 control using trona or other sorbent. DSI is a 
relatively low capital cost technology that readily can be installed in 
the time frame available for compliance.76 77
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    \76\ ICAC letter to Senator Carper, November 3, 2010, http://www.icac.com/files/public/ICAC_Carper_Response_110310.pdf.
    \77\ Assessment of Technology Options Available to Achieve 
Reductions of Hazardous Air Pollutants, URS Corporation, April 5, 
2011, http://www.supportcleanair.com/resources/studies/file/4-8-11-URSTechnologyReport.pdf.
---------------------------------------------------------------------------

    It should also be noted that most APC retrofits will involve a 
source outage for final ``tie-in'' of retrofitted systems to existing 
systems, during which time emissions from the affected units are zero. 
For some sources, the duration of this tie-in outage may effectively 
extend the deadline by which all of the projected emission reductions 
need to occur.
    Although EPA believes that installation of 5.9 GW of FGD at 
facilities by January 1, 2014 is feasible, EPA also conducted an IPM 
sensitivity analysis to examine a scenario in which FGD retrofitting by 
2014 is not allowed. Results of EPA's ``no FGD build in 2014'' analysis 
indicate that if the power industry were subjected to the requirements 
of this rule without an FGD retrofit option for compliance until after 
2014, covered units would still be able to meet the Transport Rule 
requirements in every state while respecting each state's assurance 
level. (See the docket to this rulemaking for the IPM run titled ``TR--
No--FGD-- in2014--Scenario--Final.'')
    In this scenario without the availability of new FGD by 2014, 
sources in covered states complied with the Transport Rule budgets by 
using moderate additional amounts of DSI retrofits, switching to larger 
shares of sub-bituminous coal, and dispatching larger amounts of 
natural gas-fired generation in lieu of the FGD retrofits that are 
projected as being most economic under modeling of the Transport Rule 
remedy. Because new FGD capacity is included in EPA's projection of the 
least-cost set of SO2 emission reductions required in Group 
1 states, the ``no FGD'' sensitivity scenario did project higher system 
costs, although these costs were still substantially lower than the 
remedy EPA modeled in the Transport Rule proposal.
    The ``no FGD'' analysis indicates that while the ability of Group 1 
states to meet their 2014 SO2 budgets is facilitated by FGD 
retrofits, they are by no means required, nor is Transport Rule 
compliance jeopardized by their absence. Even under a scenario in which 
sources fail to complete FGD retrofits by 2014, sources in the affected 
states would have other compliance options available at reasonable cost 
to meet the state's budget requirements. This analysis shows that Group 
1 states would be able to comply with their 2014 SO2 budgets 
by relying on other emission reduction opportunities that do not 
require FGD retrofits. EPA analysis confirms that those alternatives 
are feasible both in terms of cost and timing.
    Finally, EPA recognizes that, when finalized later this year as 
currently scheduled, the Mercury and Air Toxics Standards (MATS) will 
require significant retrofit activity at covered sources in the power 
sector with a 2015 compliance date for that rule. EPA's projections of 
retrofit activity under the final Transport Rule are highly compatible 
with its projections of retrofit activity under the proposed MATS 
(which included the proposed Transport Rule in its baseline). EPA 
therefore anticipates that the Transport Rule's projected retrofit 
activity will not only be the least-cost compliance pathway to meeting 
state budgets in 2014 but will also accelerate emission reductions 
subsequently required by the effective date of MATS. The final 
Transport Rule's projected 2014 retrofit installations will also 
further incentivize the power sector to ramp up its retrofit 
installation capabilities to achieve broader deployment of the 
projected pollution control retrofits under the proposed MATS.
    Considering all the reasons given above, EPA has concluded that the 
2014 requirements for SO2 emissions in the states covered by 
the Transport Rule are reasonable and can be met by the power industry 
by a variety of means.
c. Coal Switching for SO2 Compliance in 2012 and 2014
    Coal switching is another mechanism which can be used along with 
operating pollution controls in 2012 for compliance. It will be a 
complementary activity by many coal-fired units alongside of operating 
pollution controls and the addition of more scrubbers and DSI in 2014.
    In the proposal, EPA noted that coal switching could serve as a 
compliance mechanism for 2012. EPA requested comment on the 
reasonableness of EPA's assumption that coal switching will have 
relatively little cost or schedule impact on most units. EPA received 
substantial comment suggesting that the coal switching and coal 
blending projected by EPA modeling are not feasible for all units,

[[Page 48284]]

and that, if feasible, would often incur a cost through the derating of 
the unit associated with the switch to a lower sulfur coal or coal 
blend. Additionally, sources indicated that coal switching by 2012 
would not always be possible in the six month window between final rule 
signature and start of compliance. These feasibility concerns stemmed 
from restrictions included in existing coal supply contracts and from 
boiler design constraints that may hinder coal switching within a 6 
month window.
    EPA agrees with these concerns and revised its IPM modeling to 
limit coal switching capability in 2012 for particular units that may 
have trouble switching coals or coal blends in a six month time frame. 
A cost adder was also included in the IPM modeling for coal switching 
to capture the potential cost burden of deratings that might accompany 
switching to a very low sulfur subbituminous coal or coal blend.
    A particular commenter concern regarding switching to lower sulfur 
within the eastern bituminous coals related to a possible impact on the 
performance of a cold-side electrostatic precipitator (ESP). Some ESPs 
that operate at acceptably high collection efficiency when using a 
high- or medium-sulfur bituminous coal may experience some loss in 
collection efficiency when a lower sulfur coal is used. Whether this 
occurs on a specific unit, and the extent to which it occurs, would 
depend on the design margins built into the existing ESP, the 
percentage change in coal sulfur content, and other factors. In any 
case, industry experience indicates that relatively inexpensive 
practices to maintain high ESP performance on lower sulfur bituminous 
coals are available and can be used successfully where necessary. These 
include a range of upgrades to ESP components and flue gas 
conditioning.\78\ EPA therefore assumes that it will not be necessary 
for units that switch from higher to lower sulfur bituminous to make a 
costly replacement of the ESP.
---------------------------------------------------------------------------

    \78\ Assessment of Technology Options Available to Achieve 
Reductions of Hazardous Air Pollutants, URS Corporation, April 5, 
2011, http://www.supportcleanair.com/resources/studies/file/4-8-11-URSTechnologyReport.pdf.
---------------------------------------------------------------------------

    Coal switching as a SO2 compliance option might also 
include switching from bituminous to subbituminous coal. EPA's analysis 
does not assume that a unit designed for bituminous can switch to (very 
low sulfur) subbituminous coal unless the unit's historical data 
demonstrate that capability in the past. EPA assumes that units with 
that demonstrated capability have already made any investments needed 
to handle a switch back to the use of subbituminous coal at a similar 
percentage of its heat input as in the past. For IPM analysis in the 
final rule EPA also introduced a coal switching option that assumes 
that units can increase a historically low percentage use of 
subbituminous to a ``maximum'' level, if economic. This option includes 
an appropriate derate in output, increase in heat rate, and additional 
capital and operating costs. Details of this and other IPM updates for 
this rule are provided in the IPM Modeling Documentation in the docket 
for this rulemaking (``Documentation Supplement for EPA Base Case 
v.4.10--FTransport--Updates for Final Transport Rule'').
    Some commenters also expressed concern with the assumption that 
coal-switching from lignite to subbituminous is a cost-effective or 
feasible emission reduction strategy, particularly at Texas EGUs. EPA 
carefully considered these comments and adjusted its modeling of cost-
effective reductions to address this concern. Specifically, EPA made 
adjustment in the model so that it assumes coal-switching is not a 
compliance option at the specific units where commenters identified 
technical barriers to subbituminous coal consumption. The Transport 
Rule emission budgets are based on this adjusted modeling which does 
not assume any infeasible coal-switching from lignite to subbituminous. 
In addition, EPA's analysis of cost-effective reductions in each state 
presented in section VI.B shows that Texas is capable of cost-
effectively meeting its Transport Rule emission budgets; however, EPA 
also conducted sensitivity analysis that shows Texas can also achieve 
the required cost-effective emission reductions even while maintaining 
current levels of lignite consumption at affected EGUs. More details 
regarding this analysis, including a table comparing key parameters 
between the main Transport Rule remedy analysis and this Texas lignite 
sensitivity, can be found in the response to comments document and the 
IPM model output files included in the docket for this rulemaking.

D. Allocation of Emission Allowances

    Under the final rule, EPA distributes a number of SO2, 
annual NOX, and ozone-season NOX emission 
allowances to covered units in each state equal to the SO2, 
annual NOX, and ozone-season NOX budgets for 
those states. These budgets are addressed in section VI.D of this 
preamble. This section discusses the methodology EPA uses to allocate 
allowances to covered units in each state.
    As discussed later in section VII.D.2, EPA is setting aside a base 
2 percent of each state's budgets for allowance allocations for new 
units, with 5 percent of that 2 percent, or 0.1 percent of the total 
state budget being set aside for new units located in Indian country. 
To this base 2 percent, EPA is setting aside an additional percentage 
on a state-by-state basis, ranging from 0 to 6 percent (yielding total 
set asides of 2 percent to 8 percent), for units planned to be built. 
The remainder of the state budget is allocated to existing units. 
Tables VI.D.-3 and VI.D.-4 in this preamble show the SO2, 
annual NOX, and ozone-season NOX budgets for each 
covered state (without the variability limits). In allocating 
allowances to existing and new units, EPA distributes four discrete 
types of emission allowances for four separate programs: SO2 
Group 1 allowances, SO2 Group 2 allowances, annual 
NOX allowances, and ozone-season NOX allowances.
    In the SO2 Group 1 and SO2 Group 2 programs, 
each SO2 allowance authorizes the emission of one ton of 
SO2 in that vintage year or earlier and is usable for 
compliance only in the program for which the allowance was issued. In 
the annual NOX program, each annual NOX allowance 
authorizes the emission of one ton of NOX in that vintage 
year or earlier in that program. In the ozone-season NOX 
program, each ozone-season NOX allowance authorizes the 
emission of one ton of NOX during the regulatory ozone 
season (May through September for this final rule) in that vintage year 
or earlier for that program.
    In each of the four trading programs, a covered source is required 
to hold sufficient allowances (issued in the respective trading 
program) to cover the emissions from all covered units at the source 
during the control period. EPA assesses compliance with these 
allowance-holding requirements at the source (i.e., facility) level.
    This section explains how, in this final rule, EPA allocates a 
state's budget to existing units and new units in that state. This 
section also describes the new unit set-asides and Indian country new 
unit set-asides in each state, allocations to units that are not 
operating, and the recordation of allowance allocations in source 
compliance accounts.
1. Allocations to Existing Units
    This subsection describes the methodology EPA will use in the FIPs 
finalized in this action to allocate to

[[Page 48285]]

existing units.\79\ The same methodology will be used to allocate 
allowances to existing units for all four trading programs.
---------------------------------------------------------------------------

    \79\ In this rule, existing units are defined as covered units 
that commenced commercial operation prior to January 1, 2010. As 
explained in greater detail in Section VII.B. of this preamble, EPA 
decided to use this definition to ensure that EPA would have at 
least 1 full year of quality-assured data on which to base a unit's 
allocation.
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    For the reasons explained below, EPA has decided to base 
allocations made under the FIPs on historic heat input, subject to a 
maximum allocation limit to any individual unit based on that unit's 
maximum historic emissions. This methodology gives each existing unit 
an allocation equal to its share of the state's historic heat input for 
all the covered units in the program, except where that allocation 
would exceed its maximum historic emissions; this methodology 
constrains the heat input-based allocations from exceeding any unit's 
maximum historic emissions. Further detail on the implementation of 
this approach is provided in section VII.D.1.c below as well as in the 
Allowance Allocation Final Rule TSD in the docket for this rulemaking. 
All existing-unit allocations for 2012 will be made pursuant to the 
FIPs. However, as described in section X, states may submit SIPs or 
abbreviated SIPs to use different allocation methodologies for 
allowances of vintage year 2013 and later.
a. Summary of Allocation Methodologies and Comments
    EPA took comment on three distinct allocation methodologies for 
existing units. The first--an emissions-based option--was presented in 
the original Transport Rule proposal (75 FR 45309). The second and 
third--heat input option 1 and heat input option 2--were presented in a 
Notice of Data Availability (76 FR 1113). EPA received numerous 
comments on all three options.
i. Emission-Based Allocation Methodology
    The emission-based option presented in the original Transport Rule 
proposal would base allowance allocations to existing units on each 
covered unit's calculated emission ``share'' of that state's budget for 
a given pollutant under the Transport Rule. The proposed rule stated 
that ``for 2012, each existing unit in a given state receives 
allowances commensurate with the unit's emissions reflected in 
whichever total emissions amount is lower for the state, 2009 emissions 
or 2012 base case emissions projections. In either case, the allocation 
is adjusted downward, if the unit has additional pollution controls 
projected to be online by 2012. * * * For states with lower 
SO2 budgets in 2014 (SO2 Group 1 states), each 
unit's allocation for 2014 and later is determined in proportion to its 
share of the 2014 state budget, as projected by IPM'' (75 FR 45309).
    Many commenters objected to this projected emission allocation 
methodology. Commenters offered two principle objections. First, they 
argued EPA should not use unit-level model projections to allocate 
allowances. Second, they argued the use of any emission-based allowance 
methodology is improper. Many of these commenters argued that instead 
of an emission-based allocation methodology, EPA should use a heat-
input-based allocation methodology.
    Commenters' objections to the use of unit level model projections 
focused primarily on the accuracy of such projections. While many 
commenters supported the use of modeling projections in determining 
state emission budgets, they argued that the unit-level model 
projections were not sufficiently accurate to use as a basis for 
allocating allowances to individual units. Among other things, they 
argued that the modeling used for the proposal did not recognize 
certain non-economic factors that may cause individual units to operate 
differently than the model projects. Commenters also argued that EPA's 
modeling does not capture all up-to-date contracts and other economic 
arrangements made at the unit-level which may affect operational 
decision-making. Some of these commenters continued to support the use 
of an emission-based allocation approach, but urged EPA to use more up-
to-date and specific unit-level data in its modeling projections. 
Others opposed the use of any emission-based allocation approach.
    EPA acknowledges that the model may not, at this time, capture all 
relevant operational decision factors for each individual unit. EPA 
also recognizes that there are unit-level details of operational 
decision-making and economic arrangements (such as certain contracts 
for electricity sales) that are private and thus unavailable to EPA on 
an ongoing basis for modeling purposes. EPA believes these potential 
omissions would not have a significant impact on EPA's determination of 
significant contribution at the state level; however, EPA recognizes 
they could conceivably have a significant impact on projections at the 
individual unit level. EPA thus agrees with commenters that the unit-
level emission projections from its modeling may not reflect all 
possible operational decisions at a given unit and are therefore not an 
appropriate proxy measure to use as a basis for allocating allowances 
to individual units.
    Many commenters also argued that, even if the emission projections 
could be adjusted to capture all known and up-to-date unit-level 
operational factors, EPA should not use any emission-based allocation 
approach. They argued that an emission-based approach should not be 
used because it is not fuel-neutral. That is to say, the type of fuel 
consumed significantly affects the emissions from, and therefore the 
allocation to, a given unit under an emission-based approach. 
Commenters argued that an approach that is not fuel-neutral effectively 
awards higher-emitting units. Commenters also argued that a projected 
emission-based approach should not be used because it is not control-
neutral. In other words, whether or not a unit has installed controls 
would significantly affect the allocation for a given unit under an 
emission-based approach. Under an emission-based approach, controlled 
units receive significantly fewer allowances than uncontrolled units. 
Such an approach, commenters pointed out, effectively penalizes sources 
who have taken action to reduce emissions.
    EPA acknowledges that an emission-based approach would not be fuel-
neutral or control-neutral. EPA notes that the DC Circuit rejected the 
fuel adjustment factors that were used in CAIR to adjust state budgets 
based on the type of fuel burned at each covered unit. North Carolina, 
531 F.3d 918-21 (rejecting use of fuel adjustments in setting state 
NOX budgets). While the proposal's allocation methodology 
did not explicitly adopt ``fuel adjustment factors'' for allocation 
purposes, EPA recognizes that an emission-based allocation methodology 
effectively advantages or disadvantages units based on the type of fuel 
they combust.
    In addition, several commenters argued that the proposal's 
emission-based methodology would inappropriately reward the highest 
emitters under the program with more allowances than their lower-
emitting counterparts would receive. EPA acknowledges that such a 
methodology would allocate more allowances to units whose emissions 
make up a larger share of the proposed Transport Rule programs' state 
budgets. EPA notes that because any allocation patterns under the 
Transport Rule FIPs would be established in advance of covered sources' 
compliance decisions (i.e., decisions regarding how much to emit under 
the programs), covered sources

[[Page 48286]]

cannot be ``rewarded'' by adjusting their future emissions. However, 
EPA notes commenters' observations that the proposal's methodology 
would reduce allocations to units that previously installed pollution 
control technology or invested in cleaner forms of generation in 
anticipation of CAIR. EPA concluded in review of these comments that 
the proposed Transport Rule's allocation methodology unintentionally 
yielded this distributional outcome. EPA therefore considered 
alternative allocation methodologies described below.
    A substantial portion of the commenters who objected to the 
proposal's emission-based allocation option urged EPA to consider 
historic heat input based approaches. EPA agreed it should accept 
comment on the use of historic heat input-based approaches and 
published a NODA to provide an opportunity for comment on two specific 
heat input options and the allocations that would result from 
application of those options to the proposed Transport Rule state 
budgets.
ii. Heat Input Allocation Option 1
    The first heat input option presented by EPA in the NODA (``Option 
1'') allocates allowances to units based solely on their historic heat 
input. Under this option, EPA would establish a 5-year historic heat 
input baseline for each covered unit and allocate allowances to sources 
at levels proportional to the each unit's share of the total historic 
heat input at all covered units in that state.
    Numerous commenters supported the use of a heat-input based 
allocation methodology. These commenters stated that basing allocations 
on historic heat input has the following advantages over the proposal's 
emission-based allocation methodology:
    (A) For certain types of units, historic heat input data may offer 
a better representation of unit-level operation than model projections 
of unit-level emissions; furthermore, for all units, historic heat 
input is typically represented by quality-assured data reported by 
sources from continuous emission monitoring systems, which strengthens 
its accuracy.
    (B) Historic heat input data are generally fuel-neutral in that 
they do not generally yield higher allocations for units burning or 
projected to burn higher emitting fuels.
    (C) Historic heat input data are generally emission-control-neutral 
in that they do not generally yield reduced allocations for units that 
installed or are projected to install pollution control technology.
    Many commenters also argued that a heat input-based allocation 
methodology should be used because, unlike the proposal's emission-
based methodology, a heat-input based methodology would be generally 
fuel-neutral and control-neutral and would rely on unit-level quality-
assured data instead of on modeling projections.
    Several commenters expressed support for specific aspects of heat 
input option number one. From a technical standpoint, commenters noted 
that heat input option 1 relied on the highest-quality and most 
transparent data EPA had provided as a basis for allocating allowances 
under the Transport Rule programs. They argued that the calculation 
methodology for heat input option 1 is more readily re-created and 
understood by sources than either the proposal's methodology or EPA's 
application of the ``reasonable upper-bound capacity utilization factor 
and a well-controlled emission rate'' in heat input option 2 (described 
in greater detail below). They also pointed out that it is similar to 
methodologies used in previous trading programs, such as the 
NOX Budget Trading Program (see 40 CFR 96.42(a) & (b) 
(calculating each existing EGU's allocation by multiplying each unit's 
historic heat input by 0.15 lb/mmBtu)). In addition, commenters 
supported the reliance of heat input option 1 on continuous emission 
monitoring system (CEMS) data that are reported to EPA and certified by 
the source's designated representative (DR) as accurate and complete. 
In addition, many commenters supported EPA's use of historic data 
without further transformation by any calculation factors created by 
EPA.
    From a policy perspective, commenters highlighted the fuel 
neutrality and emission-control neutrality aspects of heat input option 
1. They noted that this option does not, in contrast to the proposal's 
emission-based methodology, penalize a source, through a reduced 
allowance allocation, for having chosen a generation technology or 
emission control technology that was more favorable to public health 
and the environment. EPA agrees with these observations. The allocation 
pattern associated with this option does not advantage or disadvantage 
units based on either the fuel consumed or the presence or absence of a 
pollution control technology. In this respect, it is a neutral approach 
that does not ``reward'' high-emitting units or ``penalize'' low-
emitting units, including, for example, those units on which pollution 
control technology was installed in anticipation of CAIR.
    EPA agrees with the aforementioned arguments from these commenters 
regarding the technical and policy merits of this heat input-based 
allocation methodology. EPA believes that the quality-assured heat 
input data reported by EGUs under its programs are among the most 
detailed and sound unit-level data accessible by EPA. EPA believes the 
calculation of any individual unit's share of this historic heat input 
data is a straightforward, clear, and simple calculation to perform, 
such that EPA's calculated allowance allocations under this approach 
can be relatively easily replicated.
    EPA also agrees with commenters that such data has previously 
supported allowance allocation procedures for highly successful program 
implementation of the ARP and the NOX Budget Trading Program 
(NBP). Notably, Congress chose a heat input-based allocation approach 
when authorizing the ARP in title IV of the Clean Air Act, suggesting 
that Congress viewed heat input as a reasonable basis for allocation. 
Additionally, EPA's selection of a heat input-based approach for the 
NBP was not legally challenged, implying that stakeholders generally 
saw a heat input-based approach as reasonable.
    EPA also agrees with comments observing that allocations made under 
this heat input approach do not advantage or disadvantage units based 
on their choice of fuel combustion or pollution control technology, and 
that allocations under this approach would thus be ``fuel-neutral'' and 
``control-neutral.'' EPA also agrees with commenters that unlike the 
proposed rule's emission-based methodology, this heat input methodology 
does not yield lower allocation to units that reduced emissions in 
advance of the Transport Rule relative to units that did not make such 
emission reductions.
    Other commenters objected to the use of a heat-input based 
allocation methodology. These commenters argued that the allocation 
pattern associated with a heat-input allocation methodology would yield 
``windfall profits''--in the form of allowance allocations greatly in 
excess of likely emissions--for certain units, particularly with regard 
to SO2 allowance allocations for units combusting natural 
gas. EPA disagrees with the characterization of the excess allowances 
as ``windfall profits.'' Allocations based on heat-input alone are 
fuel-neutral and control-neutral. The characterization of the heat-
input allocation methodology as creating ``windfall profits'' for any 
unit is based on the assumption that all units should

[[Page 48287]]

be allocated allowances based on emissions, not heat input. In arguing 
the heat-input approach creates a ``windfall'' for some units, 
commenters are assuming that the allocation of allowances above a 
unit's projected emissions constitutes a ``windfall''--a conclusion EPA 
does not accept. EPA believes that under market-based regulatory 
programs, it is appropriate to base initial allowance allocations on a 
neutral factor and allow the market to determine the least-cost pattern 
of emission reductions in each state to achieve the reductions that 
address the state's significant contribution and interference with 
maintenance under the final Transport Rule programs. EPA disagrees that 
future allowance transactions (following a neutral-factor initial 
allocation) in response to these market forces can be characterized as 
``windfall profits.'' As explained above, EPA believes it is 
appropriate to allocate allowances based on a neutral factor. 
Commenters appear to ask EPA, instead of allocating based on a neutral 
factor, to consider the unit-level distributional impacts of each 
allocation methodology and to select an allocation methodology on the 
basis of equity. EPA does not believe it would be appropriate for the 
agency to pick an allocation methodology to achieve any particular 
distributional outcome as such considerations are not related to the 
statutory mandate of CAA section 110(a)(2)(D)(i)(I). Instead, EPA 
believes it is appropriate to allocate allowances to sources covered by 
its trading programs based on a neutral factor. Furthermore, CAA 
section 110(a)(2)(D)(i)(I) requires prohibition of certain emissions 
within a state (i.e., a state's significant contribution and 
interference with maintenance). It does not direct EPA to use any 
particular methodology for allocating allowances under a trading 
program designed to ensure all such emissions are prohibited. As such, 
EPA believes it is appropriate to allocate allowances based on a 
neutral factor representing fossil energy content used to produce 
electricity. Detailed considerations of equity, as the DC Circuit 
reminded EPA, are not related to the statutory mandate of section 
110(a)(2)(D)(i)(I). North Carolina, 531 F.3d 921.
    Some commenters objected to the use of a heat input-based approach 
by arguing that higher-emitting units would not receive an initial 
allocation sufficient to cover their emissions. EPA does not believe it 
is reasonable to expect initial allocations to cover each unit's 
emissions under a trading program aimed at producing meaningful 
emission reductions. In its administration of prior trading programs 
such as the ARP and the NBP, EPA has made initial allowance allocations 
using a heat input-based approach, and virtually all covered sources 
have successfully complied at the end of each compliance period by 
making cost-effective emission reductions, purchasing additional 
allowances through robust markets to cover emissions, or undertaking 
both types of activities. EPA disagrees with commenters' arguments that 
allowance allocations should be used to compensate units with higher 
emissions.
iii. Heat Input Allocation Methodology Option 2
    The second heat input option presented by EPA for public comment 
also would use historic heat input but would apply a constraint to 
unit-level allocations under certain circumstances. Specifically, under 
this option unit-level allocations would not be allowed to exceed what 
EPA determines, based on historic emissions and other factors, to be 
the units' ``reasonably foreseeable maximum emissions.''
    To apply this constraint, EPA first would determine whether the 
allocation to a unit under an unconstrained heat-input methodology 
would exceed that unit's maximum historic emissions of the relevant 
pollutant since 2003 ``in order to reflect unit-level emissions before 
and after the promulgation of the CAIR'' (76 FR 1115). Using this 
baseline would enhance the neutrality of the maximum historic emissions 
data because it would capture the highest emissions of the unit during 
that period regardless of what fuels it combusted or what pollution 
control devices were installed and used at any particular time during 
that period. In other words, a unit's allocation would not be reduced 
due to a recent decision to switch fuels or install pollution controls.
    Second, for this option, EPA then would adjust that maximum 
historic emissions data by applying a ``well-controlled rate maximum,'' 
designed to place ``a reasonably foreseeable maximum emissions level 
reflecting a reasonable upper-bound capacity utilization factor and a 
well-controlled emission rate that all units (regardless of the type of 
fuel they combust) can meet for the pollutant'' (76 FR 1115). This 
option would constrain certain units' allocations that, if based solely 
on historic heat input, would be determined by EPA to be ``in excess of 
their reasonably foreseeable maximum emissions'' under the Transport 
Rule programs (76 FR 1115).
    As noted above, commenters offered numerous arguments in favor of 
using a historic heat input approach. These arguments apply equally to 
heat input option 1 and heat input option 2. EPA also received numerous 
comments comparing the two heat input options presented.
    Many commenters preferred heat input option 1's reliance purely on 
historic data as compared with heat input option 2's reliance on that 
data modified by the application of EPA-determined ``reasonable upper 
bound capacity factors'' and ``well-controlled emission rates.'' 
Commenters also criticized the complexity of these modification factors 
in heat input option 2. While EPA believes both options represent 
viable approaches, the Agency agrees with commenters that the 
application of these factors increase the complexity of allocation 
determinations and would adjust unit-specific historic data by applying 
EPA-created factors generically determined for broad categories of 
units.
    Some commenters suggested that EPA's application of these 
modification factors could also represent legal vulnerabilities for the 
Transport Rule. In particular, they were concerned that the capacity 
factors and well controlled emission rates presented as part of heat 
input option 2 could be perceived as arbitrary. While EPA does not 
agree that these modification factors are arbitrary, the Agency does 
recognize that application of such EPA-created generic factors in 
determining unit-specific allocations increases the complexity of the 
allocation approach and raises issues regarding whether such generic 
factors are appropriately applied to each individual unit.
iv. General Comments on EPA's Authority To Allocate Allowances
    Numerous commenters also noted that EPA has generally broad 
authority in selecting an allocation methodology under CAA sections 
110(a)(2)(D)(i)(I) and 302(y).\80\ EPA agrees with commenters that the 
Agency has broad discretion in this area. Neither the CAA nor the D.C. 
Circuit Court's opinion in North Carolina specifies a particular 
methodology that EPA must use to allocate allowances to individual 
units.

[[Page 48288]]

CAA section 110(a)(2)(D)(i)(I) requires prohibition of emissions 
``within the state'' that significantly contribute to nonattainment or 
interfere with maintenance and gives states broad discretion to develop 
a control program in a SIP that achieves this objective. EPA has 
similarly broad discretion when issuing a FIP to realize this 
objective. Moreover, while the definition of FIP in CAA section 302(y) 
clarifies that a FIP may include ``enforceable emission limitations or 
other control measures, means or techniques (including economic 
incentives, such as marketable permits or auctions of emissions 
allowances),'' this section does not require EPA to use any particular 
methodology to allocate allowances under a FIP trading program. In 
light of this lack of direction in the CAA concerning allowance 
allocation, EPA has broad discretion to select an allocation 
methodology that is reasonable and consistent with the goals of CAA 
section 110(a)(2)(D)(i)(I).
---------------------------------------------------------------------------

    \80\ CAA section 302(y) defines the term ``Federal 
implementation plan'' as ``a plan (or portion thereof) promulgated 
by the Administrator to fill all or a portion of a gap or otherwise 
correct all or a portion of an inadequacy in a State implementation 
plan, and which includes enforceable emission limitations or other 
control measures, means or techniques (including economic 
incentives, such as marketable permits or auctions of emissions 
allowances), and provides for attainment of the relevant national 
ambient air quality standard.''
---------------------------------------------------------------------------

    The body of public comment makes it clear that no allocation option 
could be deemed satisfactory from the perspective of all stakeholders. 
Public comments from most states and industrial stakeholders with a 
substantial interest in how EPA allocates allowances under the 
Transport Rule FIPs expressed support for an historical heat input-
based approach as opposed to the proposal's emission-based approach. 
Most commenters favored this historical heat input data basis as the 
most sound and offered technical data corrections, which EPA considered 
and generally used in the final rule. EPA believes it is reasonable to 
select a heat input-based approach for the final Transport Rule because 
this approach is consistent with the rule's statutory objectives and 
has been found, when implemented in prior trading programs, to be a 
credible, workable allocation approach.
b. Final FIP Allocation Methodology
    After consideration of all comments, EPA decided to allocate 
allowances to individual units based on that units' share of the 
state's historic heat-input, but to ensure that no unit's allocations 
exceed that unit's historic emissions. EPA decided to use the 
allocation methodology originally presented as heat input option 2, 
modified in response to public comments. EPA decided to use heat input 
option 2 but without the application of the ``reasonable upper-bound 
capacity utilization factor and a well-controlled emission rate'' 
factors. This allocation approach reflects the Agency's response to 
extensive public comment on the options presented in the proposed 
Transport Rule and subsequent NODAs and is a logical outgrowth of those 
actions. EPA is using this approach to allocate allowances under the 
FIPs for all four trading programs. Further details on the calculation 
and implementation of this approach are provided below in section 
VII.D.1.c and can also be found in the Allowance Allocation Final Rule 
TSD in the docket for this rulemaking.
    The principal reasons for this decision are:
     EPA believes that existing-unit allowance allocation under 
the Transport Rule should not generally advantage or disadvantage units 
based on the selection of fuels consumed or of pollution controls 
installed at a given unit in anticipation of either the Clean Air 
Interstate Rule or the Transport Rule, i.e., fuel or control decisions 
taken from 2003 onward. An approach that does not advantage or 
disadvantage units in this way avoids allocating in a way that would 
effectively penalize units that have already invested in cleaner fuels 
or other pollution reduction measures that will continue to deliver 
important emission reductions under this rulemaking. The approach 
selected in the final rule generally does not penalize such units and 
is thus generally fuel-neutral and control-neutral in its allocation 
determinations.
     EPA finds that the selected approach maximizes 
transparency and clarity of allowance allocations. EPA has already made 
public the historic heat input and historic emissions data on which 
this approach is based, and its application to calculate unit-level 
allocations in each state under that state's emission budgets finalized 
in this Transport Rule can be relatively easily replicated.
     EPA finds that quality-assured historic CEMS-quality data 
used to implement this approach represent the most technically superior 
data available to EPA at the time of this rulemaking for calculating 
unit-level allocations. The selected approach relies on unmodified 
historic data reported directly by the vast majority of covered 
sources, whose designated representatives have already attested to the 
validity and accuracy of this data. EPA agrees with commenters that 
allowance allocations should be based on quality-assured data to the 
maximum extent possible. This approach uses the most accurate data 
currently available to EPA.
     Heat-input based approaches were used to allocate 
allowances under both the NOX Budget Trading Program and the 
Acid Rain Program. Allocation under these programs was readily and 
easily administered, and the programs achieved or exceeded their 
environmental goals. The selected approach's use of heat input as a 
basis for allocations builds on prior legislative and administrative 
approaches to allowance allocations for trading programs.
     EPA also finds that the selected approach's addition of a 
constraint to heat input-based allocations where such allocations would 
otherwise exceed a unit's maximum historic emissions is a reasonable 
extension of a heat input-based allocation approach. The Transport Rule 
trading programs are established to achieve overall emission reductions 
in each covered state. As a group, covered sources within each state 
must make the necessary reductions under these programs. In light of 
each program's goal to reduce each state's overall emissions, it is 
logical and consistent with that goal that the starting point for each 
source under these programs--i.e., the initial allocations of shares of 
the state budget to covered units--be an amount of allowances no 
greater than each unit's maximum historic emissions. Under the trading 
programs, any source may emit a ton of SO2 or NOX 
for which it holds a corresponding allowance, which it may acquire 
either by initial allocation or by subsequent purchase, to the extent 
consistent with the assurance provisions (discussed elsewhere in this 
preamble) that ensure achievement of the requisite overall reductions 
in each state. Consequently, the initial allocations to the units at 
each source are the starting point for each source's efforts to comply 
with the allowance-holding and assurance provision requirements, but do 
not determine the source's strategies for compliance and ultimate level 
of emissions. EPA believes that a starting point of unit-level heat 
input-based allocations constrained not to exceed each specific units' 
maximum historic emissions is reasonable and consistent with the 
program goals of reducing overall emissions in each state: Each 
existing unit is allocated an amount that either reflects reduced unit 
emissions or does not exceed historic emissions, and, from that 
starting point, the units, as a group, reduce overall emissions to the 
level required for each state. Conversely, EPA believes that a starting 
point allocating some units more than they have ever emitted would be 
illogical in programs aimed at reducing overall emissions.
    EPA believes that this selected allocation methodology for the 
final Transport Rule FIPs is within its authority under the Clean Air 
Act. Section 110(a)(2)(D)(i)(I) of the CAA

[[Page 48289]]

requires that emissions ``within a state'' that significantly 
contribute to nonattainment or interfere with maintenance in another 
state be prohibited. In the final Transport Rule, EPA analyzed each 
individual state's significant contribution and interference with 
maintenance and calculated budgets that represent each state's 
emissions after the elimination of prohibited emissions in an average 
year. The methodology used to allocate allowances in a state budget to 
individual units in the state has no impact on that state's budget or 
on the requirement that the state's emissions not exceed that budget 
plus variability. Regardless of the allocation methodology used, the 
state's responsibility for eliminating its significant contribution and 
interference with maintenance remains unchanged. This is reflected by 
the fact that allocations under each state's budget, regardless of how 
they are made, cannot change that state's budget. In sum, the 
allocation methodology has no impact on the final rule's ability to 
satisfy the statutory mandate of CAA section 110(a)(2)(D)(i)(I) to 
eliminate significant contribution to nonattainment and interference 
with maintenance.
    Consistent with its broad authority in CAA sections 
110(a)(2)(D)(i)(II) and 302(y), EPA believes that data quality, fuel-
neutrality, control-neutrality, transparency, clarity, consistency with 
program goals, and successful experience in previous trading programs 
are reasonable factors on which to base the selection of an allowance 
allocation methodology for existing units for the final Transport Rule. 
EPA believes that the transparency and clarity of this allocation 
approach builds credibility with the public that the government is 
distributing a public resource--i.e., allowances--precisely as stated 
in this rulemaking, with clear execution that can be relatively easily 
verified.
    EPA also believes that the final Transport Rule's heat input-based 
approach for existing units is consistent with the goals of the Clean 
Air Act because it allocates allowances to existing units on the basis 
of a neutral factor that does not advantage or disadvantage a unit 
based on what fuel the unit burns or whether or not a unit has 
installed controls in anticipation of these regulations. In contrast, 
allocations under the proposal's emission-based methodology would give 
a greater share of allowances to units with higher emission rates, 
which are generally responsible for a greater share of a state's total 
emissions. Because these higher-emitting rate units are generally 
responsible for a greater share of emissions, it follows that they are 
also responsible for a greater share of a state's significant 
contribution to nonattainment and interference with maintenance. The 
proposal's emission-based allocation methodology would disadvantage one 
of two otherwise identical existing units if it invested in emission 
reductions in anticipation of the Clean Air Interstate Rule or this 
final Transport Rule.
    The heat-input allocation methodology selected for the final 
Transport Rule does not have this flaw. In contrast to the proposal's 
emission-based allocation approach, the heat input allocation 
methodology selected by EPA yields a smaller proportion of allowances 
relative to emissions to higher-emission-rate units and a higher 
proportion of allowances relative to emissions to lower-emission-rate 
units. For example, assume that in a state with two units and in a 
baseline year, Unit A combusts 100 mmBtu of heat input and emits 1,000 
tons while Unit B combusts 100 mmBtu of heat input and emits only 500 
tons. Assume also that this state's future Transport Rule emissions 
budget for this pollutant is only 500 tons. Because Units A and B each 
make up an even share of historic heat input for the state, the final 
rule's heat input-based approach would allocate the same share of 
allowances (250 tons) to each unit. In this example, Unit A's initial 
allocation of 250 is a smaller proportion of its historic emissions (25 
percent of its baseline 1,000-ton emissions), while Unit B's initial 
allocation of 250 is a larger proportion of its historic emissions (50 
percent of its baseline 500-ton emissions). Therefore, Unit B's ability 
to emit fewer tons per mmBtu of heat content used for generating 
electricity (as compared with Unit A) results in Unit B receiving a 
larger proportion of its historic emissions as an initial allocation 
share than Unit A receives.
    This relative distributional pattern yielded is consistent with the 
goals of CAA section 110(a)(2)(D)(i)(I) because under this 
distribution, higher-emitting units, which are responsible for a 
greater share of the state's significant contribution to nonattainment 
and interference with maintenance, would require relatively more 
allowances in order to cover their pre-existing emissions than would 
lower-emitting units. EPA believes this initial allocation pattern is 
an appropriate reflection of the goals of CAA section 
110(a)(2)(D)(i)(I).
    The heat input-based allowance methodology selected by EPA is fuel-
neutral, control-neutral, transparent, based on reliable data, and 
similar to the allocation methodologies used in the NOX SIP 
Call and Acid Rain Program. For all these reasons, EPA determined that 
it is appropriate to use a heat input-based allocation methodology in 
this rule.
    In addition, this allocation methodology is similar to an output-
based allocation approach, which would base allocations on the quantity 
of electricity generated (rather than energy content combusted) and 
would also be fuel-neutral, control-neutral, and able to reward 
generation units that operate the most efficiently. Many state and 
industry commenters advocated using an output-based approach due to its 
reported strong value in promoting efficiency. However, at this time 
EPA does not have access to unit-level output data that is as quality-
assured or comprehensive as its data sets on heat input across the 
units considered. Therefore, EPA is using a heat input-based approach 
under the Transport Rule in part due to its ability to serve as a 
reasonable proxy for an output-based standard using the most quality-
assured data that EPA has to date.
    In the NODA, EPA noted that final state budgets and allocations may 
differ from the proposed budgets and allocations because EPA was still 
in the process of updating its emission inventories and modeling in 
response to public comments, including comments on IPM. Thus, unit-
level allocations in the NODA provided an indication of the 
proportional share of a state's budget that would be allocated to 
individual existing units if the alternative methodologies were used. 
The allocations made final today are based on budgets that reflect the 
updated modeling and comments received during the comment period.
c. Calculation of Existing Unit Allocations Under the Final Transport 
Rule FIPs
    Allocations under this final methodology for each existing unit are 
determined by applying the following steps.
    1. For each unit in the list of potential existing Transport Rule 
units, annual heat input values for the baseline period of 2006 through 
2010 are identified using data reported to EPA or, where EPA data is 
unavailable, using data reported to the Energy Information 
Administration (EIA). For a baseline year for which a unit has no data 
on heat input (e.g., for a baseline year before the year when a unit 
started operating), the unit is assigned a zero value. (Step 2 explains 
how such zero values are treated in the calculations.) The allocation 
method uses a 5-year

[[Page 48290]]

baseline to approximate a unit's normal operating conditions over time.
    2. For each unit, the three highest, non-zero annual heat input 
values within the 5-year baseline are selected and averaged. Selecting 
the three highest, non-zero annual heat input values within the five-
year baseline reduces the likelihood that any particular single year's 
operations (which might be negatively affected by outages or other 
unusual events) would determine a unit's allocation. If a unit does not 
have three non-zero heat input values during the 5-year baseline 
period, EPA averages only those years for which a unit does have non-
zero heat input values. For example, if a unit has only reported data 
for 2008 and 2009 among the baseline years and the reported heat input 
values are 2 and 4 mmBtus, respectively, then the unit's average heat 
input used to determine its pro-rata share of the state budget is 
(2+4)/2 = 3.
    3. Each unit is assigned a baseline heat input value calculated as 
described in step 2, above, referred to as the ``3-year average heat 
input.''
    4. The 3-year average heat inputs of all covered existing units in 
a state are summed to obtain that state's total ``3-year average heat 
input.''
    5. Each unit's 3-year average heat input is divided by the state's 
total 3-year average heat input to determine that unit's share of the 
state's total 3-year average heat input.
    6. Each unit's share of the state's total 3-year average heat input 
is multiplied by the existing-unit portion of the state budget (i.e., 
the state budget minus the state's new unit set-aside and, if 
applicable, minus the Indian country new unit set-aside) to determine 
that unit's initial allocation.
    7. An 8-year (2003-2010) historic emissions baseline is established 
for SO2, NOX, and ozone-season NOX 
based on data reported to EPA or, where EPA data is unavailable, based 
on EIA data. This approach uses this 8-year historic emissions baseline 
in order to capture the unit-level emissions before and after the 
promulgation of CAIR.
    8. For each unit, the maximum annual historic SO2 and 
NOX emissions are identified within the 8-year baseline. 
Similarly, the maximum ozone season NOX emissions from the 
8-year baseline for each unit are identified. These values are referred 
to as the ``maximum historic baseline emissions'' for each unit.
    9. If a unit has an initial historic heat-input based allocation 
(as determined in step 6) that exceeds its maximum historic baseline 
emissions (as determined in step 8), then its allocation equals the 
maximum historic baseline emissions for that unit.
    10. The difference (if positive) under step 9 between a unit's 
historic heat-input-based allocation and its ``maximum historic 
baseline emissions'' is reapportioned on the same basis as described in 
steps 1 through 6 to units whose historic heat-input-based allocation 
does not exceed its maximum historic baseline emissions. Steps 7, 8, 
and 9 are repeated with each revised allocation distribution until the 
entire existing-unit portion of the state budget is allocated. The 
resulting allocation value is rounded to the nearest whole ton using 
conventional rounding.
    Table VI.D-1 below provides an illustrative application of the 
steps 1-10 in a hypothetical state.

 Table VI.D-1--Demonstration of Allocations Using Final Allocation Methodology in a Three-Unit State With an 80-
                                                Ton State Budget
----------------------------------------------------------------------------------------------------------------
                                                 Steps 1-6      Steps 7, 8, 9      Steps 1-9         Step 10
                                             ----------------------------------    reiterated   ----------------
                                                                               -----------------
                                                  Initial          Maximum          Revised
                                               historic heat       historic      historic heat        Final
                                                input-based        baseline       input-based       allocation
                                                 allocation       emissions        allocation
----------------------------------------------------------------------------------------------------------------
Unit A......................................               20               16              N/A               16
Unit B......................................               30               50               32               32
Unit C......................................               30               50               32               32
----------------------------------------------------------------------------------------------------------------

2. Allocations to New Units
    EPA is finalizing--similar to the proposal (75 FR 45310)--an 
approach to allocate emission allowances to new units from new unit 
set-asides in each state. A ``new unit'' may be any of the following: 
(1) A covered unit commencing commercial operation on or after January 
1, 2010; (2) any unit that becomes a covered unit by meeting 
applicability criteria subsequent to January 1, 2010; (3) any unit that 
relocates into a different state covered by the Transport Rule; \81\ 
and (4) any existing covered unit that stopped operating for 2 
consecutive years but resumes commercial operation at some point 
thereafter.
---------------------------------------------------------------------------

    \81\ Existing- or new-unit allocations drawn from the budget of 
the relocated unit's original state are replaced by new unit set-
aside allocations from the budget of the unit's relocation state in 
order to generally ensure that allocations are drawn from the 
correct state budget.
---------------------------------------------------------------------------

    The proposed Transport Rule would have required that owners and 
operators initially request allowances from the new unit set-aside when 
the unit first became eligible for an allocation. EPA now believes that 
it can identify which units become eligible and when they become 
eligible, based on information provided in other submissions (e.g., 
certificates of representation, monitoring system certifications, and 
quarterly emissions reports) that the final rule already requires such 
units to make to EPA. EPA concludes that requiring owners and operators 
to submit requests of new unit set-aside allocations would impose an 
unnecessary burden on the owners and operators, as well as on EPA, and 
therefore EPA has removed this requirement in the final rule.
    The following sections describe the methodology in the final 
Transport Rule for allocating to new units, how EPA determined the size 
of new unit set-asides in the final rule, and how EPA has provided for 
allocations to new units that locate in Indian Country.
a. New Unit Allocation Methodology
    The proposal's new unit allocation methodology did not provide any 
allocation for a new unit's first control period of commercial 
operation. Some commenters expressed concern about the lack of new unit 
allocations the first year of commercial operation. In order to address 
this concern, EPA is modifying the new unit allocation methodology in 
this final rule to include allocations to new units for the first 
control period in which the units are in commercial operation, as well 
as for control periods in subsequent years.

[[Page 48291]]

    The final rule's allocation to new units is performed in two 
``rounds.'' The first round is the same as the new unit allocation 
procedures in the proposal (except for elimination of the requirements 
that owners and operators request the allocations) and occurs during 
the control period for which the allocations are made. These first 
round allocations are based on new unit emissions during the prior 
control period and are recorded in allowance accounts in the Allowance 
Management System for the units by August 1 of each control period. For 
example, for the 2012 vintage year, ``first-round'' allocations would 
be made to new units by August 1, 2012 based on their emissions in the 
2011 control period (as monitored and reported in accordance with Part 
75 of the Acid Rain Program regulations). If the new unit set-aside is 
insufficient to accommodate first round allocations reflecting all new 
units' prior control period emissions, the first round allocations are 
made pro rata to new units based on their share of total new unit 
emissions in the prior control period.
    The second round of allocations accommodates new units that come 
online during the control period for which the allocations are made and 
did not therefore receive any allocation in the first round. The second 
round also accommodates new units that come online partway into the 
prior control period and therefore received an allocation in the first 
round that did not extend to cover operations in a full control period. 
This second round of new unit allocation is therefore applicable only 
to new units coming online either during the control period of the 
allocation or during the control period immediately prior. New units 
coming online earlier than the previous control period only receive 
first-round allocations from the new unit set-asides, as first-round 
allocations to those units are based on operational data spanning an 
entire control period.
    Second-round allocations are based on new unit emissions during the 
same control period as the vintage year of the allowances allocated. 
For example, for the 2012 vintage year, ``second-round'' allocations 
are based on the difference between the new unit's emissions in the 
2012 control period and the new unit allocation (if any) that the unit 
received in the first round of allocations. For a unit coming online in 
2012, this amount equals its total emissions during the 2012 control 
period. For a unit coming online in 2011, this amount equals its 
incremental emissions in 2012 beyond its emissions in 2011, as such a 
unit would have already received a first-round allocation from the new 
unit set-aside based on its emissions in 2011. Second-round allocations 
are recorded in allowance accounts by November 15 for the 
NOX ozone season trading program (ahead of the December 1 
compliance deadline) and by February 15 of the following calendar year 
for NOX and SO2 annual trading programs (ahead of 
the March 1 compliance deadline).
    This methodology only allocates in the second round whatever 
allowances remain in the new unit set-asides after the first-round 
allocations have been recorded. If the new unit set-aside available for 
second round allocations is insufficient to accommodate allocations 
based on the difference between control period emissions and any first 
round allocations for the units involved, then the second round 
allocations are made pro rate to the new units based on their share of 
the total of such differences.
b. Determination of New Unit Set-Asides
    The proposed Transport Rule identified new units using a threshold 
online date of January 1, 2012, whereas the final Transport Rule uses a 
threshold online date of January 1, 2010. As explained above, EPA 
adjusted this cutoff date because the final Transport Rule's allocation 
methodology for existing units requires that EPA possess at least 1 
full year of historic data in order to calculate allocations. As a 
consequence, EPA recognizes that the proposal's methodology to 
determine the size of the new unit set-asides based only on new EGUs 
forecast by the model would fail to account for known EGUs that have 
come online, or are planned to come online, after January 1, 2010. 
Therefore, EPA has modified its approach to determining the size of the 
new unit set-asides in the final rule to account for both ``potential'' 
units (i.e., those that are not yet planned or under construction but 
are projected by modeling to be built) and ''planned'' units (i.e., 
those that are known units with planned online dates after January 1, 
2010). EPA uses the distinction between ``potential'' and ``planned'' 
new units to determine the ultimate size of each state's new unit set-
aside (as a percentage of that state's budgets for each pollutant 
covered); however, the new unit allocation methodology described above 
applies the same to ``potential'' and ``planned'' new units.
    The first step of EPA's analysis to determine the new unit set-
asides accounts for likely future emissions from potential units, and 
its methodology is taken directly from the Transport Rule proposal but 
reflects updated modeling (see ``Allowance Allocation to Existing and 
New Units Under the Transport Rule Federal Implementation Plans'' TSD 
for detailed findings). This analysis informed EPA's decision to 
establish a minimum new unit set-aside size of 2 percent of each 
state's budget for each pollutant that is configured to accommodate 
future emissions from potential units.
    For the final rule, EPA augmented its new unit set-aside 
determination to account for ``planned'' units through an additional 
step. Because the location of these ``planned'' units is known and 
identified in EPA modeling, this second step is a state-specific 
modification of the size of the new unit set-asides. That is, EPA only 
increased new unit set-asides above the 2 percent minimum established 
in the first step for states that had additional known units coming 
online between January 1, 2010, and January 1, 2012.
    The increases made to the new unit set-asides for these planned 
units reflect the projected emissions from these units. Therefore, if 
the expected emissions of a given pollutant from all ``planned'' new 
units in a given state were equal to 3 percent of that state's budget 
for that pollutant, then EPA added that amount to the base 2 percent 
new unit set-aside (creating a hypothetical new unit set-aside of 5 
percent for that pollutant in that state). See ``Allowance Allocation 
to Existing and New Units Under the Transport Rule Federal 
Implementation Plans'' TSD for detailed results showing how EPA 
determined the size of each new unit set-aside reflecting the 
application of both of the steps described above. This approach to 
determining the size of state new unit set-asides is a logical 
outgrowth of the proposal, the NODA on allowance allocations, and 
updated modeling results. In fact, EPA received comments that using a 
January 1, 2010 cutoff date for distinguishing between existing and new 
units would result in the new unit set-aside, as proposed, being 
insufficient to meet the needs of units already under construction. EPA 
believes that the approach adopted in the final rule results in new 
unit set-asides that reasonably accommodate the foreseeable emissions 
from both planned and potential new units in each state.
    The new unit allocation percentages for each state are shown in 
Table VII.D.2-1.

[[Page 48292]]

        Table VII.D.2-1--Percentage of State Emission Budgets for Allowances in State New Unit Set-Asides
----------------------------------------------------------------------------------------------------------------
                                                                                                   Ozone-season
                                                                    Annual SO2      Annual NOX          NOX
----------------------------------------------------------------------------------------------------------------
Alabama.........................................................              2%              2%              2%
Arkansas........................................................  ..............  ..............              2%
Florida.........................................................  ..............  ..............              2%
Georgia.........................................................              2%              2%              2%
Illinois........................................................              5%              8%              8%
Indiana.........................................................              3%              3%              3%
Iowa............................................................              2%              2%  ..............
Kansas..........................................................              2%              2%  ..............
Kentucky........................................................              6%              4%              4%
Louisiana.......................................................  ..............  ..............              3%
Maryland........................................................              2%              2%              2%
Michigan........................................................              2%              2%  ..............
Minnesota.......................................................              2%              2%  ..............
Mississippi.....................................................  ..............  ..............              2%
Missouri........................................................              2%              3%  ..............
Nebraska........................................................              4%              7%  ..............
New Jersey......................................................              2%              2%              2%
New York........................................................              2%              3%              3%
North Carolina..................................................              8%              6%              6%
Ohio............................................................              2%              2%              2%
Pennsylvania....................................................              2%              2%              2%
South Carolina..................................................              2%              2%              2%
Tennessee.......................................................              2%              2%              2%
Texas...........................................................              5%              3%              3%
Virginia........................................................              4%              5%              5%
West Virginia...................................................              7%              5%              5%
Wisconsin.......................................................              5%              6%  ..............
----------------------------------------------------------------------------------------------------------------

c. Procedures for Allocating New Unit Set-Asides
    For the first round of new unit set-aside allocations, the 
Administrator will promulgate a notice of data availability informing 
the public of the specific new unit allocations and provide an 
opportunity for submission of objections on the grounds that the 
allocations are not consistent with the requirements of the relevant 
final rule provisions. A second notice of data availability will 
subsequently be promulgated in order to make any necessary corrections 
in the specific new unit allocations. As discussed elsewhere in this 
preamble, the final rule establishes a different schedule for 
promulgation of these notices of data availability than the proposed 
rule. In particular, a single set of deadlines (i.e., for the first 
notice in the first round of allocations, June 1 of the year for which 
the new unit allocations are described in the notice and, for the 
second notice of the first round, August 1 of that year) for 
promulgation of the notices is established for all of the Transport 
Rule trading programs. EPA believes that these deadlines will provide 
sufficient time for EPA to obtain final emissions data for the prior 
year for the units involved and to calculate the allocations and 
promulgate the notices. Further, the approach of using the same 
deadline for all of the Transport Rule trading programs will simplify 
EPA's implementation and reduce the complexity of the process for 
source owners and operators.
    For the second round of new unit set-aside allocations, the 
Administrator will also promulgate two notices of data availability. 
However, the deadlines for the notices differ for the NOX 
ozone season trading program and for the SO2 and 
NOX annual trading programs because control period emissions 
data (used in making second round allocations) become available sooner, 
and the compliance deadline for holding allowances covering emissions 
is sooner, in the NOX ozone season trading program. The 
control period in the NOX ozone season program ends on 
September 30, and fourth quarter emissions reports must be submitted to 
EPA by October 30, while the control periods in the SO2 and 
NOX annual programs end on December 31 and fourth quarter 
emission reports are due by January 30. Further, in order for the 
second round allocations to be available to be used for compliance with 
the allowance-holding requirement, the second round needs to be 
completed before the compliance dates, which are December 1 in the 
NOX ozone season program and March 1 in the SO2 
and NOX annual programs. Consequently, for the 
NOX ozone season program the Administrator will promulgate 
by September 15 a notice of data availability identifying the units 
eligible for second round allocations and by November 15 a second NODA 
of the list of eligible units and their second round allocations, which 
will also be recorded in the allowance accounts by that date. The 
comparable deadlines for the SO2 and NOX annual 
programs are December 15 and February 15. EPA believes that these 
deadlines will provide sufficient time for EPA to identify the units 
and obtain their needed emissions data and to calculate the allocations 
and promulgate the notices.
d. Addition of Allowances to New Unit Set-Asides
    As discussed elsewhere in this preamble, EPA proposed that, if a 
unit with an existing-unit allocation does not operate for 3 
consecutive years, the allowances that would otherwise have been 
allocated to that unit, starting in the seventh year after the first 
year of non-operation, would be allocated to the new unit set-aside for 
the state in which the retired unit is located. EPA is retaining this 
provision in the final rule but is changing the time of non-operation 
to 2 years and the time of allowance allocation to a non-operating unit 
to 4 years. Starting in the fifth year of non-operation, allowances 
will be allocated to the new unit set-aside for the state in which the 
non-operating unit is located.
    EPA received comments that the new unit set-asides were not 
sufficient to

[[Page 48293]]

encourage the operation of new units. One commenter suggested that 
allowance allocations should cease after 3 years of non-operation 
because the financial incentive gained from receiving allowances beyond 
the 3-year period is insignificant relative to operating and fuel 
costs. Another commenter said that providing allowances to non-
operating units is unnecessary and distorts the market.
    In addition to increasing the size of the new unit set-aside in 
this final rule, as described above, EPA is terminating existing unit 
allocations starting in the fifth year after the unit does not operate 
for 2 consecutive years and reallocating to the new unit set-aside the 
allowances that the unit otherwise would have received for the fifth 
and subsequent years in order to make them available for new units in 
the state. This approach allows the new unit set-asides to grow over 
time.
e. Allocations to New Units Locating in Indian Country
    EPA received several comments on the proposed rule that it did not 
explicitly address the distribution of allowances to potential new 
units built in Indian country. EPA recognized this concern and 
requested comment on this topic in the January 7, 2011 NODA.
    In the final rule, EPA is providing a mechanism to make allowances 
available in the future for new units built in Indian country. The 
final rule establishes an Indian country new unit set-aside for each 
pollutant in each state whose borders encompass Indian country (i.e., 
Florida, Iowa, Kansas, Louisiana, Michigan, Minnesota, Mississippi, 
Nebraska, New York, North Carolina, South Carolina, Texas, and 
Wisconsin). EPA will retain administration of these Indian country new 
unit set-asides as part of the Transport Rule trading programs whether 
or not a Transport Rule state elects to modify or replace the Transport 
Rule FIPs through approved SIP revisions. EPA does not create Indian 
country new unit set-asides for states lacking Indian country within 
their borders.
    EPA determined the size of each Indian country new unit set-aside 
by calculating the ratio of square mileage of Indian country to the 
square mileage of the state within whose borders Indian country is 
located. This calculation yielded a maximum percentage of 5 percent 
when assessing all of the states encompassing Indian country subject to 
the final Transport Rule; this is referred to as the ``5 percent Indian 
country factor'' below. To determine the maximum percentage, EPA used 
the American Indian Reservations/Federally Recognized Tribal Entities 
dataset, which contains data for the 562 federally recognized tribal 
entities in the contiguous U.S. and Alaska. EPA accessed the data to 
analyze the Transport Rule region and compare the square miles of 
Indian country with the square miles of the Transport Rule state that 
includes the Indian country. EPA then took the highest percentage as 
the number to be applied across all states with Indian country to 
determine the size of the Indian country new unit set-aside pertinent 
to that state's budgets under the Transport Rule. EPA chose to use the 
maximum percentage (5 percent) from the Indian country analysis to 
determine the Indian country set-aside for each state on the basis that 
this approach would reserve a reasonable number of allowances from each 
state's budget for potential allocation to new units that may locate in 
Indian country within that state's borders. Any allowances from the 
Indian country new unit set-aside that are not allocated in a given 
control period are redistributed into the state's new unit set-aside. 
As discussed above, any allowances not allocated from that new unit 
set-aside are redistributed to existing units based on the existing 
units' share of the total existing unit allocations.
    To calculate the size of each tribal new unit set-aside, EPA 
applied this 5 percent Indian country factor to the portion of the 
state's new unit set-aside originally determined by accounting for 
``potential'' new units, which as described above was set at 2 percent 
of each pollutant's budget in each state. Therefore, the Indian country 
new unit set-aside is 5 percent of 2 percent of a state's budget, or 
0.1 percent of that total state budget. EPA did not apply the 5 percent 
Indian country factor to the state-specific planned unit portion of 
each state's new unit set-aside because the planned unit portion is 
determined using projected emissions from specific, known units coming 
online after January 1, 2010, and none of these known units are located 
in Indian country.
    The Indian country new unit set-asides in the following Transport 
Rule states with Indian Country are shown in Table VII.D.2-2.

                        Table VII.D.2-2--New Unit Set-Aside Allowances for Indian Country
                                                     [Tons]
----------------------------------------------------------------------------------------------------------------
                                                                                                          Ozone-
                                                                   SO2                Annual    Ozone-    season
                                                      SO2 2012-    2014     Annual     NOX      season     NOX
                                                         2013      and    NOX 2012-    2014   NOX 2012-    2014
                                                                  beyond     2013      and       2013      and
                                                                                      beyond              beyond
----------------------------------------------------------------------------------------------------------------
Florida.............................................  .........  .......  .........  .......        28        28
Iowa................................................       107        75        38        38  .........  .......
Kansas..............................................        42        42        31        26  .........  .......
Louisiana...........................................  .........  .......  .........  .......        13        13
Michigan............................................       229       144        60        58  .........  .......
Minnesota...........................................        42        42        30        30  .........  .......
Mississippi.........................................  .........  .......  .........  .......        10        10
Nebraska............................................        65        65        26        26  .........  .......
New York............................................        27        19        18        18         8         8
North Carolina......................................       137        58        51        42        22        18
South Carolina......................................        89        89        32        32        14        14
Texas...............................................       244       244       134       134        63        63
Wisconsin...........................................        80        40        32        30  .........  .......
----------------------------------------------------------------------------------------------------------------

[[Page 48294]]

    Under the FIPs, EPA allocates allowances from Indian country new 
unit set-asides in essentially the same manner as it allocates 
allowances from state new unit set-asides. The approach for 
identifying, and determining the number of allowances allocated to, new 
units in Indian country is the same as the approach for identifying and 
determining allocations for non-Indian country new units covered by the 
state new unit set-aside, and allocations are made in two rounds using 
the same schedules for promulgation of notices of data availability. 
However, as discussed above, unallocated allowances in the Indian 
country set-asides are handled differently from unallocated allowances 
in the state new unit set-asides in that unallocated Indian country new 
unit set-aside allowances are first transferred back into the state new 
unit set-aside and then, if still not allocated to new units, are 
distributed to existing units in the state. EPA believes that the 
above-described approach in establishing and handling the Indian 
country new unit set-asides and state new unit set-asides is a 
reasonable way of making a sufficient amount of allowances available 
for new units in the state and Indian country located in the state and 
ensuring that the entire state budget is available to either new or 
existing units in the state and Indian country. EPA retains 
administration of these Indian country new unit set-asides (and, of 
course, the portions of state budgets that comprise these set-asides) 
as part of the Transport Rule trading programs even if a state elects 
to modify or replace the Transport Rule FIPs through approved SIP 
revisions. EPA continues to manage and distribute the Indian country 
new unit set-aside allowances in the same manner as under the FIPs. 
Unallocated allowances in the Indian country new unit set-aside will be 
returned to the portion of the state budget allocated under the 
approved SIP's allocation provisions. EPA believes that this approach 
is reasonable because EPA, rather than the states, has the authority 
and responsibility of administering the Transport Rule with regard to 
new units that locate in Indian country.

E. Assurance Provisions

    To ensure that the FIPs require the elimination of all emissions 
that EPA has identified that significantly contribute to nonattainment 
or interfere with maintenance within each individual state, the Agency 
is adopting assurance provisions in addition to the requirement that 
sources hold allowances sufficient to cover their emissions. These 
assurance provisions limit emissions from each state to an amount equal 
to that state's trading budget plus the variability limit for that 
state (i.e., the state assurance level). As discussed in section VI of 
this preamble, this variability limit takes into account the inherent 
variability in baseline EGU emissions and recognizes that state 
emissions may vary somewhat after all significant contribution to 
nonattainment and interference with maintenance are eliminated. This 
approach also provides sources with flexibility to manage growth and 
electric reliability requirements, thereby ensuring the country's 
electric demand will be met, while meeting the statutory requirement of 
eliminating significant contribution to nonattainment and interference 
with maintenance.
    Starting in 2012, EPA is establishing, as part of the FIPs, limits 
on the total emissions that may be emitted from EGUs at sources in each 
state. For any single year, the state's emissions must not exceed the 
state budget with the variability limit allowed for any single year for 
that state (i.e., the state's 1-year variability limit). In other 
words, in addition to covered sources being required to hold allowances 
sufficient to cover their emissions, the total sum of EGU emissions in 
a particular state cannot exceed the state budget with the state's 1-
year variability limit in any 1 year (i.e., the state's assurance 
level). EPA is not finalizing 3-year variability limits that were 
included in the proposal for the reasons explained previously in 
section VI.E of this preamble. The state budgets, variability limits, 
and state assurance levels for each state are shown in Tables VI.F-1, 
VI.F-2 and VI.F-3 in section VI.F of this preamble. The basis for the 
variability limits is also described in section VI.E of this preamble. 
Additional details may be found in the Power Sector Variability Final 
Rule TSD in the docket to this rule.
    To implement this requirement, EPA first evaluates whether any 
state's total EGU emissions in a control period exceeded the state's 
assurance level. If any state's EGU emissions in a control period 
exceed the state assurance level, then EPA applies additional criteria 
to determine which owners and operators of units in the state will be 
subject to an allowance surrender requirement. In applying the 
additional criteria, EPA evaluates which groups of units at the common 
designated representative (DR) level had emissions exceeding the 
respective common DR's share of the state assurance level (regardless 
of whether the source had enough allowances to cover its emissions) 
during the control period.\82\
---------------------------------------------------------------------------

    \82\ A group of one or more sources and units in a state has a 
common designated representative where the same individual is 
authorized as the designated representative (not the alternate 
designated representative) for that group of sources and units as of 
April 1 immediately following the allowance transfer deadline for 
the control period involved.
---------------------------------------------------------------------------

    The requirement that owners and operators surrender allowances 
under the assurance provisions will be triggered only if two criteria 
are met: (1) The group of sources and units with a common DR are 
located in a state where the total state EGU emissions for a control 
period exceed the state assurance level; and (2) that group with the 
common DR had emissions exceeding the respective DR's share of the 
state assurance level. The share of the assurance penalty borne by the 
owners and operators will be based on the amount by which the total 
emissions for the units in the group exceed the common DR's share of 
the state assurance level as a percentage of the total calculated for 
all such groups of sources and units in the state. Thus, the owners and 
operators of each such group of sources and units must surrender an 
amount of allowances equal to the excess of state EGU emissions over 
the state assurance level multiplied by the owners' and operators' 
percentage and multiplied by two (to reflect the penalty of two 
allowances for each ton of the state's excess EGU emissions). See Table 
VII.E-1 below for an illustrative example.
    This approach in the final rule of implementing the assurance 
provisions on a common designated representative basis contrasts with 
the approach in the proposed rule of implementing the assurance 
provisions on an owner basis. In the January 7, 2011 NODA, EPA 
requested comment on the alternative of basing the assurance provision 
penalty using common designated representatives, and some commenters 
supported this alternative. The common designated representative 
approach is simpler and avoids the need to collect information on 
percentage ownership (which information is not used in any other 
provisions of the Transport Rule trading programs).
    In addition, the common designated representative approach provides 
additional flexibility to owners and operators who have only one or a 
few units in a given state but have the option of selecting a common 
designated representative with owners and operators of other units in 
the state. EPA expects companies in various states will readily be able 
to manage their

[[Page 48295]]

emissions to stay collectively below their state's assurance levels as 
they track emissions quarterly throughout the year and manage their 
generation units and pollution control efforts accordingly. However, if 
the state appears to be approaching its assurance level, this final 
rule also gives companies the ability to further ensure that they will 
not have excess emissions by combining multiple units under a common 
DR. This flexibility allows utilities to re-balance allowances and 
emissions to mitigate penalty risk if the state violates its assurance 
level. In a state that does not appear to risk violating its assurance 
level in a given period, utilities would not need to consider the 
assurance aspect of selecting DRs. However, EPA anticipates that in the 
event utilities desire additional certainty or mitigation of assurance 
penalty risk, they will take advantage of this common DR provision or 
pursue similar private arrangements with each other to cover their 
emissions at the lowest possible cost.
    While the DR provision could benefit utilities by allowing them to 
pool their penalty risk, the utilities would still be subject to the 
antitrust laws. As with any joint venture between competitors, the 
efficiency benefits of pooling risk would be weighed against any 
anticompetitive harm associated with DRs.
    This new feature in the final rule, in conjunction with the 
simplifications to the final rule's variability limits described in 
section VI.E, will give companies under the air quality-assured trading 
program greater flexibility in each state to determine the most cost-
effective pattern of emission reductions while EPA ensures each state 
meets its assurance level needed to address the significant 
contribution in each state.
    In the January 7, 2011 NODA, EPA also requested comment on 
continuing to link allocations to assurance provision allowance 
surrender requirements. Even though the final rule uses a different 
allowance allocation methodology than the allocation methodology that 
was proposed, the final rule continues to treat the groups of units 
with greater emissions than their allocations plus share of state 
variability as responsible for the state's excess of emissions over the 
state assurance level. EPA believes that this approach is reasonable 
because any state that exceeds its state assurance level likely does so 
because not all units have made the reductions necessary to eliminate 
the state's contribution to nonattainment or interference with 
maintenance. Moreover, the groups of units with emissions exceeding 
their allocations plus share of variability are the units most likely 
to have contributed to the state's exceedance of its state assurance 
level and thus to the state's triggering of the assurance provisions. 
Consequently, EPA concludes that it is reasonable to penalize owners 
and operators of those sources and units (grouped by common DR) for the 
state's exceedance through application of the assurance provision 
allowance surrender requirement. Some commenters stated that this is a 
reasonable approach.
    While a few commenters suggested alternative approaches to the 
assurance provisions, EPA believes that the suggested alternatives are 
not workable and are likely to create implementation problems. These 
commenters suggested variations of approaches that would have created 
state-specific and vintage year-specific allowances that would have 
been traded independently of compliance allowances. These 
differentiated allowances would have fragmented the allowance markets 
and made the programs resemble the intrastate trading option that EPA 
rejected because of market power and other concerns described in the 
proposal.
    The existence of the assurance provisions with significant 
penalties imposed if a state's emissions exceed the state budget with 
the variability limit, along with other features of the Transport Rule 
trading programs discussed below, will ensure that state emissions stay 
below the level of the budget with the variability limit. In making 
compliance decisions and determining to what extent to rely on 
purchased or banked allowances, owners and operators will have to take 
into account the risk of triggering the assurance provisions in the 
state involved and of incurring significant assurance provision 
penalties. The greater the extent to which units sharing a common DR 
have emissions exceeding the DR units' allocations plus share of the 
state variability limit, the greater the risk of being subject to the 
assurance provision penalties.
    As discussed previously in section VII.D.2, EPA allocates 
allowances to a new unit for the control period during which the unit 
commences commercial operation from the new unit set-aside based on its 
emissions. In the case where assurance provisions for a state are 
triggered in the year that a new unit commences operation, the unit's 
share of the state assurance level is calculated using the unit's 
allocation from the new unit set-aside plus its proportional share of 
the variability limit. There is the possibility that a new unit would 
receive no allocation for the control period during which the unit 
commences commercial operation. EPA sees no reasonable basis for 
disadvantaging owners and operators because they started up a new unit 
and EPA had no emissions data on which to base an allocation from the 
new unit set-aside or no allowances were available for the unit in the 
state's new unit set-aside.\83\ For these new units, EPA would use a 
specific surrogate number to calculate the maximum amount of emissions 
that the unit would likely have had during that year. The surrogate 
emission number applies only if the state's assurance provisions are 
triggered and only in the first year of the new unit's commercial 
operation for a new unit that did not receive an allocation from the 
set-aside. The methodology for calculating the surrogate emission 
number is essentially unchanged from the proposal (75 FR 45313). For 
more details on capacity factors for new units, see ``Capacity Factors 
Analysis for New Units Final Rule TSD.''
---------------------------------------------------------------------------

    \83\ Some other units (e.g., those units with no data for the 
2006-2010 base period) may have a zero allocation for a control 
period. However, those are highly likely to be units that will 
continue to operate rarely or not at all and so will incur little or 
none of the assurance provision penalties.
---------------------------------------------------------------------------

    These assurance provisions are above and beyond the fundamental 
requirement for each source to hold enough allowances to cover its 
emissions in the control period. Failure to hold enough allowances to 
cover emissions is a violation of the CAA, subject to an automatic 
penalty and discretionary civil penalties, as described in section 
VII.F of this preamble.
    Several features of the air quality-assured trading programs work 
in conjunction with the assurance provisions to ensure state emissions 
do not exceed state assurance levels. The air quality-assured trading 
programs have: State-specific budgets that do not include the 
variability limits and that are the basis for allocating allowances in 
each state so that total allocations in a state cannot exceed the state 
budget; a requirement that owners and operators of each source hold 
enough allowances to cover source emissions for each control period; 
assurance provisions that require owners and operators to hold a 
significant amount of additional allowances in a state if the assurance 
provisions are triggered; and additional penalties for failing to hold 
sufficient allowances under the assurance provisions. The underlying 
mechanism of cap and trade--with a cap on allowances issued and a 
requirement to

[[Page 48296]]

hold allowances covering emissions--has succeeded, even without 
assurance provisions, in broadly reducing emissions below allowance 
allocation levels. The accumulated data, history, and experience from 
cap and trade programs underscore that emission reduction requirements 
and environmental and public health goals of the programs have been met 
and, in many instances, exceeded. Additionally, EPA has now added 
assurance provisions to ensure that emissions within a state do not 
exceed the state budget with the variability limitation that eliminates 
the state's significant contribution to nonattainment and interference 
with maintenance in downwind states.
    Emissions from a common DR's group of units in excess of the DR's 
share of the state budget with the variability limit are not a 
violation of the rule or the CAA, but do lead to strict allowance 
surrender requirements. Specifically, the owners and operators with a 
common DR will be required to surrender two allowances for each ton of 
their proportional share of the exceedance of the state budget with the 
variability limit. Failing to hold sufficient allowances to meet the 
allowance surrender requirement will be a violation of the regulations 
and the CAA and subject to discretionary civil penalties under CAA 
section 113. Allowances surrendered to meet an assurance provision 
penalty may be from the year immediately following the control period 
in which the state assurance level was exceeded (i.e., the year during 
which the penalty is assessed) or any prior year. Any future vintage 
allowances beyond the year in which the penalty is assessed may not be 
used to meet an assurance provision penalty.
    This penalty level is a change from the proposal, in which one 
allowance was to be surrendered for each ton of emissions over the 
state assurance level. EPA ran an IPM modeling scenario in order to 
assess the level of penalty that would be sufficient to deter sources 
from exceeding state assurance levels. According to the model, no state 
would exceed its assurance level and incur the two-for-one allowance 
penalty in either 2012 or 2014, although some states emit up to the 
assurance level. The two-for-one allowance surrender requirement is 
significant, and EPA believes that this penalty--along with the other 
elements of the Transport Rule discussed above--will be sufficient to 
ensure that the state emissions will not exceed the budgets plus the 
variability limits. See the Assurance Penalty Level Analysis Final Rule 
TSD for further details of the analysis.
    Below are examples of how the penalty will be assessed for four 
common designated representatives in the same state if the assurance 
provisions are triggered. In the first case, DR1's combined units were 
allowed to emit up to 71 tons of SO2 (60 * 118 percent), but 
actually emitted 75 tons during the control period, or 4 more than 
their share of the state assurance level. Since the state, as a whole 
exceeded the state assurance level by 15 tons, DR1's share of the 
penalty is 25 percent of the total penalty, or 8 allowances (25 percent 
of 30).

                                             Figure VII.E-1--Assurance Provision Allowance Surrender Example
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                             Emissions
                                                           Allocation +                      Emissions         above                          Penalty
                                            Allowances       share of          Total           above       allocation +   Share of state    (allowances
                                             allocated      variability      emissions      allocation       share of     exceedance (%)   surrendered)
                                                                                                            variability
--------------------------------------------------------------------------------------------------------------------------------------------------------
DR1.....................................              60              71              75              15               4             25%               8
DR2.....................................              20              24              33              13               9             56%              17
DR3.....................................              10              12              15               5               3             19%               6
DR4.....................................              10              12              10               0              -2              0%               -
                                         ---------------------------------------------------------------------------------------------------------------
Total...................................             100             118             133              33              15            100%              30
--------------------------------------------------------------------------------------------------------------------------------------------------------
DR1, DR2, DR3, and DR4 are all in the same state.
State budget plus 18 percent variability limit is 118 tons (100 + 18 = 118).
State exceeded its assurance level by 15 tons (133-118 = 15).
Penalty is 2 allowances per ton over the assurance level (2 x 15 = 30).
Some numbers may not add up due to rounding.

    In the proposal, EPA took comment on whether assurance provisions 
should be implemented starting in 2012 or 2014. While a number of 
commenters supported the proposal to start in 2014, EPA received 
several comments making the case that starting assurance provisions in 
2012 would be more compatible with the Court's opinion in North 
Carolina, which emphasized EPA's obligation to require elimination of 
emissions within the states that significantly contribute to 
nonattainment or interfere with maintenance. In this final rule, EPA 
makes the assurance provisions effective starting in 2012 because this 
approach provides even further assurance, consistent with North 
Carolina, that each state's prohibited emissions will be eliminated 
from the start of the Transport Rule trading programs.

F. Penalties

    Under the final Transport Rule FIPs (like under the proposed rule), 
the owners and operators of each covered source must hold, as of the 
allowance transfer deadline, an allowance for each ton of 
SO2 or NOX emitted by the source and are subject 
to penalties if they fail to comply with this allowance-holding 
requirement.
    In particular, the owners and operators must hold in the source's 
compliance account in the Allowance Management System enough allowances 
issued for the respective Transport Rule annual trading program 
(SO2 Group 1, SO2 Group 2, or annual 
NOX program) to cover the annual emissions of the relevant 
pollutant from all covered units at the source. The allowances must 
have been issued for the year in which the emissions occurred or a 
prior year. If the owners and operators fail to meet this allowance-
holding requirement, they must provide--for deduction by the 
Administrator from the source's compliance account--one allowance as an 
offset, and one allowance as an excess emissions penalty, for each ton 
of emissions (i.e., excess emissions) in excess of the amount of 
allowances held. The allowances surrendered for the excess emissions 
penalty must be allocated for the control period in the year 
immediately following the year when the excess emissions occurred or 
for a control period in any prior year. The offset and the excess 
emissions penalty are automatic requirements in

[[Page 48297]]

that they must be met without any further action by EPA (e.g., any 
additional proceedings) regardless of the reason for the occurrence of 
the excess emissions. In addition, each ton of excess emissions, as 
well as each day in the averaging period (i.e., the control period of 
one calendar year), constitute a violation of the CAA, and the maximum 
discretionary civil penalty is $25,000 (inflation-adjusted to $37,500 
for 2010) per violation under CAA section 113. This means that, if a 
source has emissions in excess of allowances held for the source as of 
the allowance transfer deadline for a control period, the number of 
tons of excess emissions multiplied by the total number of days in that 
control period and multiplied by $25,000 (inflation adjusted) equals 
the maximum discretionary civil penalty for that occurrence of excess 
emissions.
    For the ozone-season NOX trading program, the same 
provisions apply as for an annual program, except that the averaging 
period (i.e., the control period) is the ozone season, not a calendar 
year. Consequently, the relevant emissions are for an ozone season, the 
allowances usable to meet the allowance-holding requirement are 
allowances issued for Transport Rule ozone-season NOX 
trading program for the ozone season involved or a prior ozone season, 
and the number of days used in calculating the maximum civil penalty is 
the number in the ozone season.
    Commenters expressed concern that the proposed FIPs expressly 
stated that, for purposes of determining the maximum discretionary 
civil penalty for failure to meet the allowance-holding requirement, 
each ton of emissions lacking a held allowance would be a violation and 
each day in the averaging period involved would be a violation. Some 
commenters compared the proposed penalty provisions for excess 
emissions with the excess emissions penalty provisions under the Acid 
Rain Program and claimed that the proposed penalty provisions differed 
from the Acid Rain Program provisions and were excessive.
    In fact, however, the final FIP provisions concerning discretionary 
civil penalties are essentially the same as those under the Acid Rain 
Program, as well as those under the NOX Budget Trading 
Program and the CAIR trading programs. In particular, the Acid Rain 
Program regulations state that each ton of SO2 excess 
emissions constitutes ``a separate violation'' of the CAA. 40 CFR 
72.9(c)(2). Moreover, while the Acid Rain Program regulations do not 
expressly address that each day in the averaging period (i.e., a 
calendar year control period under the Acid Rain Program) constitutes a 
separate violation when a unit has excess emissions for the calendar 
year, the courts have addressed this question. In decisions applying 
the discretionary civil penalty provisions in section 309(d) of the 
Clean Water Act, which are analogous to the civil penalty provisions in 
CAA section 113, the courts have interpreted the provisions to mean 
that, when a source violates the emission limitation for a multi-day 
control period, the source has a violation for each day in the control 
period, as well as for each ton of excess emissions on each such day. 
See, e.g., Chesapeake Bay Foun. v. Gwaltney of Smithfield, 791 F.2d 
304, 313-15 (4th Cir. 1986), Atlantic States Legal Foun. v. Tyson 
Foods, 897 F.2d 1128, 1139-40 (11th Cir. 1990), and U.S. v.  Allegheny 
Ludlum Corp., 366 F.3d 164, 169 (3d. Cir. 2004). As noted by the 
courts, the treatment of each ton and each day as a separate violation 
is used for purposes of setting the maximum discretionary civil 
penalty. Because CAA section 113 sets the maximum civil penalty, EPA, 
of course, has the discretion to tailor the penalty amount that it 
seeks in any specific occurrence of excess emissions to reflect the 
circumstances of that excess emission occurrence. See 42 U.S.C. 7413(b) 
(stating that the Administrator may commence a civil action ``to assess 
and recover a civil penalty of not more than $25,000 per day for each 
violation''). Moreover, when a district court imposes a civil penalty, 
the court ``retains discretion to assess a penalty much smaller than 
the maximum, as the situation requires.'' Chesapeake Bay, 791 F.2d at 
316. In addition, the Acid Rain Program regulations state that any 
allowance deduction, excess emission penalty, or interest under the 
Acid Rain Program regulations ``shall not affect liability'' of the 
owners and operators ``for any additional fine, penalty, or assessment, 
or their obligation to comply with any other remedy, for the same 
violation, as ordered under the [CAA],'' including under CAA section 
113 providing for discretionary civil penalties. 40 CFR 77.1(b). In 
summary, under the Acid Rain Program, each ton of excess emissions and 
each day in the averaging period (i.e., the calendar year) constitute a 
violation, the resulting number of violations times $2,000 is the 
maximum civil penalty for violating owners and operators, and EPA has 
the discretion to impose a civil penalty at or below such maximum, in 
addition to the automatic requirement to surrender one allowance and 
pay $2,000 (inflation adjusted) for each ton of excess emissions.
    The final FIPs take an analogous approach to that under the Acid 
Rain Program. Specifically, the final FIPs state both that each ton of 
excess emissions is a violation of the CAA and that each day in the 
averaging period (i.e., a calendar year under the annual programs and 
the ozone season under the ozone-season program) is a violation. 
Moreover, the imposition of civil penalties at or below the maximum 
amount resulting from the maximum penalty calculation is in addition to 
the automatic allowance surrender and penalty totaling 2 allowances per 
ton of excess emissions. Thus, commenters' assertion that the approach 
in the final FIPs is inconsistent with the approach in the Acid Rain 
Program is incorrect. Moreover, EPA has taken this same general 
approach in two other trading programs (i.e., the NOX Budget 
Trading Program and the CAIR trading programs), whose regulations 
explicitly state that each ton and each day of the averaging period 
constitute a violation. See 40 CFR 96.54(d)(3) (NOX Budget 
Trading Program); and 40 CFR 96.106(d) (CAIR).
    In any event, EPA maintains that the approach of treating each 
excess emission ton and each day in the averaging period as a violation 
for purposes of calculating the maximum discretionary civil penalty is 
reasonable. Some commenters suggested that only the days on which a 
source's cumulative control period emissions exceed the amount of 
allowances that the source then holds for that control period should be 
treated as a violation. However, this suggested approach makes little 
sense in the context of the Transport Rule trading programs.
    In order to provide owners and operators compliance flexibility, 
the Transport Rule trading programs do not require source owners and 
operators to hold any amount of allowances to cover emissions until the 
allowance transfer deadline, no matter what the source's cumulative 
control period emissions are before that deadline. The commenters' 
approach of comparing--each day, cumulative emissions and allowances 
held--for purposes of calculating maximum civil penalties would be 
inconsistent with the flexibility that EPA intends to provide owners 
and operators. For example, under the commenters' suggested approach, 
owners and operators that buy or sell allowances in the allowance 
market or hold allowances in a company-wide account, do not transfer 
allowances into their source's compliance account until just before the 
allowance transfer deadline, and end up with some excess emissions for 
the calendar year would

[[Page 48298]]

face a significantly higher maximum civil penalty than owners and 
operators that every day increase the amount of allowances held in 
their source's compliance account as the source's cumulative emissions 
increase and end up with the same amount of excess emissions for the 
calendar year. In short, the commenters' approach would penalize owners 
and operators that use some of the compliance flexibility that the 
trading programs are intended to provide.
    EPA also maintains that it is reasonable to both impose the 
automatic allowance surrender and penalty provisions and to retain the 
discretion to impose civil penalties for the same occurrence of excess 
emissions. This approach encourages compliance with the allowance-
holding requirement by ensuring that violating owners and operators are 
penalized automatically (i.e., without any further administrative or 
judicial proceedings, except for appeals) and that EPA can seek 
additional penalties where the circumstances warrant discretionary 
civil penalties. In fact, the Acid Rain Program, for which CAA Title IV 
mandated this approach, has achieved a very high level of compliance 
with the requirement to hold allowances covering SO2 
emissions and therefore resulted in major reductions in utility 
SO2 emissions. See 42 U.S.C.7651j(a). Similarly, the 
NOX Budget Trading Program and CAIR trading programs, which 
took the same approach, also have achieved very high compliance levels 
and major utility emission reductions.
    EPA notes that, in calculating maximum civil penalties when owners 
and operators fail to hold allowances required under the assurance 
provisions in the final FIPs, EPA takes a similar approach in 
determining the number of violations. Each ton for which an allowance 
is not held as required and each day in the control period involved 
constitute a violation of the CAA. As discussed elsewhere in this 
preamble, EPA believes that this calculation approach is also 
reasonable in the context of the assurance provisions and that taking 
an approach like the commenters' suggested approach described above 
would be inconsistent with some of the flexibility that the Transport 
Rule trading programs are intended to provide.

G. Allowance Management System

    The final Transport Rule trading programs, like the proposed 
preferred remedy, utilize EPA's allowance management system (AMS), 
which currently supports allowance surrender, transfer, and tracking 
activity under the Acid Rain Program and CAIR. EPA received no adverse 
comment on this aspect of the proposed rule.
    The primary role of AMS is to provide an efficient, automated means 
for covered sources to comply and for EPA to determine whether covered 
sources are complying, with the emissions-related provisions of the 
Transport Rule trading programs. As was proposed, each of the final 
SO2 trading programs and final NOX trading 
programs is separately handled in the AMS, which is used to track 
Transport Rule trading program SO2 and NOX 
allowances held by covered sources, as well as such allowances held by 
other entities or individuals.
    In addition, the AMS tracks: The allocation of all SO2 
and NOX allowances; holdings of SO2 and 
NOX allowances in compliance accounts (i.e., accounts for 
individual covered sources), general accounts (i.e., accounts for other 
entities such as companies and brokers), and assurance accounts (i.e., 
accounts for allowance surrender by owners and operators of groups of 
sources and units with common designated representatives under the 
assurance provisions); deduction of SO2 and NOX 
allowances for compliance purposes (including deductions from assurance 
accounts where necessary); and transfers of allowances between 
accounts. The AMS also allows the public to see whether each source is 
in compliance and provides information to the allowance market and the 
public in general, including information on ownership of allowances, 
dates of allowance transfers, buyer and seller information, and the 
serial numbers of allowances transferred.

H. Emissions Monitoring and Reporting

    Under the proposed rule, units subject to the Transport Rule 
trading programs would monitor and report NOX and 
SO2 mass emissions in accordance with 40 CFR part 75, as 
incorporated in the proposed rule, and with certain other specified 
requirements, such as compliance deadlines.
    In the final rule, like the proposed rule, covered units must 
comply with emissions monitoring and reporting requirements that are 
largely incorporated from Part 75 monitoring and reporting 
requirements.
    Under the final rule and under Part 75, a unit has several options 
for monitoring and reporting, namely the use of: a CEMS; an excepted 
monitoring methodology (NOX mass monitoring for certain 
peaking units and SO2 mass monitoring for certain oil- and 
gas-fired units); low mass emissions monitoring for certain non-coal-
fired, low emitting units; or an alternative monitoring system approved 
by the Administrator through a petition process. In addition, the 
Administrator can approve petitions for alternatives to Transport Rule 
and Part 75 monitoring, recordkeeping, and reporting requirements.
    Further, the final rule and Part 75 specify that each CEMS must 
undergo rigorous initial certification testing and periodic quality 
assurance testing thereafter, including the use of relative accuracy 
test audits (RATAs) and 24-hour calibrations. In addition, when a 
monitoring system is not operating properly, standard substitute data 
procedures are applied and result in a conservative estimate of 
emissions for the period involved.
    In addition, the final rule and Part 75 require electronic 
submission, to the Administrator and in a format prescribed by the 
Administrator, of a quarterly emissions report. The report must contain 
all of the data required concerning NOX annual and ozone-
season and SO2 annual emissions.
    Most Transport Rule units are in states subject to CAIR and are 
already monitoring and reporting NOX and/or SO2 
under CAIR and the Acid Rain Program, which programs also use Part 75 
monitoring and reporting. Units under the Transport Rule annual trading 
programs and in states subject to CAIR generally have no changes to 
their monitoring and reporting requirements. These units must continue 
to monitor and submit reports on a year-round basis as they have under 
CAIR. Therefore, units in the following states must monitor and report 
both SO2 and NOX year-round under the Transport 
Rule: Alabama, Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky, 
Maryland, Michigan, Minnesota, Missouri, Nebraska, New Jersey, New 
York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, 
Texas, Virginia, West Virginia and Wisconsin.
    Some states (Kansas, Minnesota, and Nebraska) subject to the 
Transport Rule annual trading programs were not subject to CAIR. 
Transport Rule units in those states must meet monitoring and reporting 
requirements that are new except to the extent the units were subject 
to Part 75 under some other program (such as the Acid Rain Program).
    Further, some states (Florida, Louisiana, and Mississippi) subject 
to the Transport Rule ozone-season trading program but not the 
Transport Rule annual trading programs were subject to the annual and 
ozone-season trading programs under CAIR. Transport Rule

[[Page 48299]]

units in those states must continue to monitor and report in accordance 
with Part 75 but have the option of monitoring and reporting on a year-
round or ozone-season-only basis.
    In addition, one state (Arkansas) subject to the Transport Rule 
ozone-season trading program but not to the Transport Rule annual 
trading program was similarly subject to only the ozone-season trading 
program in CAIR. Transport Rule units in that state continue to have 
the option of monitoring and reporting NOX on a year-round 
or ozone-season-only basis.
    Finally, some states (Connecticut, Delaware, District of Columbia, 
and Massachusetts) that were subject to CAIR are not subject to the 
Transport Rule. Electric generating units in those states must continue 
to meet monitoring and reporting requirements only to the extent the 
units are subject to Part 75 under some other program (such as the Acid 
Rain Program or a state adopted program requiring such monitoring and 
reporting).
    EPA is finalizing requirements for existing Transport Rule units in 
states covered by the Transport Rule annual trading programs to monitor 
and report SO2 and NOX emissions by January 1, 
2012 programs and for existing Transport Rule units in states covered 
by the Transport Rule ozone-season trading program to monitor 
NOX emissions by May 1, 2012. The use of Part 75 certified 
monitoring methodologies is required in both cases. As discussed 
previously, most covered existing units will generally have no changes 
to their monitoring and reporting requirements and will continue to 
monitor and submit reports under Part 75 as they have under CAIR. 
Existing units that have not been subject to Part 75 monitoring and 
reporting requirements in the past have less than 1 year to install, 
certify, and operate the required monitoring systems. EPA believes that 
these units will be able to comply with this requirement because the 
monitoring equipment needed is not extensive or is largely in place 
already for the purpose of meeting other requirements. Quality 
assurance and reporting provisions and data system upgrades may be 
necessary, but EPA believes that there is sufficient time to accomplish 
this by the deadline for existing units in the final rule.
    In the proposed rule, the compliance deadline for installing, 
certifying, and operating the required monitoring systems at new units 
was based upon the date of commencement of commercial operation. A new 
unit would have to install and certify its monitoring system within 180 
days of the commencement of commercial operation. The final rule adopts 
this deadline, which is consistent with the approach recently adopted 
in Part 75 under the Acid Rain Program. See 76 FR 17288, 17289 (March 
28, 2011).
    Using this deadline (rather than a deadline, used previously in 
Part 75, of the earlier of the unit's 90th operating day or 180 days 
after the unit's commencement of commercial operation) ensures that new 
units have sufficient time to complete installation and certification 
of monitoring systems and facilitates units' compliance. Because of 
unit shakedown problems, some new units have had difficulty meeting a 
deadline earlier than 180 days after commencement of commercial 
operation. Further, using this deadline facilitates owners' and 
operators, and EPA's, ability to track important dates related to 
monitoring, reporting, and allowance holding. Under the final rule, the 
requirement that a unit hold enough allowances to cover its emissions 
starts on the later of the commencement of the Transport Rule trading 
program involved or the deadline for installation and certification of 
the monitoring system. Having a simple, easily determined deadline (180 
days after the commencement of commercial operation) makes it easier 
for owners and operators and EPA to determine when allowance-holding 
requirements begin, as well as when monitoring and reporting 
requirements begin. In contrast, using a deadline involving 
determination of a unit's 90th operating day required keeping track of 
any days on which the unit did not operate (e.g., due to problems 
associated with shakedown of the unit). EPA found that owners and 
operators have had more difficulty reporting the 90th operating day 
than in reporting the commencement of commercial operation, and once 
the latter date is reported, EPA can independently determine the 180th 
calendar day after the reported date.

I. Permitting

1. Title V Permitting
    The final Transport Rule (like the proposed rule) does not 
establish any permitting requirements independent of those under Title 
V of the CAA and the regulations implementing Title V, 40 CFR Parts 70 
and 71.\84\ All major stationary sources of air pollution and certain 
other sources are required to apply for title V operating permits that 
include emission limitations and other conditions as necessary to 
assure compliance with applicable requirements of the CAA, including 
the requirements of the applicable State Implementation Plan. CAA 
Sec. Sec.  502(a) and 504(a), 42 U.S.C. 7661a(a) and 7661c(a). The 
``applicable requirements,'' that must be addressed in title V permits 
are defined in the Title V regulations (40 CFR 70.2 and 71.2 
(definition of ``applicable requirement'')).
---------------------------------------------------------------------------

    \84\ Part 70 addresses requirements for state Title V programs, 
and Part 71 governs the federal Title V program.
---------------------------------------------------------------------------

    EPA anticipates that, given the nature of the units covered by the 
final Transport Rule, most of the sources at which they are located are 
already or will be subject to Title V permitting requirements. For 
sources subject to Title V, the requirements applicable to them under 
the final FIPs will be ``applicable requirements'' under Title V and 
therefore will need to be addressed in the Title V permits. For 
example, requirements under the final FIPs concerning designated 
representatives, monitoring, reporting, and recordkeeping, the 
requirement to hold allowances covering emissions, the assurance 
provisions, and liability will be ``applicable requirements'' to be 
addressed in the permits.
    The Title V permits program includes, among other things, 
provisions for permit applications, permit content, and permit 
revisions that will address the applicable requirements under the final 
FIPs in a manner that will provide the flexibility necessary to 
implement market-based programs such as the Transport Rule trading 
programs. For example, the Title V regulations provide that a permit 
issued under Title V must include, for any ``approved * * * emissions 
trading and other similar programs or processes'' applicable to the 
source, a provision stating that no permit revision is required ``for 
changes that are provided for in the permit.'' 40 CFR 70.6(a)(8) and 
71.6(a)(8). Consistent with this provision in the Title V regulations, 
the Transport Rule trading program regulations include a provision 
stating that no permit revision is necessary for the allocation, 
holding, deduction, or transfer of allowances. Consistent with the 
Title V regulations, this provision will also be included in each Title 
V permit for a covered source. As a result, allowances can be traded 
(or allocated, held, or deducted) under the final FIPs without a 
revision of the Title V permit of any of the sources involved.
    As a further example of flexibility under Title V, the Title V 
regulations allow the use of the minor permit modification procedures 
for permit modifications ``involving the use of economic incentives, 
marketable permits, emissions trading, and other

[[Page 48300]]

similar approaches, to the extent that such minor permit modification 
procedures are explicitly provided for in an applicable implementation 
plan or in applicable requirements promulgated by EPA.'' 40 CFR 
70.7(e)(2)(i)(B) and 40 CFR 71.7(e)(1)(i)(B). The final FIPs set forth 
in detail, and reference relevant provisions in Part 75 concerning, the 
approaches that are available for covered units to use for monitoring 
and reporting emissions (i.e., approaches using a continuous emission 
monitoring system, an excepted monitoring system under appendices D and 
E to Part 75, a low mass emissions excepted monitoring methodology 
under Sec.  75.19, or an alternative monitoring system under subpart E 
of Part 75). The final FIPs also require unit owners and operators to 
submit monitoring system certification applications (or, for 
alternative monitoring systems, petitions) to EPA establishing the 
monitoring and reporting approach actually to be used by the unit and 
allow owners and operators to submit petitions for alternatives to any 
specific monitoring and reporting requirement. These applications and 
petitions are subject to EPA review and approval to ensure consistency 
in monitoring and reporting among all trading program participants, and 
EPA's responses to any petitions for alternative monitoring systems or 
for alternatives to specific monitoring or reporting requirements are 
to be posted on EPA's Web site. Moreover, EPA intends that each covered 
unit's Title V permit will include a description of the general 
approach that the covered unit is required to use for monitoring and 
reporting emissions and that the description will reference the 
relevant sections of the Transport Rule trading program regulations and 
Part 75 and will state that the requirements may be modified through 
EPA approval of petitions for alternatives to specific requirements. 
Finally, consistent with Sec. Sec.  70.7(e)(2)(i)(B) and 
71.7(e)(1)(i)(B) of the Title V regulations, the final FIPs provide 
that a description of the general monitoring and reporting approach for 
a covered unit can be added to, or an existing description of a unit's 
general monitoring and reporting approach can be changed, in a Title V 
permit, using minor permit modification procedures, provided that the 
approach being described in the changed or new general description and 
the requirements applicable to that approach are already incorporated 
elsewhere in the permit. As a result, minor permit modification 
procedures can be used to revise a covered unit's Title V permit to be 
consistent with the monitoring and reporting approach, or any changes 
in the approach, allowed for the unit by EPA through the monitoring 
system certification or petition process under the Transport Rule 
trading programs.
    As new applicable requirements under Title V, the requirements for 
covered units under the final FIPs will be incorporated into covered 
sources' existing Title V permits either pursuant to the provisions for 
reopening for cause (40 CFR 70.7(f) and 40 CFR 71.7(f)) or the permit 
renewal provisions (40 CFR 70.7(c) and 71.7(c)).\85\ In contrast to the 
approach in CAIR of imposing permitting requirements and deadlines 
independent of those under Title V, the approach to permitting under 
the final FIPS of imposing no independent permitting requirements 
should reduce the burden on sources already required to be permitted 
under Title V and on permitting authorities. For sources newly subject 
to Title V that will also be covered sources under the final FIPs, the 
initial Title V permit issued pursuant to 40 CFR 70.7(a) will address 
the final FIP requirements.
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    \85\ A permit is reopened for cause if any new applicable 
requirements (such as those under a FIP) become applicable to a 
covered source with a remaining permit term of 3 or more years. If 
the remaining permit term is less than 3 years, such new applicable 
requirements will be added to the permit during permit renewal. See 
40 CFR 70.7(f)(1)(i) and 71.7(f)(1)(i).
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    In order to ensure that covered sources' Title V permit provisions 
concerning the final FIPs will reflect the Transport Rule trading 
program requirements and flexibilities properly and in a manner 
consistent from permit to permit, EPA intends to issue guidance to 
assist permitting authorities. This guidance would include information 
on permit issuance and permit modification requirements, as well as a 
permit content template that will identify the applicable requirements 
under the applicable Transport Rule trading program and thereby ensure 
that they will be correctly and comprehensively reflected in each 
permit in a manner that will reduce the burden on sources and 
permitting authorities related to the issuance of the permit and will 
reduce the need for permit revisions.

2. New Source Review

a. Background
    EPA recognizes that, following the vacatur of the new source review 
(NSR) pollution control project exemption in New York v. EPA, 413 F.3d 
3, 40-41 (D.C. Cir. 2005), pollution control projects, including 
pollution control projects constructed to comply with this rule, have 
the potential to trigger NSR permitting.
    This issue was previously addressed in the context of CAIR. On 
December 20, 2005, the EPA agreed to reconsider one specific aspect of 
CAIR. In that notice, EPA granted reconsideration and sought comment on 
the potential impact of the opinion in New York v. EPA, which vacated 
the previously existing NSR exemption for certain environmentally 
beneficial pollution control projects. For this reconsideration, EPA 
conducted an analysis which showed that the court decision did not 
impact the CAIR analyses. Details of this analysis can be found in a 
technical support document which is available on EPA's Web site at: 
http://epa.gov/cair/pdfs/0053-2263.pdf
    Because GHG emissions were not considered by EPA to be air 
pollutants within the meaning of the CAA at the time of CAIR, GHG 
emissions were not addressed in the 2005 analysis. GHG requirements 
related to the component of NSR concerning the Prevention of 
Significant Deterioration (``PSD'') program are addressed in EPA's 
``Interpretation of Regulations that Determine Pollutants Covered by 
Clean Air Act Permitting Programs,'' 75 FR 17004 (April 2, 2010), and 
``Prevention of Significant Deterioration and Title V Greenhouse Gas 
Tailoring Rule,'' 75 FR (June 3, 2010) (``Tailoring Rule''). Generally, 
as discussed in those actions, major stationary sources will be 
required to address GHG emissions as part of the PSD program if these 
sources emit GHG in amounts that equal or exceed the thresholds in the 
Tailoring Rule. Major sources that undergo a modification, including 
the addition of pollution control equipment, will trigger PSD 
requirements for their emissions of GHG if such emissions increase by 
at least 75,000 \86\ tons per year of CO2 equivalent 
(CO2e).
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    \86\ We note that, for sources that are modifying and are not 
subject to PSD for emissions of a non-GHG pollutant, in order to be 
subject to PSD for GHGs the source must not only have an emissions 
increase of 75,000 TPY CO2e, but must also have a PTE of 
at least 100,000 TPY CO2e and 100 TPY mass GHG. See 40 
CFR 52.21(b)(49)(v)(b). However, since it is reasonable to assume 
that all sources that are potentially subject to the Transport Rule 
will have a PTE of at least 100,000 TPY CO2e and 100 TPY, 
for the purposes of discussions in this section we will only note 
the requirement to have an emissions increase of 75,000 TPY 
CO2e.
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b. Proposed Rule
    In the proposed rule, EPA presented the following conclusions:
    (1) The 2005 analysis remains current and relevant for all 
pollutants except for GHG, and it shows that NSR requirements would not 
significantly impact the construction of controls that

[[Page 48301]]

are installed to comply with the proposed Transport Rule.
    (2) It is very unlikely that pollution control projects would cause 
GHG increases that would exceed the 75,000 tons per year threshold.
    Consistent with these proposed conclusions, EPA also concluded that 
there would be no significant impacts from NSR for any pollution 
control projects resulting from the proposed rule such as low-
NOX burners, SO2 scrubbers, or SCR. EPA requested 
comment on this issue.
c. Public Comments
    EPA received a number of comments on the NSR issue, which can be 
divided into four types of comments: (1) Comments related to GHGs, (2) 
comments related to sulfuric acid mist, (3) comments related to CO 
emission increases from low-NOX burners, and (4) suggested 
changes to the EPA rules.
    Greenhouse Gases. A number of commenters recommended that EPA 
should document and substantiate its conclusion that greenhouse gases 
would be unlikely to trigger NSR requirements. Other commenters 
suggested that some units installing a FGD scrubber could exceed the 
75,000 ton threshold for GHGs in the Tailoring Rule by emitting 
CO2 produced from the chemical reaction of SO2 
with limestone. Commenters also suggested that NSR applicability for 
GHGs would also need to consider that an FGD would consume 1-3 percent 
of a scrubbed unit's generation, referred to as ``parasitic load,'' 
which (all else held equal) lowers that unit's net generation.\87\ 
Commenters argued that any post-retrofit increase in generation to 
offset that ``parasitic load'' could lead to GHG increases potentially 
exceeding the 75,000 ton threshold.
---------------------------------------------------------------------------

    \87\ ``Net generation'' refers to total generation minus the 
amount of power consumed on-site for various purposes, including 
operation of pollution control equipment.
---------------------------------------------------------------------------

    Sulfuric Acid Mist. Two commenters noted that use of high sulfur 
fuels, in combination with SCR, can lead to increases in sulfuric acid 
mist, a pollutant regulated under NSR. One of these commenters noted 
that reagent injection was necessary to avoid triggering NSR for 
sulfuric acid mist when their SCR was installed.
    Carbon Monoxide (CO). One commenter believed that EPA's 2005 
analysis may not be adequate as it related to carbon monoxide emission 
increases that result from installation of low-NOX burners. 
The commenter noted EPA's statement in the 2005 analysis that read as 
follows: ``Since the NOX removal efficiencies used in EPA's 
analysis are not aggressive, it is believed that the units installing 
combustion controls can opt for moderate levels of overfire air flow 
rates and still achieve the NOX reduction levels projected 
in EPA's analysis, without causing significant increases in the CO and 
unburned carbon emissions.'' The commenter suggested that the transport 
rule NOX may be more aggressive than CAIR and thus EPA 
should conduct a review to determine whether EPA retains the same 
conclusion regarding CO emissions.
    Recommended Rule Changes. Some commenters suggested changes to EPA 
rules to address their concerns that control equipment installed as a 
result of the Transport Rule could trigger NSR. Some commenters 
suggested that EPA craft an exclusion from NSR in the Transport Rule. 
One of these commenters suggested that EPA could do this by: (1) 
Providing special definition of baseline actual emissions; (2) a 
causation determination specifically tied to the Transport Rule; or (3) 
interpret the term ``stationary source'' in CAA 110(a)(4) in a way that 
doesn't impede Transport Rule compliance.
    Other commenters expressed the concern that if NSR is triggered, 
the proposed Transport Rule did not allow enough time for compliance 
for sources needing to install control equipment. These commenters 
recommend that EPA should waive Transport Rule requirements or provide 
extra allowances until NSR review is complete.
d. Final Rule and Responses to Comments
    Greenhouse Gases. EPA has carefully reviewed relevant data in 
assessing the comments suggesting that NSR permitting would likely be 
triggered for facilities installing FGD scrubbers to comply with this 
rule. EPA believes that sources installing FGD to comply with the 
Transport Rule can achieve those installations without triggering NSR.
    EPA notes that its forecast of the number and extent of FGD 
scrubber installations substantially decreased since the time of 
proposal. For the proposed rule, EPA modeled 14 GW of FGD retrofit 
installations by 2014. For the final rule, EPA models a total of 5.7 GW 
of wet FGD installations from 7 units at 5 plants.
    There are two factors associated with wet FGD scrubbers that 
commenters suggested individually or in combination could lead to 
increases above the 75,000 tons per year threshold in the Tailoring 
Rule. The first is the CO2 chemically produced from the 
reaction of SO2 with limestone in wet FGD scrubbers. The 
second is that owners or operators of the affected units may desire to 
increase coal usage after the retrofit is made to offset the 
``parasitic load'' that is consumed on-site in order to operate the 
scrubber.
    With respect to chemically produced CO2, EPA concludes 
that only in very limited circumstances when installation of a scrubber 
is coupled with a change to considerably higher sulfur coal could 
installation of a wet limestone scrubber be associated with a more than 
75,000 ton increase in CO2 emissions. EPA finds this 
possibility unlikely to occur. For example, EPA's acid rain emissions 
reporting system shows that the plant with the greatest emissions from 
unscrubbed units in 2009 emitted about 103,000 tons of SO2 
from those units. If this plant installed a wet limestone scrubber 
assumed to reduce those SO2 emissions by 96 percent, EPA 
calculates that chemically produced CO2 could increase 
emissions by:

103,000 x (0.96) x (44/64) = 67,980 tons CO2.\88\
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    \88\ The factor 44/64 reflects the relative molecular weight of 
CO2 and SO2, respectively. A wet FGD's removal 
of one ton of SO2 involves a chemical reaction that 
releases the equivalent molecular weight of CO2 (thus 
equaling 44/64 of a ton of CO2 emissions).

    Therefore, EPA finds that all currently uncontrolled units are 
technically capable of retrofitting with wet FGD without chemically 
produced CO2 increases leading to a triggering of NSR. In 
limited circumstances, an owner or operator may elect to switch fuels 
to a significantly higher-sulfur coal subsequent to FGD installation 
and may risk an increase in chemically produced CO2 
emissions that would trigger NSR, but such a decision is not necessary 
in order to successfully install and operate the scrubber as a strategy 
for compliance with Transport Rule requirements.
    With respect to the ``parasitic load'' issue, EPA estimates that 
today's wet FGD retrofit technology would consume typically about 1.7 
percent of on-site generation.\89\ If a facility made no other changes 
to its operation other than installing an FGD retrofit, that facility's 
CO2 emissions from fuel combustion would remain constant. It 
is possible, however, that a source's owner or operator may elect to 
increase coal usage by some amount after retrofitting FGD, if for 
example the owner or operator desires to increase net generation after 
retrofitting. Under NSR, any such source would be able to

[[Page 48302]]

compare such a CO2 emissions increase against the highest 
average annual emissions in any consecutive 24-month period from a 5-
year historic baseline. Therefore, a unit retrofitting a scrubber under 
the Transport Rule may be able to increase its CO2 emissions 
by more than 75,000 tons without triggering NSR if that increase would 
register as less than 75,000 tons against a higher emissions level in 
the aforementioned NSR baseline.
---------------------------------------------------------------------------

    \89\ Documentation Supplement for EPA Base Case v.4.10--
FTransport--Updates for Final Transport Rule.
---------------------------------------------------------------------------

    EPA also notes that scrubber installations provide facilities with 
the opportunity to make other capital improvements at the unit on which 
the scrubber is installed to improve the efficiency of boilers, steam 
turbines, motors, other auxiliary equipment, and plant control systems. 
Such improvements could allow a retrofitting unit to lower its 
CO2 output rate such that a subsequent decision to increase 
net generation may not result in increased coal use, or may limit any 
CO2 emission increase to less than the 75,000 tons per year 
threshold for triggering NSR.
    As discussed in section VII.C, EPA notes that the Transport Rule 
does not mandate any specific control activity, including scrubber 
retrofitting, as a compliance strategy for units within a state to meet 
that state's SO2 budget. As demonstrated by EPA's ``no FGD'' 
sensitivity analysis described in VII.C, covered sources within the 
Group 1 states are capable of meeting their emission reduction 
obligations through a variety of emission reduction strategies even if 
no unit is able to complete a scrubber installation by 2014. Therefore, 
EPA does not believe that NSR permitting presents an obstacle in any 
way to Transport Rule compliance, even if a given unit retrofitting 
with FGD triggers NSR for CO2.
    For some plants, EPA's IPM modeling forecasts installation and 
operation of dry sorbent injection (DSI) systems. EPA does not believe 
any of these systems would result in CO2 emission increases 
above the 75,000 ton threshold. Moreover, given the relatively short 
construction schedule for DSI systems, EPA believes that if any of the 
plants did require NSR permitting, installation of DSI could still be 
accomplished by 2014.
    In summary, EPA believes that the operators of plants projected to 
install scrubbers for Transport Rule SO2 reductions could 
readily develop workable compliance strategies whether or not such an 
installation would trigger NSR. Plant owners could readily develop 
strategies to avoid emission increases that would trigger NSR, 
including but not limited to alternative SO2 reduction 
strategies or technologies, efficiency improvements, or the ability to 
adjust net electricity generation to prevent a 75,000 ton increase in 
CO2 emissions. EPA believes that projected scrubber 
installations under the Transport Rule are broadly unlikely to trigger 
NSR, but even in the limited conditions where such a triggering may 
occur, the NSR permitting process would not infringe on a state's 
ability to comply with its budgets under the Transport Rule. (See 
section VII.C for more details on EPA's analysis of a ``no FGD'' 
sensitivity supporting these points.)
    Sulfuric Acid Mist. EPA continues to conclude that, consistent with 
the 2005 TSD, sulfuric acid mist increases due to compliance with this 
rule are very unlikely to trigger NSR permitting. Such increases are 
most commonly seen from installation of SCR units on facilities with 
relatively high sulfur coal. However, as acknowledged by one of the 
commenters, engineering solutions have been developed to prevent such 
increases, and EPA believes that facility owners would take this into 
account in designing such an SCR system. Moreover, EPA's IPM modeling 
of the NOX budgets in the final rule suggests that no new 
SCR units will result from the final rule.
    Carbon Monoxide. EPA concludes that any NSR permitting required due 
to CO increases associated with NOX controls should not 
hinder the ability of sources to comply with Transport Rule 
requirements. For states that were included in the CAIR for either 
ozone, PM2.5, or both, EPA finds no evidence to suggest that 
the NOX control requirements of the Transport Rule would 
require more aggressive controls triggering NSR. As EPA's baseline 
analysis acknowledges, many sources in these states installed 
NOX controls to comply with CAIR. In addition, their 
historic emissions reflect operation of these controls and there is no 
evidence to suggest that the Transport Rule will require sources to 
operate these controls more aggressively, thereby increasing CO 
emissions above the relevant threshold and triggering NSR. In a few 
states that were not covered by CAIR, a limited number of facilities 
may install new combustion controls (such as low-NOX 
burners, overfire air, or other combustion controls or upgrades) as a 
result of the Transport Rule. EPA expects relatively few such 
installations, and believes that NSR permitting, if required, is not an 
obstacle to compliance with the rule. First, EPA believes that NSR 
permitting should be relatively straightforward for these installations 
and that the BACT determination for CO will be very straightforward. 
EPA expects a relatively short time period for permitting, and as 
discussed later, EPA is planning to initiate actions that will further 
expedite any required permitting.
    Second, EPA notes that the rule achieves reductions through a 
trading program rather than direct control requirements. Accordingly, 
even if a few installations do not have controls in place at the very 
beginning of the compliance period, this should not hinder the ability 
of states to meet their ozone-season NOX budgets. Covered 
sources have a suite of NOX pollution control strategies and 
technologies available to them, including coal selection, selective 
non-catalytic reduction, gas re-burn, low-NOX burner and 
overfire air installations or upgrades, and neural network optimization 
of combustion controls operation. Sources may consider all of these 
technologies and strategies, which can be designed and operated so as 
to minimize CO emission increases that may otherwise trigger NSR. EPA 
also notes that during the downtime for installation of the 
construction controls, there would be no NOX emissions, and 
thus the source's allowance holding requirements would also be lower 
for that period.
    Recommended Rule Changes. EPA disagrees with commenters who 
suggested rule changes, either to the NSR program or to this rule, to 
account for installations triggering NSR. As noted above, EPA concludes 
that NSR would be triggered at most for just a few of the projected 
control installations. EPA believes, however, that even if required 
these NSR permits would likely be issued in a timely manner given the 
overall environmental benefits resulting from the control equipment 
installation. In addition, this rule's requirements are based on a 
flexible trading approach rather than a direct control approach. 
Accordingly, if this affect occurs for only a few installations, EPA 
believes that any extra emissions that occur during the relatively 
short time needed to obtain an NSR permit could be accommodated within 
the overall trading system.
    Expediting Permitting. In the limited circumstances where pollution 
control installations under the Transport Rule may trigger NSR, we also 
note that an expedited permitting process can occur with sufficient 
time to obtain permits and achieve emission reductions under the 
Transport Rule programs. For this reason, we strongly encourage 
permitting authorities to expedite

[[Page 48303]]

permitting for any such projects, which are likely to be very limited 
in number. To ensure that the permitting decisions are expedited, 
separate from this rulemaking EPA will provide assistance and guidance 
in order to expedite issuance of any such permits. For example, we are 
considering assistance that would serve to expedite BACT reviews or 
required air quality analysis. EPA requests early notification of any 
specific cases where such guidance and assistance may be needed.

J. How the Program Structure Is Consistent With Judicial Opinions 
Interpreting the Clean Air Act

    The air quality-assured trading programs established by this rule 
eliminate all of the emissions that EPA has identified as significantly 
contributing to downwind nonattainment or interference with maintenance 
\90\ in a manner that is consistent with section 110(a)(2)(D)(i) of the 
CAA as interpreted by the DC Circuit in North Carolina, 531 F.3d 896. 
The FIPs finalized in this action require sources to participate in air 
quality-assured interstate emission trading programs that include 
provisions to ensure that no state's emissions exceed that state's 
budget with variability limit. These assurance provisions, combined 
with the requirement that all sources hold emission allowances 
sufficient to cover their emissions, effectuate the requirement that 
emission reductions occur within the state. See 42 U.S.C. 
7410(a)(1)(2)(D).
---------------------------------------------------------------------------

    \90\ As explained in greater detail in Section VI of this 
notice, for each covered state, EPA has identified emissions that 
must be prohibited pursuant to section 110(a)(2)(D)(i)(I). In most 
instances, EPA has determined that elimination of such emissions is 
sufficient to satisfy the requirements of that section. Thus, in 
these instances, the budgets represent an estimate of the emissions 
that will remain after the elimination of all emissions in that 
state that significantly contribute to nonattainment or interfere 
with maintenance of the NAAQS in another state. In a few limited 
instances, however, EPA determined that elimination of the emissions 
is necessary but may not be sufficient to satisfy the requirements 
of that section. In these instances, the budgets represent an 
estimate of the emissions that will remain after the elimination of 
all emissions that EPA, at this time, has determined must be 
eliminated.
---------------------------------------------------------------------------

    The state budgets developed in this rule represent an estimate of 
the emissions that will remain in a given state after the elimination 
of all emissions in that state that EPA has determined must be 
prohibited pursuant to section 110(a)(2)(D)(i)(I). However, for the 
reasons explained above, the amount of emissions that remain after the 
requirements of 110(a)(2)(D)(i)(I) are satisfied may vary. EPA 
recognizes that shifts in generation due to, among other things, 
changing weather patterns, demand growth, or disruptions in electricity 
supply from other units can affect the amount of generation needed in a 
specific state and thus baseline EGU emissions from that state. Because 
a state's significant contribution to nonattainment or interference 
with maintenance is defined by EPA as all emissions that can be 
eliminated for a specific cost (as explained above, using air quality 
considerations to identify this cost threshold), and because EGU 
baseline emissions are variable, the amount of emissions remaining in a 
state after all significant contribution or interference with 
maintenance is eliminated is also variable. In other words, EGU 
emissions in a state whose sources have installed all controls and 
taken all measures necessary to eliminate its significant contribution 
to nonattainment or interference with maintenance could exceed the 
state budget without variability.
    For this reason, EPA determined that it is appropriate for the 
program to recognize the inherent variability in state EGU emissions. 
The program does so by identifying a variability range for each state 
in the program. The assurance provisions in the program, in turn, limit 
a state's emissions to the state's budget with variability limit.
    In addition, the requirement that all sources hold emission 
allowances sufficient to cover their emissions (and the fact that the 
total number of emission allowances allocated will be equal to the sum 
of all state budgets without variability) ensures that the use of 
variability limits both takes into account the inherent variability of 
baseline EGU emissions in individual states (i.e., the variability of 
total state EGU emissions before the elimination of significant 
contribution or interference with maintenance) and recognizes that this 
variability is not as great in a larger region. The variability of 
emissions across a larger region is not as large as the variability of 
emissions in a single state for several reasons. Increased EGU 
emissions in one state in one control period often are offset by 
reduced EGU emissions in another state within the control region in the 
same control period. In a larger region that includes multiple states, 
factors that affect electricity generation, and thus EGU emission 
levels, are more likely to vary significantly within the region so that 
resulting emission changes in different parts of the region are more 
likely to offset each other. For example, a broad region can encompass 
states with differing weather patterns, with the result that increased 
electricity demand and emissions due to weather in one state may be 
offset by decreased demand and emissions due to weather in another 
state. By further example, a broad region can encompass states with 
differing types of industrial and commercial electricity end-users, 
with the result that changes in electricity demand and emissions among 
the states due to the effect of economic changes on industrial and 
commercial companies may be offsetting. Similarly, because states in a 
broad region may vary in their degree of dependence on fossil-fuel-
based electric generation, the impact of an outage of non-fossil-fuel-
based generation (e.g., a nuclear plant) in one state may have a very 
different impact in that state than on other states in the region. 
Thus, EPA does not believe it is necessary to allow total regional 
allowance allocations for the states covered by a given trading program 
to exceed the sum of all state budgets without variability for these 
states.
    For these reasons, the fact that the use of state budgets with 
variability limits may allow limited shifting of emissions between 
states is not inconsistent with the court's holding that emission 
reductions must occur ``within the state.'' North Carolina, 531 F.3d at 
907. Under the FIPs, no state may emit more than its budget with 
variability limit and total emissions cannot exceed the sum of all 
state budgets without variability. This approach takes into account the 
inherent variability of the baseline emissions without excusing any 
state from eliminating its significant contribution to nonattainment or 
interference with maintenance. It is thus consistent with the statutory 
mandate of section 110(a)(2)(D)(i)(I) as interpreted by the Court.
    Most commenters voiced support for a remedy option that allows some 
degree of interstate trading. However, one commenter argued that the 
structure of the preferred trading remedy that EPA proposed is legally 
problematic. The program, the commenter argues, provides no legal 
assurance that the variability margins will be used by market 
participants to account for variability. The commenter does not suggest 
a solution, but instead says, if a solution cannot be found, EPA should 
not allow any amount of interstate trading.
    EPA disagrees with the commenter that the structure of the 
preferred interstate trading program is legally problematic. In North 
Carolina, the Court held that the CAIR interstate trading programs were 
inconsistent with section 110(a)(2)(D)(i)(I), concluding that ``EPA's 
apportionment decisions have nothing to do with each state's 
`significant contribution' '' (531 F.3d at

[[Page 48304]]

907) and that ``EPA is not exercising its section 110(a)(2)(D)(i)(I) 
duty unless it is promulgating a rule that achieves something 
measurable toward the goal of prohibiting sources `within the State' 
from contributing to nonattainment or interfering with maintenance `in 
any other State.' '' (531 F.3d at 908). It emphasized that ``[t]he 
trading program is unlawful, because it does not connect states' 
emission reductions to any measure of their own significant 
contributions. To the contrary, it relates their SO2 
reductions to their Title IV allowances. * * * The allocation of 
NOX caps is similarly arbitrary because EPA distributed 
allowances simply in the interest of fairness.'' 531 F.3d at 930. As 
explained in this rule, EPA has addressed these concerns by using 
source specific analysis to identify each individual state's 
significant contribution to nonattainment and interference with 
maintenance, and including assurance provisions to ensure that the 
necessary reductions occur in each state. The Court did not go further 
to prohibit all interstate trading. In fact, it notes that ``after 
rebuilding, a somewhat similar CAIR may emerge'' (531 F.3d at 930). For 
all of these reasons, EPA does not believe the opinion in North 
Carolina can be read to stand for the proposition that no interstate 
trading can be allowed unless the specific reasons behind market 
participants' decisions to purchase allowances can be ascertained. 
Because allowance purchase decisions are likely to be based on multiple 
factors, which can include the desire to hedge against potential 
emission variability as well as to address actually occurring 
variability, requiring ascertainment of the specific reasons for 
allowance purchases would be tantamount to prohibiting all interstate 
trading.
    Moreover, as discussed above, variability is inherent to the 
operation of the electric generation system and thus to emissions from 
this sector. In fact, variability in emissions occurs every year in 
every state and, like variability of year-to-year weather conditions 
(which is a major cause of emission variability), cannot be accurately 
predicted. See the Power Sector Variability Final Rule TSD in the 
docket for this rulemaking. EPA maintains that its approach of allowing 
state EGU emissions each year to vary by up to the historically 
representative, annual amount of inherent, emission variability 
reasonably reflects the realities of the electric generation system and 
is consistent with the North Carolina decision. In summary, the 
variability limits take into account inherent variability over time of 
emissions in each state from this sector while also ensuring that each 
state makes necessary emission reductions to eliminate significant 
contribution and interference with maintenance. EPA thus concludes that 
the commenter's argument that the use of variability limits allows 
sources ``within the state'' to avoid eliminating their significant 
contribution or interference with maintenance is without merit.

VIII. Economic Impacts of the Transport Rule

A. Emission Reductions

    The projected impacts of this final rule as presented throughout 
the preamble do not reflect minor technical corrections to 
SO2 budgets in three states (KY, MI, and NY) made after the 
impact analyses were conducted. These projections also assumed 
preliminary variability limits that were smaller than the variability 
limits finalized in this rule. EPA conducted sensitivity analysis 
confirming that these differences do not meaningfully alter any of the 
Agency's findings or conclusions based on the projected cost, benefit, 
and air quality impacts presented for the final Transport Rule. The 
results of this sensitivity analysis are presented in Appendix F in the 
final Transport Rule RIA.
    Table VIII.A-1 presents projected power sector emissions in the 
base case (i.e., without the Transport Rule or CAIR) compared to 
projected emissions with the Transport Rule in 2012 and 2014 for all 
covered states. Table VIII.A-2 presents 2005 historical power sector 
emissions compared to projected emissions with the Transport Rule in 
2012 and 2014. Note that for ozone-season emissions, these tables 
present results from a modeling scenario that reflects ozone-season 
NOX requirements in 26 states. This modeling differs from 
the final Transport Rule because it includes ozone-season 
NOX requirements for six states (Iowa, Kansas, Michigan, 
Missouri, Oklahoma, and Wisconsin) that the final Transport Rule does 
not cover (as discussed previously, EPA is issuing a supplemental 
proposal to request comment on inclusion of these six states).

  Table VIII.A-1--Projected SO2 and NOX Electric Generating Unit Emission Reductions in Covered States With the
                       Transport Rule Compared to Base Case Without Transport Rule or CAIR
                                                 [Million tons]
----------------------------------------------------------------------------------------------------------------
                                                     2012                                   2014
                                     2012  Base   Transport       2012      2014  Base   Transport       2014
                                        case         rule       Emission       case         rule       Emission
                                     emissions    emissions    reductions   emissions    emissions    reductions
----------------------------------------------------------------------------------------------------------------
SO2...............................          7.0          3.0          4.0          6.2          2.4          3.9
Annual NOX........................          1.4          1.3          0.1          1.4          1.2          0.2
Ozone-Season NOX..................          0.7          0.6          0.1          0.7          0.6          0.1
----------------------------------------------------------------------------------------------------------------

    Notes: The SO2 and annual NOX emissions in 
this table reflect EGUs in the 23 states covered by this rule for 
purposes of the 24-hour and/or annual PM2.5 NAAQS 
(Alabama, Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky, 
Maryland, Michigan, Minnesota, Missouri, Nebraska, New Jersey, New 
York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, 
Texas, Virginia, West Virginia, and Wisconsin).
    The ozone-season NOX emissions reflect EGUs in the 20 
states covered by this rule for purposes of the ozone NAAQS 
(Alabama, Arkansas, Florida, Georgia, Illinois, Indiana, Kentucky, 
Louisiana, Maryland, Mississippi, New Jersey, New York, North 
Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, Texas, 
Virginia, and West Virginia) and the six states that would be 
covered for the ozone NAAQS if EPA finalizes its supplemental 
proposal (Iowa, Kansas, Michigan, Missouri, Oklahoma, and 
Wisconsin).

    Tables VIII.A-3 through VIII.A-5 present projected state-level 
emissions with and without the Transport Rule in 2012 and 2014 from 
fossil-fuel-fired EGUs greater than 25 MW in covered states.

[[Page 48305]]

  Table VIII.A-2--Projected SO2 and NOX Electric Generating Unit Emission Reductions in Covered States With the
                                Transport Rule Compared to 2005 Actual Emissions
                                                 [Million tons]
----------------------------------------------------------------------------------------------------------------
                                                                  2012         2012         2014         2014
                                                     2005      Transport     Emission    Transport     Emission
                                                    Actual        rule      reductions      rule      reductions
                                                  emissions    emissions    from 2005    emissions    from 2005
----------------------------------------------------------------------------------------------------------------
SO2............................................          8.8          3.0          5.8          2.4          6.4
Annual NOX.....................................          2.6          1.3          1.3          1.2          1.4
Ozone-Season NOX...............................          0.9          0.6          0.3          0.6          0.3
----------------------------------------------------------------------------------------------------------------

    Notes: The SO2 and annual NOX emissions in 
this table reflect EGUs in the 23 states covered by this rule for 
purposes of the 24-hour and/or annual PM2.5 NAAQS 
(Alabama, Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky, 
Maryland, Michigan, Minnesota, Missouri, Nebraska, New Jersey, New 
York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, 
Texas, Virginia, West Virginia, and Wisconsin).
    The ozone-season NOX emissions reflect EGUs in the 20 
states covered by this rule for purposes of the ozone NAAQS 
(Alabama, Arkansas, Florida, Georgia, Illinois, Indiana, Kentucky, 
Louisiana, Maryland, Mississippi, New Jersey, New York, North 
Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, Texas, 
Virginia, and West Virginia) and the six states that would be 
covered for the ozone NAAQS if EPA finalizes its supplemental 
proposal (Iowa, Kansas, Michigan, Missouri, Oklahoma, and 
Wisconsin).

[GRAPHIC] [TIFF OMITTED] TR08AU11.001

[[Page 48306]]

[GRAPHIC] [TIFF OMITTED] TR08AU11.002

[[Page 48307]]

[GRAPHIC] [TIFF OMITTED] TR08AU11.003

BILLING CODE 6560-50-C

B. The Impacts on PM2.5 and Ozone of the Final SO2 and NOX Strategy

    The air quality modeling platform described in section V was used 
by EPA to model the impacts of the final rule SO2 and 
NOX emission reductions on annual average PM2.5, 
24-hour PM2.5, and 8-hour ozone concentrations. In brief, we 
ran the CAMx model for the meteorological conditions in the year of 
2005 for the eastern U.S. modeling domain.\91\ Modeling was performed 
for the 2014 base case and the 2014 air quality-assured trading (i.e., 
remedy) scenario to assess the expected effects of the final rule on 
projected PM2.5 and ozone design value concentrations and 
nonattainment and maintenance. The procedures used to project future 
design values and nonattainment and maintenance are described in 
section V.
---------------------------------------------------------------------------

    \91\ As described in the Air Quality Modeling Final Rule TSD, 
the eastern U.S. was modeled at a horizontal resolution of 12 x 12 
km. The remainder of the U.S. was modeled at a resolution of 36 x 36 
km.
---------------------------------------------------------------------------

    The projected 2014 concentrations of annual PM2.5, 24-
hour PM2.5, and ozone at each monitoring site in the East 
for which projections were made are provided in the Air Quality 
Modeling Final Rule TSD. The number of nonattainment and/or maintenance 
sites in the East for the 2012 base case, 2014 base case, and 2014 
remedy for annual PM2.5, 24-hour PM2.5, and ozone 
are provided in Table VIII.B-1.\92\ The average and peak reductions in 
annual PM2.5, 24-hour PM2.5, and ozone predicted 
at 2012 nonattainment and/or maintenance sites due the emission 
reductions between 2012 and the 2014 remedy are provided in Table 
VIII.B-2.
---------------------------------------------------------------------------

    \92\ To provide a point of reference, Table VIII.B-1 also 
includes the number of nonattainment and/maintenance sites based on 
ambient design values for the period 2003 through 2007.

[[Page 48308]]

                Table VIII.B-1--Projected Reduction in Nonattainment and/or Maintenance Problems for PM2.5 and Ozone in the Eastern U.S.
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                               Percent
                                                                                                             reduction:
                                           Ambient (2003-                                                  2012 base case   Percent reduction: 2014 base
                                                2007)      2012 Base case  2014 Base case    2014 remedy      vs. 2014          case vs. 2014 remedy
                                                                                                               remedy
                                                                                                              (percent)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Annual PM2.5 Nonattainment Sites \93\....             103              12               7               0             100  100 percent.
Annual PM2.5 Maintenance-Only Sites......              22               4               3               0             100  100 percent.
24-hour PM2.5 Nonattainment Sites........             151              20              10               1              95  90 percent.
24-hour PM2.5 Maintenance-Only Sites.....              48              21              12               4              81  67 percent.
Ozone Nonattainment Sites................             104               7               4               4              43  No Change.
Ozone Maintenance-Only Sites.............              65               9               6               6              33  No Change.
--------------------------------------------------------------------------------------------------------------------------------------------------------

     Table VIII.B-2--Average and Peak Reduction in Annual PM2.5, 24-Hour PM2.5, and Ozone for Sites That Are
                Projected to Have Nonattainment and/or Maintenance Problems in the 2012 Base Case
----------------------------------------------------------------------------------------------------------------
                                          Average reduction: 2012 base Case    Peak reduction: 2012 base case to
                                                    to 2014 remedy                        2014 remedy
----------------------------------------------------------------------------------------------------------------
Annual PM2.5 Nonattainment Sites.......  2.73 [mu]g/m\3\....................  3.32 [mu]g/m\3\.
Annual PM2.5 Maintenance-Only Sites....  2.99 [mu]g/m\3\....................  3.26 [mu]g/m\3\.
24-hour PM2.5 Nonattainment Sites......  6.8 [mu]g/m\3\.....................  11.7 [mu]g/m\3\.
24-hour PM2.5 Maintenance-Only Sites...  6.5 [mu]g/m\3\.....................  11.0 [mu]g/m\3\.
Ozone Nonattainment Sites..............  1.9 ppb............................  2.3 ppb.
Ozone Maintenance-Only Sites...........  1.8 ppb............................  2.1 ppb.
----------------------------------------------------------------------------------------------------------------

    The information in Table VIII.B-1 shows that there will be 
significant reductions in the extent of nonattainment and maintenance 
problems for annual PM2.5, 24-hour PM2.5, and 
ozone between 2012 and 2014 as a result of the emission budgets in this 
rule coupled with emission reductions during this time period from 
other existing control programs. Specifically, the results of the air 
quality modeling indicate that no sites are projected to be in 
nonattainment or projected to have a maintenance problem for annual 
PM2.5 in 2014 with the emission reductions expected from the 
Transport Rule. As indicated in Table VIII.B-2, the average reduction 
in annual PM2.5 across the twelve 2012 nonattainment sites 
is 2.73 [mu]g/m\3\ and the peak reduction at an individual 
nonattainment site is 3.32 [mu]g/m\3\. Large reductions are also 
projected at annual PM2.5 maintenance-only sites.
---------------------------------------------------------------------------

    \93\ ``Nonattainment'' is used to denote sites that are 
projected to have both nonattainment and maintenance problems.
---------------------------------------------------------------------------

    For 24-hour PM2.5, we project that the number of 
nonattainment sites will be reduced by 95 percent and the number of 
maintenance-only sites by 81 percent in 2014 compared to the 2012 base 
case. The average reduction in 24-hour PM2.5 across the 
twenty 2012 nonattainment sites is 6.8 [micro]g/m\3\ and the peak 
reduction at an individual nonattainment site is 11.7 [micro]g/m\3\. 
Similarly large reductions are projected at 24-hour PM2.5 
maintenance-only sites, as indicated in Table VIII.B-2.
    The emission reductions in the Transport Rule will result in 
considerable progress toward attainment and maintenance at the 5 sites 
that remain as nonattainment and/or maintenance for the 24-hour 
PM2.5 standard. On average for these 5 sites, the predicted 
amount of PM2.5 reduction in 2014 is 64 percent of what is 
needed for these sites to attain and/or maintain the 24-hour standard.
    Thus, the SO2 and NOX emission reductions 
which will result from the Transport Rule will greatly reduce the 
extent of PM2.5 nonattainment and maintenance problems by 
2014 and beyond. As described previously, these emission reductions are 
expected to substantially reduce the number of PM2.5 
nonattainment and/or maintenance sites in the East and make attainment 
easier for those counties that remain nonattainment by substantially 
lowering PM2.5 concentrations in residual nonattainment 
sites. The emission reductions will also help those locations that may 
have maintenance problems.
    Based on the 2012 base air quality modeling for ozone, 16 sites in 
the East are projected to be nonattainment or have problems maintaining 
the 1997 ozone standard. The summer NOX reductions are 
projected to lower 8-hour ozone concentration by 1.8 ppb, on average by 
2014, at monitoring sites projected to be nonattainment and/or have 
maintenance problems in the 2012 base case. We expect that the number 
of nonattainment sites will be reduced by 43 percent and the number of 
maintenance-only sites by 33 percent in 2014 compared to the 2012 base 
case. Thus, our modeling indicates that by 2014 the summer 
NOX emission reductions in this rule, coupled with other 
existing control programs, will lower ozone concentrations in the East 
and help bring areas closer to attainment for the 8-hour ozone NAAQS. 
As discussed in section III of this preamble, EPA plans to finalize its 
reconsideration of the 2008 revised ozone NAAQS soon, and these 
reductions will help areas achieve those revised NAAQS.

C. Benefits

1. Human Health Benefit Analysis
    To estimate the human health benefits of the final Transport Rule, 
EPA used the BenMAP model to quantify the changes in PM2.5 
and ozone-related health impacts and monetized benefits based on 
changes in air quality. For context, it is important to note that the 
magnitude of the PM2.5 benefits is largely driven by the 
concentration response function for premature mortality. Experts have 
advised EPA to consider a variety of assumptions, including estimates 
based both on empirical (epidemiological) studies and judgments 
elicited from scientific experts, to characterize the uncertainty in 
the relationship between PM2.5

[[Page 48309]]

concentrations and premature mortality. For this rule we cite two key 
empirical studies, one based on the American Cancer Society cohort 
study \94\ and the other based on the extended Six Cities cohort 
study.\95\
---------------------------------------------------------------------------

    \94\ Pope et al., 2002. ``Lung Cancer, Cardiopulmonary 
Mortality, and Long-term Exposure to Fine Particulate Air 
Pollution.'' Journal of the American Medical Association. 287:1132-
1141.
    \95\ Laden et al., 2006. ``Reduction in Fine Particulate Air 
Pollution and Mortality.'' American Journal of Respiratory and 
Critical Care Medicine. 173:667-672.
---------------------------------------------------------------------------

    The estimated benefits of this rule are substantial, particularly 
when viewed within the context of the total public health burden of 
PM2.5 and ozone air pollution. A recent EPA analysis 
estimated that 2005 levels of PM2.5 and ozone were 
responsible for between 130,000 and 320,000 PM2.5-related 
and 4,700 ozone-related premature deaths, or about 6.1 percent of total 
deaths from all causes in the continental U.S. (using the lower end of 
the range for premature deaths).\96\ In other words, 1 in 20 deaths in 
the U.S. is attributable to PM2.5 and ozone exposure. This 
same analysis attributed almost 200,000 non-fatal heart attacks, 90,000 
hospital admissions due to respiratory or cardiovascular illness, 2.5 
million cases of aggravated asthma among children, and many other human 
health impacts to exposure to these two air pollutants.
---------------------------------------------------------------------------

    \96\ Fann N, Lamson A, Wesson K, Risley D, Anenberg SC, Hubbell 
BJ. Estimating the National Public Health Burden Associated with 
Exposure to Ambient PM2.5 and Ozone. Risk Analysis; 2011 
In Press.
---------------------------------------------------------------------------

    We estimate that PM2.5 improvements under the Transport 
Rule will, starting in 2014, annually reduce between 13,000 and 34,000 
PM2.5-related premature deaths, 15,000 non-fatal heart 
attacks, 8,700 incidences of chronic bronchitis, 8,500 hospital 
admissions, and 400,000 cases of aggravated asthma while also reducing 
10 million days of restricted activity due to respiratory illness and 
approximately 1.7 million work-loss days. We also estimate substantial 
health improvements for children from fewer cases of upper and lower 
respiratory illness and acute bronchitis.
    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 2014, annual ozone related 
health benefits are expected to include between 27 and 120 fewer 
premature mortalities, 240 fewer hospital admissions for respiratory 
illnesses, 86 fewer emergency room admissions for asthma, 160,000 fewer 
days with restricted activity levels, and 51,000 fewer days where 
children are absent from school due to illnesses.
    Table VIII.C-1 presents the primary estimates of annual reduced 
incidence of PM2.5 and ozone-related health effects for the 
final rule based on 2014 air quality improvements. When adding the PM 
and ozone-related mortalities together, we find that the Transport Rule 
will yield between 13,000 and 34,000 fewer premature mortalities 
annually. By 2014, in combination with other federal and state air 
quality actions, the Transport Rule will address a substantial fraction 
of the total public health burden of PM2.5 and ozone air 
pollution.
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2. Quantified and Monetized Visibility Benefits
    Only a subset of the expected visibility benefits--those for Class 
I areas--are included in the monetary benefit estimates we project for 
this rule. We anticipate improvement in visibility in residential areas 
where people live, work, and recreate within the Transport Rule region 
for which we are currently unable to monetize benefits. For the Class I 
areas we estimate annual benefits of $4.1 billion beginning in 2014 for 
visibility improvements. The value of visibility benefits in areas 
where we are unable to monetize benefits could be substantial.
3. Benefits of Reducing GHG Emissions
    When fully implemented in 2014, the Transport Rule will reduce 
emissions of CO2 from electrical generating units by about 
25 million metric tons annually. Using a ``social cost of carbon'' 
(SCC) estimate that accounts for the marginal dollar value (i.e., cost) 
of climate-related damages resulting from CO2 emissions, 
previous analyses, including the RIA for the Final Rulemaking to 
Establish Light-Duty Vehicle Greenhouse Gas Emissions Standards and 
Corporate Average Fuel Efficiency Standards, have found the total 
benefit of CO2 reductions is substantial. The monetary value 
of these avoided damages also grows over time. Readers interested in 
learning more about the calculation of the SCC metric should refer to 
the SCC TSD, Social Cost of Carbon for Regulatory Impact Analysis Under 
Executive Order 12866 [Docket No. EPA-HQ-OAR-2009-0472].
4. Total Monetized Benefits
    Table VIII.C-2 presents the estimated annual monetary value of 
reductions in the incidence of health and welfare effects. These 
estimates account for increases in the value of risk reduction over 
time. Total monetized benefits are driven primarily by the reduction in 
premature fatalities each year, which account for between 89 and 96 
percent of total benefits.

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5. How do the benefits in 2012 compare to 2014?
    The magnitude of SO2 emission reductions achieved under 
the rule is actually larger in 2012 than in 2014, due to substantial 
emission reductions expected to occur in the baseline (i.e., unrelated 
to the Transport Rule) between those years. As a consequence, EPA 
expects correspondingly greater reductions in harmful effects to accrue 
in 2012 compared to 2014.
    As presented in Table VIII.C-1, the Transport Rule is expected to 
prevent between 13,000 and 34,000 premature deaths annually from 2014 
onward due to reductions in ambient PM2.5 concentrations, 
which are most significantly impacted by SO2 emission 
reductions. Based on EPA's analysis of power sector emission reductions 
under the Transport Rule, the decline in SO2 in 2012 is 4 
percent greater than the decline in SO2 in 2014 in the 
states modeled. EPA therefore anticipates that the Transport Rule will 
deliver greater reductions in ambient PM2.5 concentrations 
in 2012 and increased annual benefits to human health and welfare 
beyond those presented in this section.
6. 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 Transport Rule states 
are $1.85 billion in 2012 and $0.83 billion in 2014 (2007 $). These 
costs are the annual incremental electric generation production costs 
that are expected to occur with the Transport Rule. 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 $0.81 billion in 
2014 assuming either a 3 percent discount rate or a 7 percent discount 
rate. Thus, the annual net benefit (social benefits minus social costs) 
as shown in Table VIII.C-3 for the Transport Rule is approximately $120 
to $280 billion or

[[Page 48314]]

$110 to $250 billion (3 percent and 7 percent discount rates, 
respectively) in 2014. Implementation of the rule is expected to 
provide society with a substantial net gain in social welfare based on 
economic efficiency criteria.
    A listing of the benefit categories that could not be quantified or 
monetized in our benefit estimates is provided in Table VIII.C-4.

     Table VIII.C-3--Summary of Annual Benefits, Costs, and Net Benefits of the Final Transport Rule in 2014
                                             [Billions of 2007$] \a\
----------------------------------------------------------------------------------------------------------------
                                                       Transport Rule remedy  (billions of 2007 $)
              Description              -------------------------------------------------------------------------
                                                  3% discount rate                     7% discount rate
----------------------------------------------------------------------------------------------------------------
Social costs..........................  $0.81..............................  $0.81.
Total monetized benefits \b\..........  $120 to $280.......................  $110 to $250.
Net benefits (benefits-costs).........  $120 to $280.......................  $110 to $250.
----------------------------------------------------------------------------------------------------------------
\a\ All estimates are for 2014, and are rounded to two significant figures.
\b\ The total monetized benefits reflect the human health benefits associated with reducing exposure to PM2.5
  and ozone and the welfare benefits associated with improved visibility in Class I areas. The reduction in
  premature mortalities account for over 90 percent of total monetized PM2.5 and ozone benefits.

    The annualized regional cost of the rule, as quantified here, is 
EPA's best assessment of the cost of implementing the Transport Rule. 
These costs are generated from rigorous economic modeling of changes in 
the power sector expected from the rule. 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 Transport Rule 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 be about $26 million (see section XII.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 this rule, 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 V that new program entrants face.
    An optimization model was employed that assumes cost minimization. 
Costs may be understated if the regulated community chooses not to 
minimize its compliance costs in the same manner to comply with the 
rules. Although EPA has not quantified these costs, the Agency believes 
that they are small compared with the quantified costs of the program 
to the power sector. However, EPA's experience and results of 
independent evaluation suggests that costs are likely to be lower by 
some degree (see RIA for details). 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. These 
impacts are summarized in the RIA for this final rule.
    Every benefit-cost analysis examining the potential effects of a 
change in environmental protection requirements is limited to some 
extent by data gaps, 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, or 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 emission 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. 
This approach calculates a mean value across value of a statistical 
life (VSL) estimates derived from 26 labor market and contingent 
valuation studies published between 1974 and 1991. The mean VSL across 
these studies is $6.3 million (2000$).\97\ The benefits estimates 
generated for this rule are subject to a number of assumptions and 
uncertainties, which are discussed throughout the RIA document.
---------------------------------------------------------------------------

    \97\ In this analysis, we adjust the VSL to account for a 
different currency year (2007$) and to account for income growth to 
2014. After applying these adjustments to the $6.3 million value, 
the VSL is $8.7 million.
---------------------------------------------------------------------------

    As Table VIII.C-2 indicates, total annual monetary benefits are 
driven primarily by the reduction in premature mortalities each year. 
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 24-hour 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.

[[Page 48315]]

    (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) We assume that the health impact function for fine particles is 
linear down to the lowest air quality levels modeled in this analysis. 
Thus, the estimates include health benefits from reducing fine 
particles in areas with varied concentrations of PM2.5, 
including both regions that are in attainment with the fine particle 
standard and those that do not meet the standard down to the lowest 
modeled concentrations.
    The EPA recognizes the difficulties, assumptions, and inherent 
uncertainties in the overall enterprise. The analyses upon which the 
Transport Rule 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 
Transport Rule 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 VIII.C-4.

 Table VIII.C-4--Unquantified and Non-Monetized Effects of the Transport
                                  Rule
------------------------------------------------------------------------
       Pollutant/Effect                         Endpoint
------------------------------------------------------------------------
PM: Health \a\...............  Low birth weight.
                               Pulmonary function.
                               Chronic respiratory diseases other than
                                chronic bronchitis.
                               Non-asthma respiratory emergency room
                                visits.
                               UVb exposure \b\.
PM: Welfare..................  Household soiling.
                               Visibility in residential areas.
                               Visibility in non-class I areas and class
                                1 areas in NW, NE, and Central regions.
                               UVb exposure \b\.
                               Global climate impacts \b\.
Ozone: Health................  Chronic respiratory damage.
                               Premature aging of the lungs.
                               Non-asthma respiratory emergency room
                                visits.
                               UVb exposure \b\.
Ozone: Welfare...............  Yields for:
                               --Commercial forests.
                               --Fruits and vegetables, and
                               --Other commercial and noncommercial
                                crops.
                               Damage to urban ornamental plants.
                               Recreational demand from damaged forest
                                aesthetics.
                               Ecosystem functions.
                               Increased exposure to UVb \b\.
                               Climate impacts.
NO2: Health..................  Respiratory hospital admissions.
                               Respiratory emergency department visits.
                               Asthma exacerbation.
                               Acute respiratory symptoms.
                               Premature mortality.
                               Pulmonary function.
NO2: Welfare.................  Commercial fishing and forestry from
                                acidic deposition effects.
                               Commercial fishing, agriculture and
                                forestry from nutrient deposition
                                effects.
                               Recreation in terrestrial and estuarine
                                ecosystems from nutrient deposition
                                effects.
                               Other ecosystem services and existence
                                values for currently healthy ecosystems.
                               Coastal eutrophication from nitrogen
                                deposition effects.
SO2: Health..................  Respiratory hospital admissions.
                               Asthma emergency room visits.
                               Asthma exacerbation.
                               Acute respiratory symptoms.
                               Premature mortality.
                               Pulmonary function.
SO2: Welfare.................  Commercial fishing and forestry from
                                acidic deposition effects.
                               Recreation in terrestrial and aquatic
                                ecosystems from acid deposition effects.
                               Increased mercury methylation.
Mercury: Health..............  Incidence of neurological disorders.
                               Incidence of learning disabilities.
                               Incidences in developmental delays.
Mercury: Welfare.............  Impact on birds and mammals (e.g.,
                                reproductive effects).
                               Impacts to commercial, subsistence and
                                recreational fishing.
------------------------------------------------------------------------
Source: EPA.
\a\ 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.
\b\ May result in benefits or disbenefits.

[[Page 48316]]

7. What are the unquantified and non-monetized benefits of the 
Transport Rule emission reductions?
    Important benefits beyond the human health and welfare benefits 
quantified in this section and the RIA are expected to occur from this 
rule. These other benefits occur directly from NOX and 
SO2 emission reductions and from co-benefits due to 
Transport Rule compliance. These benefits are listed in Table VIII.C-4. 
Some of the more important examples include: Reduced acidification and, 
in the case of NOX, eutrophication of water bodies; possible 
reduced nitrate contamination of drinking water; and reduced acid and 
particulate deposition that causes damages to cultural monuments, as 
well as, soiling and other materials damage. To illustrate the 
important nature of benefit categories EPA is currently unable to 
monetize, we discuss four categories of public welfare and 
environmental impacts related to reductions in emissions required by 
the Transport Rule: Reduced acid deposition, reduced eutrophication of 
estuaries, reduced mercury methylation and deposition, and reduced 
vegetation impairment from ozone.
a. What are the benefits of reduced deposition of sulfur and nitrogen 
to aquatic, forest, and coastal ecosystems?
    Atmospheric deposition of sulfur and nitrogen, often referred to 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. These compounds are deposited onto 
terrestrial and aquatic ecosystems across the U.S., contributing to the 
problems of acidification.
(1) 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 depends largely on the 
watershed's physical characteristics, such as geology, soils, and size. 
A key indicator of neutralizing ability is termed Acid Neutralizing 
Capacity (ANC). Higher ANC indicates greater ability to neutralize 
acidity. Acidic conditions occur more frequently during rainfall and 
snowmelt that cause high flows of water, and less commonly during low-
flow conditions except where chronic acidity conditions are severe. 
Biological effects are primarily attributable to a combination of low 
pH and high inorganic aluminum concentrations. Biological effects of 
episodes include reduced fish condition factor--changes in species 
composition and declines in aquatic species richness across multiple 
taxa, ecosystems and regions--as well as fish mortality. 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. This 
regulatory action will decrease acid deposition within and downwind of 
the transport region and is likely to have positive effects on the 
health and productivity of aquatic ecosystems in the region.
(2) Acid Deposition and Forest Ecosystem Impacts
    Acidifying deposition has altered major biogeochemical processes in 
the U.S. by increasing the nitrogen and sulfur content of soils, 
accelerating nitrate and sulfate leaching from soil to drainage waters, 
depleting base cations (especially calcium and magnesium) from soils, 
and increasing the mobility of aluminum. Inorganic aluminum is toxic to 
some tree roots. Plants affected by high levels of aluminum from the 
soil often have reduced root growth, which restricts the ability of the 
plant to take up water and nutrients, especially calcium.\98\ These 
direct effects can, in turn, influence the response of these plants to 
climatic stresses such as droughts and cold temperatures. They can also 
influence the sensitivity of plants to other stresses, including insect 
pests and disease,\99\ leading to increased mortality of canopy trees.
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    \98\ U.S. Environmental Protection Agency (U.S. EPA). 2008. 
Integrated Science Assessment for Oxides of Nitrogen and Sulfur--
Ecological Criteria National (Final Report). National
    Center for Environmental Assessment, Research Triangle Park, NC. 
EPA/600/R-08/139. December. http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=201485.
    \99\ Joslin, J.D., Kelly, J.M., van Miegroet, H. 1992. Soil 
chemistry and nutrition of North American spruce-fir stands: 
evidence for recent change. Journal of Environmental Quality, 21, 
12-30.
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    Both coniferous and deciduous forests throughout the eastern U.S. 
are experiencing gradual losses of base cation nutrients from the soil 
due to accelerated leaching from acidifying deposition. This change in 
nutrient availability may reduce the quality of forest nutrition over 
the long term. Evidence suggests that red spruce and sugar maple in 
some areas in the eastern U.S. have experienced declining health 
because of this deposition. For red spruce (Picea rubens), dieback or 
decline has been observed across high elevation landscapes of the 
northeastern U.S. and, to a lesser extent, the southeastern U.S. 
Acidifying deposition has been implicated as a causal factor.\100\
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    \100\ DeHayes, D.H., P.G. Schaberg, G.J. Hawley, and G.R. 
Strimbeck. 1999. Acid rain impacts on calcium nutrition and forest 
health. Bioscience 49(10):789-800.
---------------------------------------------------------------------------

    This regulatory action will decrease acid deposition within and 
downwind of the transport region and is likely to have positive effects 
on the health and productivity of forest systems in the region.
b. 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. A recent assessment of 141 estuaries nationwide by the 
National Oceanic and Atmospheric Administration (NOAA) concluded that 
19 estuaries (13 percent) suffered from moderately high or high levels 
of eutrophication due to excessive inputs of both nitrogen and 
phosphorus, and a majority of these estuaries are located in the 
coastal area from North Carolina to Massachusetts.\101\ For estuaries 
in the Mid-Atlantic region, the contribution of atmospheric 
distribution to total nitrogen loads is estimated to range between 10 
percent and 58 percent.\102\
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    \101\ National Oceanic and Atmospheric Administration (NOAA). 
2007. Annual Commercial Landing Statistics. August. http://www.st.nmfs.noaa.gov/st1/commercial/landings/annual_landings.html.
    \102\ Valigura, R.A., R.B. Alexander, M.S. Castro, T.P. Meyers, 
H.W. Paerl, P.E. Stacy, and R.E. Turner. 2001. Nitrogen Loading in 
Coastal Water Bodies: An Atmospheric Perspective. Washington, DC: 
American Geophysical Union.

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[[Page 48317]]

    Eutrophication in estuaries is associated with a range of adverse 
ecological effects. The conceptual framework developed by NOAA 
emphasizes four main types of eutrophication effects: low dissolved 
oxygen (DO), harmful algal blooms (HABs), loss of submerged aquatic 
vegetation (SAV), and low water clarity. Low DO disrupts aquatic 
habitats, causing stress to fish and shellfish, which, in the short-
term, can lead to episodic fish kills and, in the long-term, can damage 
overall growth in fish and shellfish populations. Low DO also degrades 
the aesthetic qualities of surface water. In addition to often being 
toxic to fish and shellfish, and leading to fish kills and aesthetic 
impairments of estuaries, HABs can, in some instances, also be harmful 
to human health. SAV provides critical habitat for many aquatic species 
in estuaries and, in some instances, can also protect shorelines by 
reducing wave strength. Therefore, declines in SAV due to nutrient 
enrichment are an important source of concern. Low water clarity is the 
result of accumulations of both algae and sediments in estuarine 
waters. In addition to contributing to declines in SAV, high levels of 
turbidity also degrade the aesthetic qualities of the estuarine 
environment.
    Estuaries in the eastern United States are an important source of 
food production, in particular fish and shellfish production. The 
estuaries are capable of supporting large stocks of resident commercial 
species, and they serve as the breeding grounds and interim habitat for 
several migratory species.
    This rule is anticipated to reduce nitrogen deposition within and 
downwind of the Transport Rule states. 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.
c. Mercury Methylation and Deposition
    Mercury is a highly neurotoxic contaminant that enters the food web 
as a methylated compound, methylmercury.\103\ The contaminant is 
concentrated in higher trophic levels, including fish eaten by humans. 
Experimental evidence has established that only inconsequential amounts 
of methylmercury can be produced in the absence of sulfate. Current 
evidence indicates that in watersheds where mercury is present, 
increased SOX deposition very likely results in 
methylmercury accumulation in fish.104 105 The 
SO2 Integrated Science Assessment concluded that evidence is 
sufficient to infer a causal relationship between sulfur deposition and 
increased mercury methylation in wetlands and aquatic environments.
---------------------------------------------------------------------------

    \103\ U.S. Environmental Protection Agency (U.S. EPA). 2008. 
Integrated Science Assessment for Sulfur Oxides--Health Criteria 
(Final Report). National Center for Environmental Assessment, 
Research Triangle Park, NC. September. http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=198843.
    \104\ Drevnick, P.E., D.E. Canfield, P.R. Gorski, A.L.C. 
Shinneman, D.R. Engstrom, D.C.G. Muir, G.R. Smith, P.J. Garrison, 
L.B. Cleckner, J.P. Hurley, R.B. Noble, R.R. Otter, and J.T. Oris. 
2007. Deposition and cycling of sulfur controls mercury accumulation 
in Isle Royale fish. Environmental Science and Technology 
41(21):7266-7272.
    \105\ Munthe, J., R.A. Bodaly, B.A. Branfireun, C.T. Driscoll, 
C.C. Gilmour, R. Harris, M. Horvat, M. Lucotte, and O. Malm. 2007. 
Recovery of mercury-contaminated fisheries. AMBIO:A Journal of the 
Human Environment 36:33-44.
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d. Ozone Vegetation Effects
    Ozone causes discernible injury to a wide array of vegetation.\106\ 
In terms of forest productivity and ecosystem diversity, ozone may be 
the pollutant with the greatest potential for regional-scale forest 
impacts.\107\ Studies have demonstrated repeatedly that ozone 
concentrations commonly observed in polluted areas can have substantial 
impacts on plant function.108 109
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    \106\ Fox, S., Mickler, R.A. (Eds.). 1996. Impact of Air 
Pollutants on Southern Pine Forests. Ecological Studies. (Vol. 118, 
513 pp.) New York: Springer-Verlag.
    \107\ U.S. Environmental Protection Agency (U.S. EPA). 2006. Air 
Quality Criteria for Ozone and Related Photochemical Oxidants 
(Final). EPA/600/R-05/004aF-cF. Washington, DC: U.S. EPA. February. 
http://cfpub.epa.gov/ncea/CFM/recordisplay.cfm?deid=149923.
    \108\ De Steiguer, J., Pye, J., Love, C. 1990. Air Pollution 
Damage to U.S. Forests. Journal of Forestry, 88(8), 17-22.
    \109\ Pye, J.M. 1988. Impact of ozone on the growth and yield of 
trees: A review. Journal of Environmental Quality, 17, 347-360.
---------------------------------------------------------------------------

    Assessing the impact of ground-level ozone on forests in the 
eastern United States involves understanding the risks to sensitive 
tree species from ambient ozone concentrations and accounting for the 
prevalence of those species within the forest. As a way to quantify the 
risks to particular plants from ground-level ozone, scientists have 
developed ozone-exposure/tree-response functions by exposing tree 
seedlings to different ozone levels and measuring reductions in growth 
as ``biomass loss.'' Typically, seedlings are used because they are 
easy to manipulate and measure their growth loss from ozone pollution. 
The mechanisms of susceptibility to ozone within the leaves of 
seedlings and mature trees are identical, and the decreases predicted 
using the seedlings should be related to the decrease in overall plant 
fitness for mature trees, but the magnitude of the effect may be higher 
or lower depending on the tree species.\110\ In areas where certain 
ozone-sensitive species dominate the forest community, the biomass loss 
from ozone can be significant. Significant biomass loss can be defined 
as a more than 2 percent annual biomass loss, which would cause long-
term ecological harm, as the short-term negative effects on seedlings 
compound to affect long-term forest health.\111\
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    \110\ Chappelka, A.H., Samuelson, L.J. 1998. Ambient ozone 
effects on forest trees of the eastern United States: a review. New 
Phytologist, 139, 91-108.
    \111\ Heck, W.W. & Cowling, E.B. 1997. The need for a long term 
cumulative secondary ozone standard--an ecological perspective. 
Environmental Management, January, 23-33.
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    Urban ornamentals are an additional vegetation category likely to 
experience some degree of negative effects associated with exposure to 
ambient ozone levels. Because ozone causes visible foliar injury, the 
aesthetic value of ornamentals (such as petunia, geranium, and 
poinsettia) in urban landscapes would be reduced. Sensitive ornamental 
species would require more frequent replacement and/or increased 
maintenance (fertilizer or pesticide application) to maintain the 
desired appearance because of exposure to ambient ozone.\112\ In 
addition, many businesses rely on healthy-looking vegetation for their 
livelihoods (e.g., horticulturalists, landscapers, Christmas tree 
growers, farmers of leafy crops, etc.) and a variety of ornamental 
species have been listed as sensitive to ozone.\113\
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    \112\ U.S. Environmental Protection Agency (U.S. EPA). 2007. 
Review of the National Ambient Air Quality Standards for Ozone: 
Policy assessment of scientific and technical information. Staff 
paper. Office of Air Quality Planning and Standards. EPA-452/R-07-
007a. July. http://www.epa.gov/ttn/naaqs/standards/ozone/data/2007_07_ozone_staff_paper.pdf.
    \113\ Abt Associates, Inc. 2005. U.S. EPA. Urban ornamental 
plants: sensitivity to ozone and potential economic losses. 
Memorandum to Bryan Hubbell and Zachary Pekar.
---------------------------------------------------------------------------

D. Costs and Employment Impacts

1. Transport Rule Costs and Employment Impacts
    For the affected region, the projected annual private incremental 
costs of the rule to the power industry are $1.4 billion in 2012 and 
$0.8 billion in 2014. These costs represent the private compliance cost 
to the electric generating industry of reducing NOX and 
SO2 emissions to meet the requirements set forth in the 
rule. Estimates are in 2007 dollars.
    In estimating the net benefits of regulation, the appropriate cost 
measure

[[Page 48318]]

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 $0.8 billion annually in 
2014. Overall, the economic impacts of the Transport Rule are modest in 
2014, particularly in light of the large benefits ($120 to $280 billion 
annually at a 3 percent discount rate and $110 to $250 billion annually 
at a 7 percent discount rate) we expect, as shown in section XII.A of 
this preamble. Ultimately, we believe the electric power 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. 
For more information on electricity price changes that result from this 
final rule, refer to section XII.H (Statement of Energy Effects) later 
in this preamble.
    For this 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 United 
States for the entire power system. Documentation for IPM can be found 
in the docket for this rulemaking or at http://www.epa.gov/airmarkets/progsregs/epa-ipm/index.html.
    EPA also included an analysis of impacts of the final rule to 
industries outside of the electric power sector by using the Multi-
Market Model. This model is a partial equilibrium economic impact model 
that includes 100 sectors that cover energy, manufacturing, and service 
applications and is designed to capture the short-run effects 
associated with an environmental regulation. This model was used to 
estimate economic impacts for the proposed MATS, and the promulgated 
industrial boilers major and area source standards and CISWI standard.
    We use the Multi-Market Model to estimate the social costs of the 
final rule. Using this model, we estimate the social costs of the final 
rule to be approximately $0.8 billion (2007 dollars), which is close to 
the compliance costs. Documentation for the Multi-Market Model can be 
found in the RIA for this final rule.
    Also note that as explained in section V.B (Baseline for Pollution 
Transport Analysis), the baseline used in this analysis assumes no 
CAIR. As explained in that section, EPA believes that this is the most 
appropriate baseline to use for purposes of determining whether an 
upwind state has an impact on a downwind monitoring site in violation 
of section 110(a)(2)(D).
    Although a stand-alone analysis of employment impacts is not 
included in a standard cost-benefit analysis, the current economic 
climate has led to heightened concerns about potential job impacts. 
Such an analysis is of particular concern in the current economic 
climate as sustained periods of excess unemployment may introduce a 
wedge between observed (market) wages and the social cost of labor. In 
such conditions, the opportunity cost of labor required by regulated 
sectors to bring their facilities into compliance with an environmental 
regulation may be lower than it would be during a period of full 
employment (particularly if regulated industries employ otherwise idled 
labor to design, fabricate, or install the pollution control equipment 
required under this rule). For that reason, EPA also includes estimates 
of job impacts associated with the final rule. EPA presents an estimate 
of short-term employment opportunities as a result of increased demand 
for pollution control equipment. Overall, the results suggest that the 
final rule could support a net increase of roughly 2,250 job-years in 
direct employment in 2014.
    The basic approach to estimate these employment impacts involved 
using projections from IPM from the final rule analysis such as the 
amount of capacity that will be retrofit with control technologies, for 
various energy market implications, along with data on labor and 
resource needs of new pollution controls and labor productivity from 
secondary sources, to estimate employment impacts for 2014. This 
analysis was also applied for the proposed MATS. For more information, 
refer to Appendix D of the RIA for the final Transport Rule.''
    EPA relied on Morgenstern, et al. (2002), a study that is a basis 
for employment impacts estimated for the final industrial boiler major 
and area source rules and CISWI standard, and the proposed MATS. The 
Morgenstern study identifies three economic mechanisms by which 
pollution abatement activities can indirectly influence jobs: (1) 
Higher production costs raise market prices, higher prices reduce 
consumption, and employment within an industry falls (``demand 
effect''); (2) pollution abatement activities require additional labor 
services to produce the same level of output (``cost effect''); and (3) 
post regulation production technologies may be more or less labor 
intensive (i.e., more/less labor is required per dollar of output) 
(``factor-shift effect'').
    Using plant-level Census information between the years 1979 and 
1991, Morgenstern, et al., estimate the size of each effect for four 
polluting and regulated industries (petroleum, plastic material, pulp 
and paper, and steel). On average across the four industries, each 
additional $1 million spending on pollution abatement results in a 
small net increase of 1.6 jobs; however, the estimated effect is not 
statistically significant. As a result, the authors conclude that 
increases in pollution abatement expenditures do not necessarily cause 
economically significant employment changes. The conclusion is similar 
to Berman and Bui (2001), who found that increased air quality 
regulation in Los Angeles did not cause large employment changes. For 
more information, please refer to the RIA for this final rule.
    The ranges of job effects calculated using the Morgenstern, et al., 
approach are listed in Table VIII.D-1.

                                             Table VIII.D-1--Range of Job Effects for the Electricity Sector
                                                      [Estimates using Morgenstern, et al. (2002)]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                          Demand effect                  Cost effect              Factor shift  effect               Net effect
--------------------------------------------------------------------------------------------------------------------------------------------------------
Change in Full-Time Jobs per      -3.56.......................  2.42........................  2.68........................  1.55.
 Million Dollars of
 Environmental Expenditure \a\.
Standard Error..................  2.03........................  0.83........................  1.35........................  2.24.
EPA Estimate for Final Rule \b\.  + 200 to -3,000.............  + 400 to 2,000..............  0 to 2,000..................  -1,000 to + 3,000.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Expressed in 1987 dollars. See footnote a of Table 8-3 in the RIA for the inflation adjustment factor used in the analysis.
\b\ According to the 2007 Economic Census, the electric power generation, transmission, and distribution sector (NAICS 2211) had approximately 510,000
  paid employees.

[[Page 48319]]

    EPA recognizes there may be other job effects which are not 
considered in the Morgenstern, et al., study. Although EPA has 
considered some economy-wide changes in industry output as shown 
earlier with the Multi-Market model, we do not have sufficient 
information to quantify other associated job effects associated with 
this rule.
2. End-Use Energy Efficiency
    EPA believes that achievement of energy efficiency (EE) 
improvements in homes, buildings, and industry is an important 
component of achieving emission reductions from the power sector while 
minimizing associated compliance costs. By reducing electricity demand, 
energy efficiency avoids emissions of all pollutants associated with 
electricity generation, including emissions of NOX and 
SO2 targeted by this final rule, and reduces the need for 
investments in EGU emission control technologies in order to meet 
emission reduction requirements. Moreover, energy efficiency can often 
be implemented at a lower cost than traditional control technologies.
    EPA recognizes that significant opportunities remain for energy 
efficiency improvements in businesses, homes, and industry. However, 
there are several informational and market barriers that limit 
investment in cost-effective energy efficient practices. Several 
federal programs authorized under the CAA, including ENERGY STAR, are 
designed to address these barriers.
    Congress, EPA, and states have all recognized the value of 
incorporating energy efficiency into air regulatory programs. Several 
allowance-based programs--including the Acid Rain Program, EPA's 
NOX Budget Trading program, and the Regional Greenhouse Gas 
Initiative (an effort of 10 states from the Northeast and Mid-Atlantic 
regions) - have provided mechanisms for rewarding energy efficiency 
through either the award of allowances, typically through the use of a 
fixed set-aside pool, or the use of revenues obtained through the 
auction of allowances. The emission caps established by these programs 
are unaffected by this approach. However, to the extent electricity 
demand reductions are realized, compliance costs are reduced. In 
addition to these allowance-based programs, EPA has also provided 
guidance \114\ concerning the recognition, in SIPs, of emission 
reduction benefits of energy efficiency and has approved the inclusion 
of EE measures in individual SIPs.\115\
---------------------------------------------------------------------------

    \114\ U.S. EPA. 2004. Guidance on State Implementation Plan 
(SIP) Credits for Emission Reductions from Electric-Sector Energy 
Efficiency and Renewable Energy Measures.
    http://www.epa.gov/ttn/oarpg/t1/memoranda/ereseerem_gd.pdf.
    \115\ Metropolitan Washington Council of Governments developed a 
regional air quality plan for the eight-hour ozone standard for the 
DC Region nonattainment area that included an EE measure. The plan 
was adopted by Virginia, Maryland, and the District of Columbia and 
the respective ozone SIPs were approved by the EPA regions in 2007.
---------------------------------------------------------------------------

    While all remedy options considered in the proposed rule would have 
lead to an increase in the relative cost-effectiveness of EE 
investments by internalizing environmental costs associated with 
emission of these pollutants, EPA took comment on whether EPA has 
authority, and whether it would be appropriate for EPA, to consider EE 
in developing the allowance allocation methodology and to consider 
other approaches for encouraging EE in the Transport Rule.
    Some commenters suggested that EPA has authority to consider EE in 
developing the allocation methodology. Other commenters do not believe 
EPA has the authority to consider EE. Some commenters suggested that 
EPA should establish an EE set-aside provision. Other commenters 
suggested that EPA should allow, and help, states to establish EE set-
asides as states transition from Transport Rule FIPs to SIPs. EPA 
believes that, while EE set-asides can be effective at encouraging 
incremental investments in EE, EE set-asides are more likely to be 
practically and effectively implemented at the state level. 
Establishing EE set-asides in the allowance allocation provisions in 
the final rule would not allow for the tailoring of the set-asides to 
the unique characteristics of individual states and would not build on 
the existing EE program delivery infrastructure that many states 
already possess. Instead of establishing EPA-administered EE set-asides 
in the final rule, EPA is clarifying that it allows and supports EE 
set-asides (including auction-based approaches) in abbreviated or full 
SIPs that states may submit, as provided in the final rule. Under this 
approach states have the ability to implement EE set-asides tailored to 
their state circumstances, if they choose. EPA anticipates providing 
additional information in the future for states on EE set-asides, as 
needed.\116\
---------------------------------------------------------------------------

    \116\ Because the question of EPA authority to create EE set-
asides in the FIPs would be best addressed in the context of actual 
FIP provisions for EPA-created EE set-asides and EPA is, for other 
reasons, not adopting such provisions in the final rule, EPA is not 
addressing in the final rule the question of EPA's authority.
---------------------------------------------------------------------------

    As discussed elsewhere in this preamble, the final rule provides 
for submission and approval of abbreviated and full SIPs providing for 
continued state participation in the Transport Rule trading programs, 
and adopting alternative allowance allocation methodologies (which may 
include EE set-asides) to the allocation methodologies adopted in the 
FIPs. While the final rule establishes certain requirements for 
approval of any such alternative allocation methodology, the final rule 
provides states flexibility to create state-implemented EE set-asides.

IX. Related Programs and the Transport Rule

A. Transition From the Clean Air Interstate Rule

1. Key Differences Between the Transport Rule and CAIR
    The Transport Rule replaces CAIR and its associated trading 
programs. There are a number of differences between implementation of 
the Transport Rule and implementation of CAIR. This section describes 
key implementation differences including differences in states covered, 
compliance deadlines, applicability, structure of the remedy, 
provisions for early reductions, and provisions for SIPs. The next 
section discusses the transition from CAIR to the Transport Rule.
    States covered. The states covered by the Transport Rule differ 
somewhat from states covered by CAIR. This section summarizes 
differences in state coverage. EPA's approach to determine states 
covered by the Transport Rule is discussed in sections V and VI of this 
preamble.
    The Transport Rule's SO2 and annual NOX 
requirements apply to covered sources in the 23 states listed in Table 
III-1 in section III of this preamble. CAIR's SO2 and annual 
NOX requirements applied to covered sources in 25 states. 
There are many states in common between the Transport Rule and CAIR 
SO2 and annual NOX programs. The differences are 
summarized in Table IX.A-1.

[[Page 48320]]

 Table IX.A-1--Differences in SO2 and Annual NOX State Coverage Between
                       the Transport Rule and CAIR
------------------------------------------------------------------------
                                  Transport rule SO2     CAIR SO2 and
             State                  and annual NOX        annual NOX
                                       programs            programs
------------------------------------------------------------------------
Kansas.........................  Yes................  No.
Minnesota......................  Yes................  No.
Nebraska.......................  Yes................  No.
Delaware.......................  No.................  Yes.
District of Columbia...........  No.................  Yes.
Florida........................  No.................  Yes.
Louisiana......................  No.................  Yes.
Mississippi....................  No.................  Yes.
------------------------------------------------------------------------

    The Transport Rule's ozone-season NOX requirements apply 
to covered sources in the 20 states listed in Table III-1 in section 
III of this preamble, while CAIR's ozone-season NOX 
requirements applied to 26 states. There are many states in common 
between the Transport Rule and CAIR ozone-season NOX 
programs. The differences are summarized in Table IX.A-2.

Table IX.A-2--Differences in Ozone-Season NOX State Coverage Between the
                         Transport Rule and CAIR
------------------------------------------------------------------------
                                    Transport rule
             State                 ozone-season NOX    CAIR ozone-season
                                       program            NOX program
------------------------------------------------------------------------
Georgia........................  Yes................  No.
Texas..........................  Yes................  No.
Connecticut....................  No.................  Yes.
Delaware.......................  No.................  Yes.
District of Columbia...........  No.................  Yes.
Iowa...........................  No.................  Yes.
Massachusetts..................  No.................  Yes.
Michigan.......................  No.................  Yes.
Missouri.......................  No.................  Yes.
Wisconsin......................  No.................  Yes.
------------------------------------------------------------------------

    In addition, EPA is proposing a supplemental notice to apply 
Transport Rule ozone-season requirements to the states of Iowa, Kansas, 
Michigan, Missouri, Oklahoma, and Wisconsin, as discussed in section 
III of this preamble.
    The transition from CAIR to the Transport Rule is discussed in 
section IX.A.2 and SIPs are discussed in section X of this preamble.
    Compliance deadlines. The Transport Rule reduction requirements 
commence January 1, 2012 for annual NOX and SO2 
requirements and May 1, 2012 for ozone-season NOX 
requirements. More stringent SO2 reduction requirements 
commence January 1, 2014 for Group 1 states.
    In contrast, the first phase of CAIR NOX reductions 
commenced January 1, 2009 for annual NOX requirements and 
May 1, 2009 for ozone-season NOX requirements. On January 1, 
2010, the first phase of CAIR SO2 requirements commenced. 
However, in anticipation of CAIR, SO2 reductions actually 
started as early as 2006 because of the incentive to reduce emissions 
and bank Title IV Acid Rain Program SO2 allowances for use 
when their value would increase under CAIR in 2010 and later. The 
second phase of CAIR reductions would have (if not replaced by the 
Transport Rule) commenced January 1, 2015 for annual NOX and 
SO2 requirements, and May 1, 2015 for ozone-season 
NOX requirements.
    Applicability. Except for the changes to the states covered, the 
general applicability provisions of the final Transport Rule trading 
programs are essentially the same as the CAIR general applicability 
provisions, with a few exceptions.
    First, the final Transport Rule does not allow any non-covered 
units to opt into the trading programs, for the reasons discussed in 
section VII.B of this preamble. In contrast, under CAIR, through SIPs, 
the states could elect to allow boilers, combustion turbines, and other 
combustion devices to opt into the CAIR trading programs under opt-in 
provisions specified by EPA.
    Second, the Transport Rule FIPs' ozone-season NOX 
trading program applicability provisions do not cover NOX 
SIP Call small EGUs and non-EGUs that a number of CAIR states brought 
into the CAIR ozone-season NOX trading program. The 
Transport Rule does allow any state in the ozone-season NOX 
program, through SIPs, to expand the applicability of the Transport 
Rule ozone-season NOX trading program to cover small EGUs. 
However, the Transport Rule does not allow states to expand the 
applicability to cover NOX SIP Call non-EGUs, for the 
reasons discussed elsewhere in this preamble.
    In contrast, in the CAIR trading programs, a NOX SIP 
Call state could expand the applicability of the CAIR ozone-season 
NOX trading program in the state in order to include all 
units subject to the NOX Budget Trading Program under the 
NOX SIP Call. A number of states chose to expand the CAIR 
ozone-season NOX trading program applicability in this way. 
The transition from CAIR to the Transport Rule is discussed in section 
IX.A.2 and SIPs are discussed in section X of this preamble.
    Structure of the remedy. The CAIR FIPs (and CAIR model trading 
rules adopted by a number of states in their CAIR SIPs) implemented 
reductions through SO2, annual NOX, and ozone-
season NOX interstate emission trading programs covering 
primarily large EGUs. The owners and operators of a covered source 
could buy allowances

[[Page 48321]]

from or sell allowances to other covered sources (or other market 
participants) and were required to surrender allowances equal to the 
source's emissions for each compliance period. CAIR's trading programs 
did not impose limitations on the aggregate emissions from covered 
units within any covered state.
    The Transport Rule FIPs will also achieve the required reductions 
through SO2, annual NOX, and ozone-season 
NOX interstate trading programs. However, in contrast to 
CAIR and for the reasons discussed in section VII of this preamble, the 
Transport Rule FIPs include assurance provisions specifically designed 
to ensure that no state's emissions will exceed that state's emission 
budget plus the variability limit, i.e., the state's assurance level.
    Another difference in the remedy structure is in the design of the 
SO2 trading programs. In CAIR all of the states required to 
reduce SO2 emissions were grouped together in one 
SO2 trading program with no restriction on the use of 
SO2 allowances from any state in the program by any source 
in the program. In contrast, and for the reasons discussed in section 
VI of this preamble, the Transport Rule divides states required to 
reduce SO2 emissions into two groups with emission reduction 
requirements of different stringency starting in 2014 (SO2 
Group 1, whose reduction requirements become more stringent starting in 
2014, and SO2 Group 2, whose reduction requirements in 2014 
do not change). A covered source may only use for compliance--with the 
requirements to hold allowances covering emissions and, if applicable, 
to surrender allowances under the assurance provisions--an 
SO2 allowance issued for the SO2 Group in which 
the source's state is included. In other words, an SO2 Group 
1 source may only use a SO2 Group 1 allowance for 
compliance, and likewise an SO2 Group 2 source may only use 
a SO2 Group 2 allowance for compliance.
    Provisions for early reductions. CAIR included provisions for 
covered sources to make early reductions prior to the start of CAIR's 
SO2 and NOX trading programs, bank emission 
allowances, and carry banked allowances into its trading programs. In 
contrast, the Transport Rule does not include provisions for covered 
sources to carry over any allowances (i.e., Title IV SO2 
allowances or CAIR annual or ozone-season NOX allowances) 
into the Transport Rule trading programs. EPA's reasons for not 
allowing the use of banked Title IV SO2 allowances or CAIR 
annual or ozone-season NOX allowances in the Transport Rule 
trading programs are discussed in the next section.
    Provisions for SIPs. The following is a summary of the key 
differences between the Transport Rule and CAIR provisions for SIPs. A 
more detailed discussion of Transport Rule SIPs is in section X of this 
preamble.
    The SIP provisions in the Transport Rule and CAIR are very similar. 
Both include provisions that allow states to submit SIP revisions 
(referred to as full SIPs) that replace an applicable FIP trading 
program with a comparable SIP trading program that has certain limited 
differences from the FIP trading program. Similarly, both rules include 
provisions that allow states to submit SIP revisions (referred to as 
abbreviated SIPs) that may modify certain limited provisions in the FIP 
trading program, which remain in place. Inclusion of this provision in 
the Transport Rule allows a state to modify certain elements of a 
Transport Rule FIP trading program in order to better meet the needs of 
the state. Both the Transport Rule and CAIR allow full or abbreviated 
SIPs that involve one or more applicable FIP trading programs. However, 
there are a few differences.
    In particular, under the Transport Rule, states may submit SIP 
revisions under which the state determines allocations for the 
applicable trading program using either full or abbreviated SIP 
revisions. States could submit similar revisions under CAIR. Under the 
Transport Rule, the state may use the same allocation methodology as 
that currently used in the Transport Rule FIP trading program or some 
other allocation methodology. However, the Transport Rule specifies 
certain requirements that must be met concerning, for example, the 
timing of such allocation determinations, and expressly allows 
allowance auctions to be used. CAIR did not include similar provisions. 
Further, the SIP submission deadlines, allocation submission, and 
allocation recordation dates are different between the Transport Rule 
and CAIR. The Transport Rule SIP submission deadlines and allocation 
recordation dates are discussed in section X of this preamble.
    In addition, both the Transport Rule and CAIR include provisions 
that allow states to submit SIP revisions under which the state expands 
the general applicability provisions of the ozone-season NOX 
trading programs to cover certain units subject to the NOX 
SIP Call. However, for the reasons discussed elsewhere in this 
preamble, this flexibility is more limited in the Transport Rule than 
it was in CAIR.
    While CAIR allowed states to adopt, through full or abbreviated 
SIPs, opt-in provisions, the Transport Rule does not allow for opt-in 
provisions. The reasons for this are discussed in section VII.B of this 
preamble.
    Finally, neither full nor abbreviated SIPs can replace FIP 
provisions that apply to units in Indian country within the borders of 
a state. For example, the FIPs include, for states within whose borders 
Indian country is located, an Indian country new unit set-aside. For 
states not having Indian country within their borders, abbreviated SIPs 
are limited to replacing the allowance allocation provisions of the 
FIPs for the state involved and may replace some or all of those 
provisions. However, for states having Indian country within their 
borders, abbreviated SIPs cannot replace the FIP provisions for the 
Indian country new unit set-aside. Similarly, for states not having 
Indian country, full SIPs can replace an entire FIP, but, in doing so, 
can only change the allowance allocation provisions. For states having 
Indian country, full SIPs can replace the FIPs except for the Indian 
country new unit set-aside provisions, which will remain under the 
applicable FIPs, and, like the abbreviated SIPs, can only change the 
allowance allocation provisions that are replaced.
    Details of the Transport Rule provisions for abbreviated and full 
SIP revisions, including deadlines for submission to EPA, are discussed 
in section X of this preamble.
2. Transition From the Clean Air Interstate Rule to the Transport Rule
    The Transport Rule replaces CAIR and its associated trading 
programs. This section elaborates on areas of transition from CAIR to 
the Transport Rule.
a. Sunsetting of CAIR, CAIR SIPs, and CAIR FIPs
    The proposal explained that, for control periods in 2012 and 
thereafter, CAIR, CAIR SIPs, and CAIR FIPs would be replaced entirely 
by the Transport Rule provisions. The proposal outlined implementation 
of the sunsetting of CAIR and CAIR FIPs, through revisions to CAIR, 
Sec. Sec.  51.123 and 51.124, and the CAIR FIPs, Sec. Sec.  52.35 and 
52.36. For the control period in these years, the CAIR trading programs 
would not continue, and the Administrator would not carry out any of 
the functions established for the Administrator in the CAIR model 
trading rule, the CAIR FIPs, or any state trading programs approved 
under CAIR. Offset and automatic penalty provisions under CAIR would 
not apply to excess emissions for 2011 control periods.

[[Page 48322]]

    Also discussed were the processes for modifying provisions in Part 
52 reflecting state-specific CAIR SIP and CAIR FIP requirements, which 
would vary depending on whether a state has an approved CAIR SIP or a 
CAIR FIP. The proposal further explained that sources in some states 
covered by CAIR or the CAIR FIPs would not be subject to the Transport 
Rule and that to the extent that CAIR reductions were needed or relied 
upon to satisfy other SIP requirements, states might need to find 
alternative ways to satisfy requirements for their SIPs.
    EPA is finalizing regulatory changes to sunset CAIR and the CAIR 
FIPs. The final rule revises the general CAIR and CAIR FIP provisions 
in Parts 51 and 52 applicable to all CAIR states. For control periods 
in 2012 and thereafter, the Administrator rescinds the determination 
that states must meet SIP requirements under CAIR, and the requirements 
of the CAIR FIPs are not applicable. Further, with regard to these 
control periods, the Administrator will no longer carry out any of the 
functions established for the Administrator in the CAIR model trading 
rule, the CAIR FIPs, or any state trading programs approved under CAIR 
with the exception of enforcing the provisions for the previous control 
periods, if necessary.
    For the reasons discussed in the proposed rule preamble (75 FR 
45337), CAIR allowances allocated for these control periods cannot be 
used in any CAIR trading program and, as discussed below, in any 
Transport Rule trading program. Specifically, for the reasons discussed 
in the proposed rule, offset and automatic allowance penalty provisions 
in the CAIR trading programs will not be applied to 2011 control period 
excess emissions, which will remain subject to discretionary civil 
penalties under CAA section 113. EPA still retains all enforcement 
options for excess emissions during the 2011 control period. CAIR 
allowances allocated for 2012 and thereafter are not usable in any CAIR 
or Transport Rule trading program. In light of that fact, in order to 
prevent any confusion by owners and operators and other members of the 
public concerning the status of such allowances, the final rule 
provides that, within 90 days after publication of the final Transport 
Rule, the Administrator will remove post-2011 CAIR annual 
NOX and ozone-season allowances from the Allowance Tracking 
System.
    The CAIR SO2 trading program, of course, uses Acid Rain 
allowances, which will remain in the Allowance Tracking System because 
they were created by CAA Title IV and continue to be usable in the Acid 
Rain Program.
    The final rule also adopts the discussion in the proposed rule 
concerning state-specific Part 52 provisions concerning CAIR (75 FR 
45337-38). With regard to Part 52 provisions reflecting EPA's adoption 
of ongoing CAIR FIPs for some individual states, the final rule revises 
the CAIR FIP provisions to make them inapplicable to control periods in 
2012 and thereafter and to require the Administrator to remove from the 
Allowance Tracking System, CAIR allowances for these control periods. 
The final, state-specific CAIR FIP provisions in Part 52 essentially 
echo the language in the final, general CAIR provisions in Part 52 
discussed above. In making the CAIR FIP provisions inapplicable to 
control periods in 2012 and thereafter, the final, state-specific 
provisions sunset the applicable CAIR FIP trading programs whether or 
not the CAIR FIPs were revised by approved, abbreviated CAIR SIPs. 
(Under CAIR, abbreviated CAIR SIPs were adopted by certain states so 
that states, rather than EPA, made NOX allowance 
allocations.) Consequently, states with approved, abbreviated CAIR SIPs 
will not need to revise their abbreviated CAIR SIPs in order to sunset 
the CAIR trading programs to which these abbreviated SIPs applied. 
Thus, although such abbreviated SIPs may remain in the state SIPs, they 
will have no force and effect, once the CAIR FIPs sunset.
    With regard to Part 52 provisions reflecting EPA's approval of full 
CAIR SIPs submitted to EPA by many individual states, the Court's North 
Carolina decision essentially overrides these Agency approvals of 
individual CAIR SIPs. (Under CAIR, full CAIR SIPs were adopted by 
certain states to replace CAIR FIPs and continue participation through 
the CAIR SIPs in the CAIR trading programs.) The Court found CAIR to be 
illegal and only allowed it to remain in effect temporarily. For this 
reason, the CAIR SIPs though approved, can have no force and effect 
once CAIR is replaced by this rule. For this reason, although the 
proposed rule indicated that states would need to submit SIP revisions 
to, among other things, make the CAIR SIPs inapplicable to control 
periods after 2011, the final rule does not require states to take any 
actions to revise their full or abbreviated CAIR SIPs. For states 
covered by CAIR or CAIR FIPs that are not subject to the Transport Rule 
and have relied on CAIR reductions to satisfy other SIP requirements, 
EPA will discuss with states alternative ways to satisfy requirements 
for those SIP requirements, e.g., through intrastate cap and trade 
programs that require the level of reductions on which the state has 
recently relied.
b. NOX SIP Call Units
    The NOX Budget Trading program was used by states to 
reduce ozone-season NOX emissions from EGUs and large non-
EGUs under NOX SIP Call requirements. The program started in 
2003 and ended in 2008. Under CAIR, a state subject to the 
NOX SIP Call was allowed to expand the applicability of the 
CAIR ozone-season NOX trading program in the state in order 
to include all units subject to the NOX Budget Trading 
Program under the NOX SIP Call and thereby to continue to 
meet the state's NOX SIP Call requirements. Fourteen states 
chose to expand the CAIR ozone-season NOX applicability in 
this way, while six states chose not to expand the applicability and 
instead to meet their NOX SIP Call obligations in other 
ways. EPA proposed to not allow this expansion in applicability for the 
Transport Rule, primarily because these sources as a group did not 
actually reduce emissions for the NOX Budget Trading Program 
or CAIR. EPA took comment on the proposed approach.
    Several commenters generally advocated allowing, at state 
discretion, all NOX Budget Trading Program units to be 
regulated under the Transport Rule ozone-season NOX trading 
program. Some also questioned how states would otherwise satisfy 
NOX SIP Call requirements for these units. Some commenters 
argued that some units did in fact make emission reductions in the 
NOX Budget Trading Program, but did not provide information 
on specific units.
    The final rule provides states an option to expand the general 
applicability provisions of the Transport Rule ozone-season 
NOX trading program to cover small EGUs, but not other units 
in the NOX SIP Call. Specifically, consistent with the 
comments, EPA determined that it is appropriate to allow states to 
expand the applicability of the Transport Rule ozone-season 
NOX trading program to include units serving a generator 
with a nameplate capacity equal to or greater than 15 MWe producing 
electricity for sale. This will allow states with NOX SIP 
Call obligations to meet those requirements with respect to these small 
EGUs. These units can be brought into the program through abbreviated 
or full Transport Rule SIPs. However, if a state chooses to expand the 
general applicability provisions, the state Transport Rule ozone-season 
NOX budget cannot be increased. EPA believes that the level 
of

[[Page 48323]]

emissions from small EGUs is sufficiently small that the existing 
Transport Rule state budget can accommodate these units. This is 
consistent with the approach taken in the NOX Budget Trading 
Program, where the states that added these small EGUs did not increase 
their NOX SIP Call EGU budgets. This also removes concern 
(expressed in the proposed rule) that increasing state budgets in the 
Transport Rule ozone-season NOX trading program, as part of 
the expansion of the applicability provisions to include small EGUs, 
would jeopardize elimination of a state's significant contribution to 
nonattainment and interference with maintenance.
    With regard to large non-EGUs that were included in the 
NOX Budget Trading Program (the remainder of the sources in 
the NOX Budget Trading Program), the final Transport Rule, 
like the proposed rule, does not allow expansion of the general 
applicability provisions for the ozone-season NOX trading 
program to include such units. As explained in the proposed rule (75 FR 
43340), while some of these units may have installed controls around 
the start of the NOX Budget Trading Program, EPA analysis 
shows that, as a group, these units did not collectively reduce 
emissions, their current emission rates are nearly identical to their 
emission rates before the start of the NOX Budget Trading 
Program, and their allocations are about twice their emissions, with 
the result that the excess allocations were sold to covered EGUs.\117\ 
Moreover, EPA believes that there are little or no emission reductions 
available by non-EGUs at the cost thresholds used in the final rule and 
so no basis for developing non-EGUs state budgets reflecting the 
elimination of significant contribution to nonattainment and 
interference with maintenance. For these reasons, the final rule allows 
states to expand the ozone-season NOX trading program to 
cover small EGUs that were in the NOX Budget Trading 
Program, but not to cover large non-EGUs that were in that program. As 
explained in the proposed rule, if a state were to do so, emissions 
from these units could jeopardize elimination of the state's 
significant contribution to nonattainment or interference with 
maintenance. See 75 FR 45340. For states that relied on large non-EGUs 
for emission reductions required by the NOX SIP Call, EPA 
will assist in identifying ways to ensure continued, future compliance 
with the NOX SIP Call requirements.
---------------------------------------------------------------------------

    \117\ Although the proposed rule discussed the EPA analysis in 
the context of considering the treatment of both small EGUs and 
large non-EGUs from the NOX Budget Trading Program, the 
analysis actually addresses, and draws conclusions about emission 
reductions, emission rates, and allowance allocations concerning 
only large non-EGUs.
---------------------------------------------------------------------------

c. Early Reduction Provisions
    Substantial emission reductions have occurred as a result of 
previous emission trading programs, under both Title IV and CAIR. This 
has lead to substantial ``banks'' of allowances (i.e., holdings of 
unused allowances allocated for years before the programs sunset) in 
each of the CAIR programs. In the proposal, EPA requested comment on 
whether to allow banked CAIR allowances to be used in the Transport 
Rule trading programs. EPA recognizes the importance of continuity in 
emission trading programs as a general principle. However, for the 
reasons explained below, EPA has decided not to allow banked CAIR 
allowances to be used in any of the Transport Rule trading programs. 
(1) SO2 Allowance Bank
    The bank of Title IV allowances was more than 12 million tons at 
the end of 2009. This bank is the result of emission reductions under 
the Title IV Acid Rain Program. Under the CAIR SO2 trading 
program, EPA allowed banked (as well as future year) Title IV 
allowances to be used in the CAIR SO2 trading program--in 
lieu of being used in the Acid Rain Program--for compliance with the 
requirement to hold allowances covering SO2 emissions. This 
approach encouraged early reductions for the CAIR SO2 
trading program, but was held to be unlawful in North Carolina.
    In the proposed rule, EPA took comment on whether sources should be 
allowed to use banked Title IV allowances in the Transport Rule 
SO2 program. EPA proposed to not allow the use of Title IV 
allowances either as the basis for allocating Transport Rule 
SO2 allowances or directly for compliance with allowance-
holding requirements, in part, because EPA was concerned that those 
approaches would be perceived as inconsistent with the requirements of 
CAA section 110(a)(2)(D)(i)(I) as interpreted by the Court in North 
Carolina. See 75 FR 45338-39.
    A number of commenters advocated that EPA recognize Title IV 
allowance holdings in the Transport Rule, either by allowing full or 
limited carryover of the allowances or by allocating all or a portion 
of the Transport Rule SO2 allowances based on Title IV 
allowance holdings. Other commenters agreed with EPA's assessment that 
allowing Title IV allowance carryover in the Transport Rule is 
inconsistent with North Carolina and that any linkage of Transport Rule 
allocations with Title IV allowance holdings would carry unnecessary, 
significant legal risk. Therefore, for the reasons explained above and 
in the proposal, EPA has decided not to permit sources to use Title IV 
allowances for compliance with the Transport Rule SO2 
trading programs.
    In addition, unlike CAIR, in the Transport Rule, EPA decided not to 
base allocation of Transport Rule SO2 allowances on the 
specific distribution of existing Title IV allowances. Title IV 
allowances continue, of course, to be usable for compliance in the Acid 
Rain Program.\118\
---------------------------------------------------------------------------

    \118\ The Title IV allowance bank is expected to be about 14 
million tons at the beginning of 2012.
---------------------------------------------------------------------------

(2) NOX Allowance Banks
    In the proposed rule, EPA estimated that the CAIR ozone-season 
NOX bank would contain over 600,000 allowances and the CAIR 
annual NOX bank would contain about 720,000 allowances after 
completion of true-up of allowance holdings and emissions for 2011. EPA 
considered the alternatives of allowing or not allowing pre-2012 CAIR 
NOX allowances and CAIR ozone-season NOX 
allowances to be used in the Transport Rule NOX trading 
programs.
    EPA also described and requested comment on several possible 
approaches for handling banked pre-2012 CAIR NOX allowances 
in the Transport Rule NOX trading programs and the pros and 
cons of each (75 FR 45339):
     Allow all such banked CAIR allowances to be brought into 
the Transport Rule NOX programs, make the assurance 
provisions effective starting in 2012, and rely on the assurance 
provisions to ensure that each state continues to eliminate all of its 
significant contribution to nonattainment and interference with 
maintenance;
     Allow only a limited amount of banked pre-2012 CAIR 
allowances to be brought into the Transport Rule NOX 
programs;
     Factor the bank into the calculation of state 
NOX budgets by reducing the state NOX budgets to 
take account of the banked pre-2012 CAIR allowances; and
     Do not allow the use of any banked pre-2012 CAIR 
allowances in the Transport Rule NOX programs.
    EPA proposed the last of these approaches and requested comment on 
all of the described approaches or suggestions on other ways to handle 
banked pre-2012 CAIR allowances in the Transport Rule NOX 
programs.

[[Page 48324]]

     Many commenters advocated allowing the carryover of CAIR 
NOX allowances to the Transport Rule. Reasons given 
included: preservation of early reduction investments; need for market 
continuity; increased flexibility during program start up and early 
years of the programs; preservation of the credibility of, and 
certainty under, trading approaches; and the lack of a prohibition in 
North Carolina of carryover of CAIR NOX allowances. 
Commenters also suggested that surrender ratios be used to limit the 
amount, and negative effects, of a carryover.
     Many other commenters were against allowing CAIR 
NOX allowance carryover into the Transport Rule. Reasons 
given included: unnecessary, significant legal risk; concerns about the 
efficacy of the Transport Rule if state budgets are supplemented by a 
carryover; and differences in the nature of the programs (the 
NOX Budget Trading Program, which addressed the 1-hour ozone 
NAAQS, and the CAIR ozone-season NOX trading program, which 
addressed the 1997 8-hour ozone NAAQS and was reversed in North 
Carolina) under which the allowances were banked, and the Transport 
Rule ozone-season NOX trading program, which addresses the 
1997 8-hour ozone NAAQS.
    For the reasons explained below, after evaluating all comments on 
this issue, EPA decided not to allow the use of CAIR NOX 
allowances in the Transport Rule NOX trading programs. EPA 
reevaluated the estimated size of the potential carryover (allowances 
that will remain unused in the CAIR programs at the end of 2011 
compliance periods), taking into account 2010 emissions. EPA estimates 
that more than 440,000 CAIR ozone-season NOX allowances will 
remain and that more than 460,000 CAIR annual NOX allowances 
will remain at the end of the 2011 compliance periods. EPA considered 
whether to allow these CAIR ozone-season NOX and CAIR annual 
NOX allowances to be used in the Transport Rule 
NOX trading programs. The CAIR ozone-season NOX 
allowances expected to remain unused represent nearly three-quarters of 
aggregate state ozone-season NOX budgets \119\ in a single 
year under the final Transport Rule. The allowances expected to remain 
unused in the annual NOX program represent more than one-
third of aggregate state annual NOX budgets in a single year 
under the Transport Rule. As discussed in the proposal, if these 
allowances were carried over in addition to the Transport Rule state 
budgets, EPA could not be assured that significant contribution to 
nonattainment or interference with maintenance would be eliminated. EPA 
therefore rejects any approach under which all banked CAIR 
NOX allowances would be added to the Transport Rule trading 
programs on top of each state's annual NOX and/or ozone-
season NOX budgets.
---------------------------------------------------------------------------

    \119\ This analysis is for all states identified to be 
contributing significantly to nonattainment or interfering with 
maintenance. When the analysis is conducted using the aggregate 
state budgets for only those states for which we are finalizing 
ozone season requirements in this rule, the percentage increases.
---------------------------------------------------------------------------

    In response to public comments, EPA considered whether the 
Transport Rule trading programs should allow some form of exchange of 
banked CAIR annual NOX and ozone-season allowances for new 
Transport Rule NOX allowances within each state's annual 
NOX and/or ozone-season budgets, respectively. However, EPA 
believes that this type of approach carries substantial legal and 
technical problems. First, the state-by-state distribution of CAIR 
NOX allowances resulted from the methodology applied by EPA 
in CAIR of using fuel factors to set the total amounts of allowance 
allocations in each state (i.e., the state NOX budgets). The 
CAIR NOX allowance banks therefore are--at least in part--
the result of this methodology, which was reversed in North Carolina. 
See North Carolina, 531 F.3d at 918-22. Thus, EPA did not use fuel 
factors in developing the Transport Rule state budgets. However, EPA is 
concerned that the distribution of some or all Transport Rule 
NOX allowances through exchanges of banked CAIR 
NOX allowances for Transport Rule NOX allowances 
would blur the bright line between the methodology used for setting 
budgets in the Transport Rule and the methodology used for setting 
budgets in CAIR that was rejected by the Court. At least to some 
extent, the parties that were advantaged under EPA's budget-setting 
methodology in CAIR would continue to have an advantage under the 
Transport Rule by receiving more Transport Rule NOX 
allowances. EPA therefore believes that allowing exchange of banked 
CAIR NOX allowances for Transport Rule NOX 
allowances carries significant legal risk.
    Second, establishing a procedure for exchanging banked CAIR 
NOX allowances for Transport Rule NOX allowances 
within each state's budget would mean that Transport Rule 
NOX allowances could not be allocated until after completion 
of the process for determining compliance with allowance-holding 
requirements for 2011 in the CAIR NOX trading programs. This 
process cannot begin until after the allowance transfer deadline for 
the 2011 control periods (i.e., March 1, 2012 for the CAIR annual 
NOX program and November 1, 2011 for the CAIR ozone-season 
NOX program) and will not likely be completed until mid-
2012. At that time, EPA could begin the procedure of implementing, 
state-by-state, the exchanges of the remaining CAIR NOX 
allowance banks held by parties (owners and operators, brokers, and 
other entities) for some or all of the allowances in the state 
NOX budgets for 2012. The portion of each state budget that 
would be used up by such exchanges would likely vary from state to 
state. The resulting delay, and uncertainty about the unit-by-unit 
amounts, of Transport Rule NOX allowance allocations for 
2012 would undermine Transport Rule allowance market liquidity, 
significantly disrupt planning by owners and operators for compliance 
with allowance-holding requirements for the 2012 control periods, and 
likely impose increased compliance costs under the Transport Rule 
NOX trading programs or impact the ability to comply with 
the 2012 limits.
    In light of the specific circumstances in this case and the above-
described legal and technical problems that would result from a 
carryover of CAIR NOX allowances into the Transport Rule 
trading programs, the final rule does not allow any such carryover. EPA 
agrees that, as a general principle, it is desirable to provide 
continuity between sequential regulatory programs involving emission 
trading and thereby to ensure that allowances in the past program 
continue to have some value in the new program. Balancing the general 
desirability of providing program continuity against the potential 
negative consequences of a carryover in, and the specific circumstances 
of, this case, EPA concludes that the carryover of banked CAIR 
NOX allowances into the Transport Rule trading programs 
should not be allowed. EPA notes that, in this case, it signaled the 
possibility that it would take such an approach in order to provide 
markets with full information and avoid unnecessary disruptions. After 
CAIR was remanded by the Court in North Carolina, 550 F.3d 1176, in 
December 2008, EPA was concerned about the future status of CAIR 
NOX allowances and consequently advised the public--through 
a statement posted on the EPA Web site in March, 2009--that ``EPA's 
continued recording of CAIR NOX allowances does not 
guarantee or imply that any allowances will continue to be usable for

[[Page 48325]]

compliance after a replacement rule is finalized or that they will 
continue to have value in the future.'' \120\ EPA believes its decision 
to disallow carryover of banked allowances here reflects the specific 
factors in this case and should not be treated as setting any precedent 
for the treatment, in any future trading programs, of any past trading 
program's banked allowances.
---------------------------------------------------------------------------

    \120\ http://epa.gov/airmarkets/business/cairallowancestatus.html. EPA posed similar statements in the on-
line systems for trading CAIR NOX allowances. See 40 CFR 
96.102 and 96.302 (definitions of ``CAIR NOX Allowance 
Tracking System'' and ``CAIR NOX Ozone Season Allowance 
Tracking System'').
---------------------------------------------------------------------------

    However, EPA notes that, under the CAIR ozone-season NOX 
trading program, where unused allowances were carried forward from the 
preceding NOX Budget Trading Program, and under the CAIR 
annual NOX trading program, where extra allowances (from the 
compliance supplement pool) were allocated for early reductions made 
during the NOX Budget Trading Program, the vast majority of 
allowance allocation decisions were made by the states administering 
these programs. Moreover, a number of states did not allocate CAIR 
allowances to their sources using fuel adjustment factors, whose use 
the Court rejected in North Carolina in connection with EPA's setting 
of state NOX emission budgets.
    In light of the general desirability of providing continuity 
between state programs, states may want to address the CAIR 
NOX banks when developing, in SIP revisions, the Transport 
Rule allowance allocations for control periods after 2012. EPA 
encourages each state that wants to allocate Transport Rule 
NOX allowances through SIP revisions to consider using 
information on the CAIR NOX allowance banks that will remain 
after 2011. Any such allowance allocations, of course, must be within 
the respective state's NOX trading budget, and must be 
submitted to EPA within the applicable submission deadlines, 
established in the final rule for the control periods for which the 
allocations are made. The Agency intends to contact states concerning 
the desirability of holding a workshop to discuss issues related to 
state allowance allocations.

B. Interactions With NOX SIP Call

    The proposed rule explained that states covered by both the 
NOX SIP Call and the Transport Rule would be required to 
comply with the requirements of both rules and that the Transport Rule 
would not preempt or replace the requirements of the NOX SIP 
Call. Most, but not all, NOX SIP Call states would be 
included in the Transport Rule. The proposed rule further explained 
that the Transport Rule ozone-season NOX trading program 
would achieve the emission reductions required by the NOX 
SIP Call from EGUs serving generators with a nameplate capacity greater 
than 25 MW and producing electricity for sale in most NOX 
SIP Call states. (This would not be the case, of course, for those 
NOX SIP Call states not covered by the Transport Rule.)
    The NOX SIP Call states used the NOX Budget 
Trading Program to comply with the NOX SIP Call requirements 
for EGUs serving a generator with a nameplate capacity greater than 25 
MW and large non-EGUs with a maximum rated heat input capacity greater 
than 250 mmBtu/hour. (In some states, EGUs serving a generator with a 
nameplate capacity of 25 MW or less were also included in the 
NOX Budget Trading Program as a carryover from the Ozone 
Transport Commission NOX Budget Trading Program.) EPA 
stopped administering the NOX Budget Trading Program under 
the NOX SIP Call after the completion of compliance 
activities related to the 2008 ozone-season control period, and states 
used other mechanisms to comply with the NOX SIP Call 
requirements.
    The proposal further explained that, if EPA promulgated a final 
rule that did not allow the expansion of the Transport Rule to 
NOX Budget Trading Program units, any state that allowed 
these units to participate in the CAIR ozone-season NOX 
trading program would need to submit a SIP revision to address the 
state's NOX SIP Call requirement for the reductions. The 
proposal also explained that states in the CAIR ozone-season 
NOX trading program or the NOX Budget Trading 
Program that would not be in the Transport Rule ozone-season 
NOX trading program would need to submit SIP revisions 
addressing the NOX SIP Call requirements for any emission 
reductions (by EGUs and non-EGUs) addressed in the NOX 
Budget Trading Program and not addressed in some other way. See 75 FR 
45340-41.
    As discussed elsewhere in this preamble, the final Transport Rule 
allows states to expand the general applicability provisions of the 
Transport Rule ozone-season NOX trading program to include 
small EGUs, which were included by some states in the NOX 
Budget Trading Program, but not for large non-EGUs, which were included 
in the NOX Budget Trading Program. This will allow states 
with NOX SIP Call obligations to meet those requirements 
with respect to small EGUs brought into the Transport Rule trading 
program, but not with regard to large non-EGUs.
    With the issuance of the final Transport Rule, NOX SIP 
Call requirements remain in place. See 40 CFR 51.121. EPA is not 
changing any of the NOX SIP Call requirements. The 
NOX SIP Call generally requires that states choosing to rely 
on large EGUs and large non-EGUs for meeting NOX SIP Call 
emission reduction requirements must establish a NOX mass 
emissions cap on each source and require Part 75, subpart H monitoring. 
As an alternative to source-by-source NOX mass emissions 
caps, a state may impose NOX emission rate limits on each 
source and use maximum operating capacity for estimating NOX 
mass emissions or may rely on other requirements that the state 
demonstrates to be equivalent to either the NOX mass 
emissions caps or the NOX emission rate limits that assume 
maximum capacity. Collectively, the caps or their alternatives cannot 
exceed the portion of the state budget for those sources. See 40 CFR 
51.121(f)(2) and (i)(4). EPA will work with states to ensure that 
NOX SIP Call obligations continue to be met (e.g., through 
intrastate cap and trade programs that require the level of reductions 
on which the state has recently relied).

C. Interactions With Title IV Acid Rain Program

    The final rule does not affect any Acid Rain Program requirements. 
Acid Rain Program requirements are established independently in Title 
IV of the CAA and are not replaced by the Transport Rule. Title IV 
sources that are subject to final Transport Rule provisions still need 
to continue to comply with all Acid Rain provisions. Title IV 
SO2 and NOX requirements continue to apply 
independently of the Transport Rule provisions. For the reasons 
explained above, Title IV SO2 allowances are not allowed to 
be used in the Transport Rule trading programs. Similarly, Transport 
Rule SO2 allowances are not usable in the Acid Rain Program.
    The final Transport Rule does not include any opt-in unit 
provisions in the FIPs and does not allow SIP revisions to include opt-
in unit provisions in the Transport Rule trading programs. 
Consequently, no sources, including those that have opted in to the 
Acid Rain Program, can opt-in to the Transport Rule trading programs.
    There will likely be changes to emissions at some Acid Rain units 
outside of the Transport Rule area as a result of the transition from 
CAIR to the Transport Rule. Namely, emissions at some non-Transport 
Rule Acid Rain

[[Page 48326]]

units in the states that border the Transport Rule states may increase 
because of potential load-shifting from units in Transport Rule states 
and because of a potential decrease in the Title IV allowance price. 
There is a discussion of possible emission increases in non-covered 
states in section VI.C of this preamble.

D. Other State Implementation Plan Requirements

    In this final action, EPA has not conducted any technical analysis 
to determine whether compliance with the Transport Rule would satisfy 
RACT requirements for EGUs in any nonattainment areas, or Regional Haze 
BART-related requirements. For that reason, EPA is neither making 
determinations nor establishing any presumptions that compliance with 
the Transport Rule satisfies any RACT or BART-related requirements for 
EGUs. Based on analyses that states conduct on a case-by-case basis, 
states may be able to conclude that compliance with the Transport Rule 
for certain EGUs fulfills nonattainment area RACT requirements. EPA 
intends to undertake a separate analysis to determine if compliance 
with the Transport Rule would provide sufficient reductions to satisfy 
BART requirements for EGUs in accordance with Regional Haze Rule 
requirements for alternative BART compliance options as soon as 
practicable following promulgation of the Transport Rule.

X. Transport Rule State Implementation Plans

    EPA proposed (75 FR 45342) FIPs setting state-specific emission 
reduction requirements for each upwind state covered by the proposed 
Transport Rule and with respect to one or more of three air quality 
standards--the 1997 annual PM2.5 NAAQS, the 2006 24-hour 
PM2.5 NAAQS, and the 1997 ozone NAAQS. In CAIR, EPA allowed 
the states to replace the CAIR FIP with SIPs and provided substantial 
flexibility. In the proposed Transport Rule, EPA proposed to allow 
similar flexibility to states for addressing the CAA section 
110(a)(2)(D)(i)(I) transport issues through a SIP. EPA proposed to 
allow a state to submit a SIP for the ozone requirements only, for the 
PM2.5 requirements only, or for both the ozone and the 
PM2.5 requirements with the specific quantity of emission 
reductions necessary for a state's SIP determined based on the state 
emission budgets provided in the final Transport Rule.
    EPA received comments suggesting that if the proposal's remedy were 
finalized, EPA should allow states to replace the FIP allowance 
allocation provisions in the proposed Transport Rule trading programs 
by state-developed allocation provisions. Commenters referenced the two 
alternatives provided to states in the CAIR trading programs where: (1) 
EPA adopted a rule and model trading regulations under which states 
that adopted, as state SIP trading programs, the model regulations 
(with only certain limited changes allowed, e.g., in the allocation 
provisions) could participate in the EPA-administered CAIR trading 
programs; and (2) EPA adopted a rule allowing states to adopt in SIPs 
provisions replacing only certain provisions in the CAIR FIPs (e.g., 
the allocation provisions) and to remain in the CAIR trading programs 
under the CAIR FIPs. Under both approaches, the covered units in the 
state participated in the CAIR trading programs, albeit with state-, 
rather than EPA-, determined allocations. Comments on the Transport 
Rule proposal supported these two types of approaches for allowing 
states to replace EPA allocations under the proposed Transport Rule 
trading programs by state allocations. EPA requested additional comment 
on this topic in the NODA published January 7, 2011 (76 FR 1109).
    Two approaches with associated deadlines were explained in the 
NODA. Under the first approach, EPA would adopt new provisions, as part 
of the proposed Transport Rule FIP that would allow a state to submit a 
SIP (referred as an abbreviated SIP) that would modify specified 
provisions of the proposed Transport Rule FIP trading programs. 
Specifically, the abbreviated SIP would substitute state allocation 
provisions for control periods in years after 2012, applicable to one 
or more of the proposed Transport Rule FIP trading programs that apply 
to the state. The NODA explained which specific provisions in the FIP 
could be replaced. If the state allocation provisions met certain 
requirements and the abbreviated SIP did not change any other 
provisions in the respective proposed Transport Rule FIP trading 
program, then EPA would approve the abbreviated SIP. In the substitute 
state allocation provisions, the state could allocate allowances to 
Transport Rule units (whether existing or new units) or other entities 
(such as renewable energy facilities) or could auction some or all of 
the allowances. The NODA went on to describe the requirements for EPA 
approval of an abbreviated SIP (76 FR 1119) including that the total 
amount of allowances allocated and auctioned each year could not exceed 
the applicable budget; allocations and auction results would need to be 
reported to EPA by the permitting authority (usually the state) by 
particular dates prior to the applicable control period depending on 
whether allowances were going to existing or new sources; the reported 
allocations and auction results could not be changed; and no other 
provisions of the FIP would be changed.
    Under the second approach, EPA would adopt a new rule that would 
provide that, if a state submitted a SIP (referred to as a full SIP) 
that adopted trading program regulations meeting certain requirements 
for control periods in years after 2012, then EPA would approve the 
full SIP as correcting the deficiency under CAA section 
110(a)(2)(D)(i)(I) in the state's SIP that was the basis for issuance 
of the comparable proposed Transport Rule FIP. In the state allocation 
provisions, the state could allocate allowances to Transport Rule units 
(whether existing or new units, except for opt-in units) or other 
entities (such as renewable energy facilities) or could auction 
allowances. Upon EPA approval of a state's full SIP, the state's SIP-
based trading program would be integrated with the comparable FIP-based 
Transport Rule trading program (whether or not modified by an 
abbreviated SIP) covering other states. Moreover, covered sources in 
the state could participate in the integrated trading program, and the 
allowances issued under the SIP-based state trading program would be 
interchangeable with the allowances issued in the comparable FIP-based 
Transport Rule trading program.
    The NODA went on to describe the limited changes that states could 
make under the full SIP option. Only allocation provisions could be 
modified with the same requirements as for abbreviated SIPs, including, 
among other things, that the total amount of allowances allocated each 
year could not exceed the applicable budget and that allocations would 
need to be reported to EPA by the permitting authority (usually the 
state) by particular dates prior to the applicable control period 
depending on whether allowances were going to existing or new sources.
    The NODA also discussed the option for states to submit SIPs using 
emission reduction approaches other than the proposed Transport Rule 
trading programs to correct the deficiency under CAA section 
110(a)(2)(D)(i)(I) in the state's SIP. EPA would review on a case-by-
case basis SIPs using such alternative approaches (76 FR 1120).
    Suggested deadlines for abbreviated and full SIPs were given in 
tables in the

[[Page 48327]]

NODA (76 FR 1120). These deadlines generally required states to submit 
SIPs about 2 years ahead of a particular control period for which state 
allocations would apply in order to give EPA time to review and approve 
the SIP and record allowances.
    Most commenters on the NODA supported state allocation options, 
within the preferred FIP remedy, that would replace FIP allocations 
with SIP-based state allocations.
    In the final rule, EPA adopts, with some revisions, both of the 
approaches described in the January 7, 2011 NODA. Under the first 
approach, a state may submit an abbreviated SIP that modifies a final 
Transport Rule FIP trading program in only a limited way (i.e., by 
replacing the allowance allocation provisions in Sec. Sec.  97.411(a) 
and (b)(1) and 97.412(a) for the annual NOX trading program, 
Sec. Sec.  97.511(a) and (b)(1) and 97.512(a) for the ozone-season 
NOX trading program, Sec. Sec.  97.611(a) and (b)(1) and 
97.612(a) for the SO2 Group 1 trading program, and 
Sec. Sec.  97.711(a) and (b)(1) and 97.712(a) for the SO2 
Group 2 trading program). In the state's replacement provisions, the 
state may allocate allowances to Transport Rule units (whether existing 
or new units) \121\ or other entities (such as renewable energy 
facilities) or may auction allowances. Additionally, state SIPs can 
address one or all of the pollutants addressed by the FIPs. For 
PM2.5, EPA is finalizing the flexibility for a state SIP to 
address either SO2 or NOX, or both. Further, if a 
state is required to make ozone-season and annual NOX 
reductions, the SIP could address either ozone-season or annual 
NOX emissions, or both. In other words, states can replace 
provisions in all FIPs that apply or some subset of the FIPs that apply 
to a particular state, and leave in place the FIPs for the requirements 
not addressed by a SIP.
---------------------------------------------------------------------------

    \121\ EPA is not finalizing opt-in provisions, so the reference 
to federal-only opt-in allocations in the NODA has been removed.
---------------------------------------------------------------------------

    Further, EPA will approve the abbreviated SIP only if the state 
replacement for the Transport Rule FIP allocation provisions meets 
certain requirements and the abbreviated SIP does not change any other 
provisions in the Transport Rule FIP trading program. For EPA approval, 
the state allocation and, where applicable, auction provisions (and any 
accompanying definitions of terms applying only to terms as used in 
these provisions) must meet the following requirements. First, the 
provisions must provide that, for each year for which the state 
allocation and, where applicable, auction provisions will apply, the 
total amount of control period (annual or ozone-season) allowances 
allocated and, where applicable, auctioned in accordance with these 
provisions cannot exceed the applicable state budget (less any 
applicable Indian country new unit set-aside, which will continue to be 
administered by EPA) for that year under the relevant Transport Rule 
FIP trading program.
    Second, to the extent the state provisions provide for allocations 
for, or auctions open to, existing units, the provisions must require 
that the state or the permitting authority under title V of the CAA for 
the state submit to the Administrator final allocations and, if any 
auction is to be held, final auction results in accordance with a 
schedule of deadlines discussed below. To the extent the provisions 
provide for allocations for or auctions open to new units or any other 
entities, the provisions must require that the permitting authority 
submit to the Administrator final allocations and, if applicable, 
auction results by July 1 of the year of the control period for which 
the allowances will be distributed. The allocation and auction results 
must be final and cannot be subject to modification (e.g., through an 
allowance surrender adjusting the allocation or auction results).
    As noted above, the state's submission to the Administrator of 
allocations or auction results with regard to existing units must meet 
a specified schedule of deadlines. These submission deadlines reflect, 
and are necessarily coordinated with, the deadlines for recordation by 
the Administrator of allowance allocations and any auction results 
under the Transport Rule trading programs. The recordation deadlines, 
which are discussed in detail in section XI of this preamble, provide 
that the Administrator must record existing-unit allowance allocations 
and auction results by: July 1, 2013 for the applicable control periods 
in 2014 and 2015; July 1, 2014 for the applicable control periods in 
2016 and 2017; July 1, 2015 for the applicable control periods in 2018 
and 2019; and July 1, 2016 and July 1 of each year thereafter for the 
control period in the fourth year after the year of the applicable 
recordation deadline. In order to provide the Administrator 1 month to 
review the submissions of allocations and auction results to ensure 
that the submissions include sufficient information (e.g., the correct 
identification for each unit involved) to record correctly the 
submitted allocations and auction results, the state or permitting 
authority must make these submissions to the Administrator by: June 1, 
2013 for the applicable control periods in 2014 and 2015; June 1, 2014 
for the applicable control periods in 2016 and 2017; June 1, 2015 for 
the applicable control periods in 2018 and 2019; and June 1, 2016 and 
June 1 of each year thereafter for the applicable control period in the 
fourth year after the year of the applicable submission deadline.
    Under the second approach, a state may submit a full SIP adopting a 
Transport Rule trading program that differs from the comparable 
Transport Rule FIP trading program only with regard to limited 
provisions of the FIP trading program. First, the full SIP may include 
new allocation or auction provisions instead of the Transport Rule FIP 
allowance allocation provisions other than those concerning the Indian 
country new unit set-aside. In the state allocation or auction 
provisions, the state may allocate allowances to Transport Rule units 
(whether existing or new units) or other entities (such as renewable 
energy facilities) or may auction allowances. EPA will approve the full 
SIP only if the state allocation or auction provisions (and any 
accompanying definitions of terms applying only to terms as used in 
these provisions) meet certain requirements. Second, the full SIP may 
substitute the name of the state for the term ``State'' as used in the 
FIP trading program provisions, provided that EPA determines that the 
substitutions are not substantive changes. Third, as discussed in more 
detail below, all references to units in Indian country, as used in the 
FIP trading program provisions, must be removed, and the full SIP 
cannot impose any requirements on units in Indian country within the 
borders of the state and may not include the Indian country set-aside 
provisions. Other than these allowed changes, all other provisions in 
the Transport Rule trading program in the full SIP must be the same as 
those in the Transport Rule FIP trading program with regard to non-
Indian country units. For EPA approval, the state allocation provisions 
must meet the same requirements, as discussed above, that state 
allocation or auction provisions in an abbreviated SIP must meet.
    A Transport Rule trading program adopted by a state in a full SIP, 
and approved by EPA, under the second approach will be fully integrated 
with the comparable Transport Rule FIP trading program (i.e., the ``TR 
NOX Annual Trading Program'', ``TR NOX Ozone 
Season Trading Program'', ``TR SO2 Group 1 Trading 
Program'', or ``TR SO2 Group 2 Trading Program''

[[Page 48328]]

respectively) for other states. This will apply whether the comparable 
Transport Rule FIP program for other states was modified by an 
abbreviated SIP approved by EPA under the first approach or was not 
modified by such an abbreviated SIP. The integration of these three 
types of trading programs will be accomplished primarily through the 
definitions of the terms, ``TR NOX Annual allowance'', ``TR 
NOX Ozone Season allowance'', ``TR SO2 Group 1 
allowance'', and ``TR SO2 Group 2 allowance'' in the full 
SIPs approved by EPA and the TR FIP trading programs (whether or not 
the programs were modified by abbreviated SIPs). ``TR NOX 
Annual allowance'' will be defined in the state and Transport Rule FIP 
trading programs as including allowances issued under any of the 
following trading programs: The comparable EPA-approved state Transport 
Rule trading programs; the comparable Transport Rule FIP trading 
programs with EPA-approved state allocation and auction provisions; and 
the Transport Rule FIP trading programs with EPA allocation provisions. 
Similarly, the definitions in the state and Transport Rule FIP trading 
programs of ``TR NOX Ozone Season allowance'', ``TR 
SO2 Group 1 allowance'', and ``TR SO2 Group 2 
allowance'' respectively will include allowances issued under all three 
types of trading programs. As a result, allowances issued in one 
approved state Transport Rule trading program will be interchangeable 
with allowances issued in the comparable Transport Rule FIP trading 
program (whether or not modified by an abbreviated SIP), and all these 
allowances will be available for use for compliance with the allowance-
holding requirements (to cover emissions and to meet assurance 
provision requirements) in all three types of trading programs.
    The integration of state and the proposed Transport Rule FIP 
trading programs will also be reflected in the definitions of ``TR 
NOX Annual Trading Program,'' ``TR NOX Ozone 
Season Trading Program'', ``TR SO2 Group 1 Trading 
Program'', and ``TR SO2 Group 2 Trading Program''. Each of 
these definitions in the state Transport Rule and Transport Rule FIP 
trading programs will expressly encompass the comparable Transport Rule 
FIP trading programs (whether or not modified by an abbreviated SIP) 
and the comparable EPA-approved state full SIP trading program.
    The final rule also sets deadlines for the submission of complete 
abbreviated and full SIPs. These deadlines are based on the first year 
for which the state wants to allocate or auction allowances, reflect 
the above-discussed deadlines for the Administrator's recordation of 
allocations and auction results, and build in a 6-month period for EPA 
review, provision of notice and opportunity for public comment, and 
approval of the SIP revisions. This 6-month period is built into the 
final rule's SIP submission deadlines because that is the period EPA 
found was needed for reviewing, providing notice and comment for, and 
approving state trading program provisions in abbreviated and full SIPs 
under CAIR. As a result, the final rule requires that complete 
abbreviated and full SIPs must be submitted to the Administrator by: 
December 1, 2012 in order to govern allowance allocation and auction 
for control periods in 2014 and 2015; December 1, 2013 in order to 
govern control periods in 2016 and 2017; December 1, 2014 in order to 
govern allowance allocation and auction for control periods in 2018 and 
2019; and December 1, 2015 and by December 1 of any year thereafter in 
order to govern allowance allocation and auction for control periods in 
the fifth year after such submission deadline.
    EPA notes that, in cases where a state that has Indian country 
within its borders submits, and EPA approves, a full SIP, the 
comparable FIP will not be entirely replaced. In such cases, the FIP 
will continue to be in place with regard to the Transport Rule trading 
program provisions that concern units in Indian country, and the full 
SIP will encompass all other provisions of the trading program. 
Specifically, to the extent Transport Rule trading program provisions 
reference and apply to Indian country units (including, for example, 
references in the applicability provisions and the Indian country new 
unit set-aside provisions), those provisions, as they apply to Indian 
country units, will remain in the FIP. The full SIP will include those 
provisions only as they apply to non-Indian country units.
    As a practical matter, this means that the Indian country new unit 
set-aside provisions, which apply exclusively to Indian country new 
units, will remain entirely in the FIP. Further, other trading program 
provisions that reference both non-Indian country units and Indian 
country units (such as the applicability provisions) will remain in the 
FIP to the extent of their application to Indian country units and will 
be included in the full SIP to the extent of their application to non-
Indian country units.
    However, EPA notes that the assurance provisions in each Transport 
Rule trading program require calculations using the entire state 
budget, including any portion of the budget that may be allocated to 
Indian country new units. Further, EPA notes that currently no new 
units are planned or anticipated to be located in Indian country. Under 
these circumstances, EPA will handle the assurance provisions as 
follows. The full SIP for a state having Indian country will initially 
include the assurance provisions, as set forth in the FIP, except with 
removal of any references to sources and units in Indian country. The 
FIP will initially not include the assurance provisions, which will be 
fully effective and enforceable under the full SIP. In the event that 
any new unit is located in Indian country in the state, EPA intends to 
modify its approval of the full SIP to take back the assurance 
provisions in order to apply, in the FIP, the assurance provisions to 
both Indian country and non-Indian country units.
    This final rule not only allows a state to choose to submit an 
abbreviated or a full SIP; it also allows a state to choose to submit 
either form of SIP to replace any or all of the FIPs in this rule as 
they apply to a particular state. By promulgating these Transport Rule 
FIPs, EPA in no way affects the right of a state to submit, for review 
and approval, a SIP that replaces the federal requirements of the FIP 
with state requirements that do not involve state participation in the 
Transport Rule trading programs. In order to replace the FIP in a 
state, the state's SIP taking an approach other than participation in 
Transport Rule trading programs must provide adequate provisions to 
prohibit NOX and SO2 emissions that are 
determined in the Transport Rule to contribute significantly to 
nonattainment or interfere with maintenance in another state or states. 
EPA will review such a SIP on a case-by-case basis. The Transport Rule 
FIPs remain fully in place in each covered state until a state's SIP is 
submitted and approved by EPA to revise or replace a FIP.
    In response to numerous comments urging EPA to allow states to 
determine allowance allocations as soon as possible, EPA has developed 
a SIP revision procedure that applies to 2013 allowance allocations 
only. In developing this procedure, EPA is balancing the desire to 
allow states the flexibility to tailor allowance allocations to the 
specific needs and situations in a particular state with the need to 
provide certainty to source owners and operators by having allowances 
recorded sufficiently ahead of the control period for which the 
allocations are made in order to facilitate owners'

[[Page 48329]]

and operators' efforts to optimize their compliance strategies. This 
final rule allows states to make 2013 allowance allocations through the 
use of a SIP revision that is narrower in scope than the other SIP 
revisions states can use to replace the FIPs and/or to make allocation 
decisions for 2014 and beyond. For 2013 allocations, the scope of the 
SIP revision is limited to allocations made to units that commence 
commercial operation before January 1, 2010 and provided in the form of 
a list of those units and their corresponding allocations for 2013. 
Additionally, this particular SIP revision may allocate only the 
portions of the state budgets set forth in Tables X-1 through X-3, 
i.e., each state budget minus the new unit set-aside and the Indian 
country new unit set-aside.
    In developing this procedure, EPA set deadlines for submissions of 
the SIP revisions for 2013 allocations and for recordation of the 
allocations that balanced the need to record allowances sufficiently 
ahead of the control period with the desire to allow state flexibility 
for 2013. EPA set deadlines that will allow sufficient time for EPA to 
review and approve these SIP revisions, taking into account that EPA 
approval must be final and effective before the 2013 allocations can be 
recorded and the allowances are available for trading. In order to 
ensure that EPA review and approval (which must include public notice 
and opportunity for comment) can be completed in time, the final rule 
necessarily limits the allowed scope of the SIP revisions for 2013 
allocations, as set forth in the requirements discussed below, and 
thereby limits the issues that must be considered and addressed in the 
review and approval process. Further, the final rule prescribes the 
form in which the state allocations for 2013 must be provided to EPA in 
order to facilitate rapid recordation of the allocations upon their 
approval.
    States, along with their sources, will need to weigh the trade-offs 
of a relatively short period of recording before the control period for 
which the allocation is made (about 6 months) with the desire to have 
state allocations in 2013, when deciding whether to pursue a SIP 
revision for 2013 allocations. States may choose to submit a SIP 
revision for one or more of the trading programs. In other words, state 
allocations for 2013 could apply in one trading program while 2013 FIP 
allocations apply in another.
    States can make 2013 allowance allocations provided the state meets 
certain requirements.
     By the date 70 days after publication of the final rule in 
the Federal Register, a state must provide notification to EPA if the 
state intends to submit state allocations for 2013. The notification 
must be in a format prescribed by the Administrator and submitted 
electronically.
     By April 1, 2012, the state must submit a SIP revision to 
EPA that:
    [cir] Allocates to existing units \122\ only, provides a list of 
the units and their state allocations to EPA electronically and in a 
format prescribed by EPA, and does not provide for any change in the 
units and allocations on the list and in any allocation previously 
determined and recorded by the Administrator;
---------------------------------------------------------------------------

    \122\ Existing unit means a unit that commenced commercial 
operation before January 1, 2010.
---------------------------------------------------------------------------

    [cir] Allocates a total amount of allowances for 2013 that does not 
exceed the applicable amount in Tables X-1 through X-3 for each trading 
program that applies in that particular state; and
    [cir] Provides for no set-asides and does not alter the new unit 
set-asides, the Indian country new unit set-asides, and any aspect of 
the FIP rules other than the existing-unit allocations for 2013.
    If EPA does not receive notification from a state by the date 70 
days after publication of the final rule in the Federal Register, EPA 
will record FIP allocations for 2012 and 2013 as scheduled (by the date 
90 days after publication of the final rule). If EPA receives timely 
notification from a state, EPA will record FIP allocations for 2012 
only and wait to record 2013 allocations. If the state provides a 
timely (not later than April 1, 2012) SIP revision meeting all the 
above-described requirements and EPA approves the SIP revision by 
October 1, 2012, EPA will record state-determined allocations for 2013 
by October 1, 2012. Otherwise, EPA will record the EPA-determined 
allocations for 2013.
BILLING CODE 6560-50-P

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[GRAPHIC] [TIFF OMITTED] TR08AU11.010

BILLING CODE 6560-50-C
    EPA will work with states that wish to submit full SIPs or 
abbreviated SIPs to ensure a smooth integration with the relevant 
Transport Rule trading programs. The Agency intends to provide 
information and tools to assist states in their rulemaking efforts, 
including electronic versions of the Transport Rule trading rules and 
EPA will work with states that wish to submit full SIPs or abbreviated 
SIPs to ensure a smooth integration with the relevant Transport Rule 
trading programs. The Agency intends to provide information and tools 
to assist states in their rulemaking efforts, including electronic 
versions of the Transport Rule trading rules and other products states 
feel may be helpful. States that submit approvable full SIPs or 
abbreviated SIPs to implement one or all of the Transport Rule trading 
programs are not required to include an additional technical 
demonstration relating to elimination of emissions that contribute 
significantly to nonattainment or contribute to maintenance in downwind 
areas.

XI. Structure and Key Elements of Transport Rule Air Quality-Assured 
Trading Program Rules

    In order to make the final FIP trading program rules as simple and 
consistent as possible, EPA designed them so that the final rules (like 
the proposed rules) for each of the trading programs (i.e., the ``TR 
NOX Annual Trading Program'', ``TR NOX Ozone 
Season Trading Program'', ``TR SO2 Group 1 Trading 
Program'', and ``TR SO2 Group 2 Trading Program'') are 
parallel in structure and contain the same basic elements. For example, 
the rules for the Transport Rule annual NOX, ozone-season 
NOX, SO2 Group 1, and SO2 Group 2 
trading programs are located, respectively, in subparts AAAAA 
(Sec. Sec.  97.401, et seq.), BBBBB (Sec. Sec.  97.501, et seq.), CCCCC 
(Sec. Sec.  97.601, et seq.), and DDDDD (Sec. Sec.  97.701, et seq.) of 
Part 97 in Title 40 of the Code of Federal Regulations. Moreover, the 
order of the specific provisions for each trading program is the same, 
and the provisions have parallel numbering. The key elements of the 
final Transport Rule trading program rules are as follows.

[[Page 48333]]

(1) General Provisions
(i) Sec. Sec.  97.402 and 97.403, 97.502 and 97.503, 97.602 and 97.603, 
and 97.702 and 97.703--Definitions and Abbreviations
    Most of the definitions in the final Transport Rule trading program 
rules are essentially the same as in the proposed rules and for each of 
the Transport Rule trading programs (except where necessary to reflect 
the different pollutants (NOX and SO2), control 
periods (for annual and ozone-season NOX, and for annual 
SO2), and geographic coverage involved in the trading 
programs). Moreover, many of the definitions in the final rules that 
are essentially the same as in the proposed rule are also essentially 
the same as in prior EPA-administered trading programs. However, as 
discussed in more detail below, some of the definitions in the final 
rules clarify, or differ from, the definitions in the proposed rule.
    As noted, several definitions in the final rules are essentially 
the same as those both in the proposed rules and in prior EPA-
administered trading programs. Examples include the definitions of 
``source,'' ``allowance transfer deadline,'' ``owner,'' ``operator'', 
``Allowance Management System'' (used instead of the term ``Allowance 
Tracking System''), and ``continuous emission monitoring system.''
    One example of a definition in the final rules that is the same as 
in the proposed rule, but that clarifies the definition used in prior 
trading programs is the definition of ``fossil fuel.'' In the final 
rule, the term ``fossil fuel'' is defined in general as including 
natural gas, petroleum, coal, or any form of fuel derived from such 
material, regardless of the purpose for which such material is derived. 
For example, with regard to consumer products that are made of 
materials derived from natural gas, petroleum, or coal, are used by 
consumers, and then are used as fuel, these materials in the consumer 
products qualify as fossil fuel. The definition in the final rules also 
includes language establishing a narrower meaning of ``fossil fuel'' 
that is not generally applicable, but rather is applicable only for 
purposes of applying the limitation on fossil-fuel use under the solid 
waste incineration unit exemption (which is discussed elsewhere in this 
preamble). This latter portion of the ``fossil fuel'' definition makes 
explicit an interpretation that EPA adopted in CAIR that--solely for 
purposes of applying the fossil-fuel use limitation in that exemption--
the term ``fossil fuel'' is limited to natural gas, petroleum, coal, or 
any form of fuel derived from such material ``for the purpose of 
creating useful heat.'' For example, applying this narrower meaning, 
consumer products made from natural gas, petroleum, or coal are not 
fossil fuel, for purposes of determining qualification under the 
fossil-fuel use limitation, because the products (e.g., tires) were 
derived from natural gas, petroleum, or coal in order to meet certain 
consumer needs (e.g., to meet transportation needs), not in order to 
create fuel (i.e., material that would be combusted to produce useful 
heat).
    As noted above, some of definitions in the final rules clarify 
definitions in the proposed rules. The definitions of ``allowable 
NOX emission rate'' and ``allowable SO2 emission 
rate'' are clarified by explaining that such a rate is the most 
stringent state or federal emission rate limitation, expressed in lb/
MWhr or, if originally expressed in lb/mmBtu, converted to lb/MWhr by 
multiplying it by the unit's heat rate in mmBtu/MWhr. This 
clarification ensures consistency from unit to unit in determining a 
unit's allowable rate.
    By further example, while the proposed rules used the same 
definition of ``commence commercial operation'' as in prior EPA-
administered trading programs, the final rules clarify the definition. 
Under the definition in the proposed rules, a unit that is physically 
changed is treated as the same unit. However, the proposed rules were 
unclear about the treatment of a unit that is replaced and whether 
moving a unit to a different location or source constitutes a physical 
change. The definition of ``commence commercial operation'' in the 
final rules clarifies that a unit that is physically changed (which 
includes a unit that is replaced) continues to be treated, for purposes 
of this final rule, as the same unit with the same commence-commercial-
operation date. The definition also clarifies that moving a unit to a 
different location or source is treated the same as a physical change, 
and so the unit continues to be treated as the same unit. The 
definition also clarifies that a unit (the replaced unit) that is 
replaced, whether at the same source or a different source, is treated 
as the same unit, while the unit (the replacement unit) that replaces 
the unit is treated as a separate unit with a new commence-commercial-
operation date. (The definition of ``commence operation'' is removed in 
the final rules because they do not use this term.)
    By further example, while the proposed rules used the same 
definition of ``unit'' as in prior EPA-administered trading programs, 
the final rules clarify the definition. The ``unit'' definition is 
clarified by expanding it to incorporate explicitly the concepts--set 
forth in the definition in the final rules of ``commence commercial 
operation'' and thus already applicable to all units--that a unit that 
is physically changed, moved to a different location or source, or 
replaced at the same or a different source continues to be treated as 
the same unit and that a replacement unit at the same source is treated 
as a separate unit. EPA believes that it is preferable to provide a 
comprehensive definition of ``unit'' in one place because the term is 
used so frequently in the final rules.
    By further example, the definition of ``nameplate capacity'' is 
clarified in the final rules by explaining that it is expressed in MWe 
rounded to the nearest tenth. This is the same rounding convention that 
is used in the reporting of nameplate capacity to the Energy 
Information Administration.
    As noted above, some of the definitions in the final rules are 
similar to those in the proposed rules but have some substantive 
differences. For example, in the proposed rules, the definitions of 
``cogeneration unit'' and ``fossil-fuel-fired'' are similar to those in 
prior trading programs but with changes to minimize the need for data 
concerning individual units or combustion devices for periods before 
1990. In order to qualify as fossil-fuel-fired, a unit would have to 
combust any amount of fossil fuel in 1990 or thereafter. In order to 
qualify as a cogeneration unit, a unit would have to meet certain 
efficiency and operating standards during the later of: the 12-month 
period starting when the unit begins producing electricity, or 1990. 
For a topping-cycle unit, useful power plus one-half of useful thermal 
energy output of the unit must equal no less than a certain percentage 
of the total energy input and useful thermal energy must be no less 
than a certain percentage of total energy output, and, for a bottoming-
cycle unit, useful power must be no less than a certain percentage of 
total energy input. EPA proposed to limit to 1990 or later the 
historical period for which information on fuel consumption and on 
cogeneration unit efficiency and operations would be required to apply 
the ``fossil-fuel-fired'' and ``cogeneration unit'' definitions. This 
limitation was proposed because EPA was concerned that some owners and 
operators could have difficulty obtaining pre-1990 information about 
older units, particularly for units whose ownership has changed over 
time.
    While EPA proposed to use 1990 as the earliest year for which 
information

[[Page 48334]]

would be required under these definitions, EPA requested comment on 
whether a more recent year should be used. As discussed elsewhere in 
this preamble, the final rules use 2005 (about 5 years before this 
rule's promulgation), rather than 1990, as the reference year. Further, 
because the language describing the historical time period used 
(including the reference year), appeared in the proposal both in the 
``cogeneration unit'' definition and the provisions concerning 
cogeneration units in the applicability provisions, the final rules 
removed any language about the historical time period from the 
``cogeneration unit'' definition and revised the language in the 
applicability provisions to use the 2005 reference year for the 
requirements for meeting the exemption for cogeneration units from the 
Transport Rule trading programs. Further, consistent with this use of 
2005 as the reference year, the ``fossil-fuel-fired'' definition in the 
final rule specifically references 2005, rather than 1990, and as 
discussed elsewhere in this preamble, the final rules also use January 
1, 2005 (rather than November 15, 1990) as the reference date 
throughout the applicability provisions.
    With this change in the reference date for the requirement to meet 
the operating and efficiency standards under the ``cogeneration unit'' 
definition, a unit would have to meet these standards throughout the 
later of 2005 or the 12-month period starting when the unit begins 
producing electricity and continuing thereafter. EPA requested comment 
on whether these standards should be applied to a calendar year when 
the unit involved did not combust any fuel, i.e., did not operate at 
all. As discussed elsewhere in this preamble, the final rules expressly 
provide that the operating and efficiency standards do not have to be 
met for a calendar year throughout which a unit did not operate at all.
    In addition, under the proposed rules, if a group of cogeneration 
units operating as an integrated cogeneration system met the efficiency 
standards, a topping-cycle unit in that system would be deemed to meet 
those standards. EPA requested comment on whether this provision should 
also apply to a bottoming-cycle unit. As discussed elsewhere in this 
preamble, this provision in the final rules is not limited to topping-
cycle units.
    By further example of definitions in the final rules that have 
substantive differences from the definitions in the proposed rules, the 
proposed definitions of ``TR NOX Annual allowance,'' ``TR 
NOX Ozone Season allowance,'' ``TR SO2 Group 1 
allowance,'' ``TR SO2 Group 1 allowance,'' ``TR 
NOX Annual Trading Program,'' ``TR NOX Ozone 
Season Trading Program,'' ``TR SO2 Group 1 Trading 
Program,'' and ``TR SO2 Group 1 Trading Program'' are 
changed in the final rules. Language is added to the definitions in 
order to reference comparable allowances and trading programs 
established through SIP revisions submitted by states and approved by 
the Administrator. As discussed elsewhere in this preamble, the final 
Transport Rule provides that, if a state submits SIP revisions meeting 
certain specified requirements, the state or permitting authority 
(rather than the Administrator) will allocate allowances, and the 
covered sources in the state will participate--along with covered 
sources in states remaining subject to the Transport Rule FIPs--in an 
integrated, region-wide air quality-assured trading program under which 
both any allowance allocated by the Administrator and any allowance 
allocated by the state or permitting authority will each authorize one 
ton of emissions of the relevant pollutant and will be usable by any 
source for compliance with the requirement to hold allowances covering 
emissions.
    As noted above, the final rules include some definitions that were 
not used in prior EPA-administered trading programs and that reflect 
unique provisions of the Transport Rule trading programs. For example, 
the terms, ``assurance account,'' ``TR NOX Annual unit,'' 
``TR NOX Ozone Season unit,'' ``TR SO2 Group 1 
unit,'' ``TR SO2 Group 2 unit,'' ``common designated 
representative,'' ``common designated representative's assurance 
level,'' and ``common designated representative's share'' are used and 
defined in the final rule.
    While the proposed rules included definitions for the terms, 
``owner's assurance level'' and ``owner's share,'' the final rules 
replace these terms and instead define the terms, ``common designated 
representative,'' ``common designated representative's assurance 
level,'' and ``common designated representative's share.'' This is 
because, as discussed elsewhere in this preamble, the final rules 
include assurance provisions similar to those in the proposed rules but 
that are implemented based on groups of units having a common 
designated representative, instead of being implemented on an owner-by-
owner basis. The definition of ``common designated representative'' in 
the final rules reflects that the determination of what groups of units 
and sources in a State have a common designated representative is made 
based on the identity of units' and sources' designated representatives 
as of April 1 of the year after the year of the control period when a 
state triggers the assurance provisions. EPA believes that the use of 
this reference date will give owners and operators greater flexibility 
to select common designated representatives after information about 
total state control period emissions is available and after the 
allowance transfer deadline when owners and operators may prefer to 
have a designated representative for their specific source (rather than 
a common designated representative for a larger group) who is focused 
on ensuring that sufficient allowances are held in or transferred to 
the source's account to cover the sources' emissions. EPA notes that 
the definition of ``common designated representative's share'' is 
simpler than the definition of ``owner's share'' because implementing 
the assurance provisions at the designated representative level means 
it is no longer necessary to address, in the definition, owner- and 
unit-level issues that may arise when a unit has multiple owners or 
where two or more units emit through the same stack.
    Finally, some definitions are added to the final rules that are not 
in the proposed rules. For example, because the term, ``business day,'' 
was used, but not defined, in the proposed rule, its meaning was 
unclear. Specifically, it was unclear whether a day that was uniquely a 
state holiday, and not a federal holiday, was a business day for 
purposes of the federally administered Transport Rule trading programs, 
e.g., whether the allowance transfer deadline applicable to all sources 
in all states in a Transport Rule trading program could fall on a day 
that was a unique state holiday in one or a few states or whether the 
allowance transfer deadline would be advanced to the next business day 
for all sources in all states or perhaps only for sources in the state 
with the state holiday. EPA believes that, for a federally administered 
trading program covering sources in multiple states, the deadlines 
should be clear and uniform for all sources, regardless of the state in 
which the sources are located, and should not be affected by unique 
state holidays of which owners and operators of sources in other states 
may not even be aware. Consequently, the ``business day'' definition is 
added in the final rules and means a day that does not fall on a 
weekend or a federal holiday.
    By further example, a definition for ``natural gas'' was added in 
the final rules. That definition, as well as the definition for 
``coal,'' incorporate the

[[Page 48335]]

corresponding definitions in Part 72 of the Acid Rain Program 
regulations. The Part 72 definitions are incorporated because they are 
also used in the Part 75 monitoring, reporting, and recordkeeping 
provisions, which provisions are already incorporated in the final 
Transport Rule Trading Program rules. (ii) Sec. Sec.  97.404 and 
97.405, 97.504 and 97.505, 97.604 and 97.605, and 97.704 and 97.705--
Applicability and Retired Units
    The applicability provisions in the final rules are, except as 
discussed herein, essentially the same as in the proposed rules and for 
each of the Transport Rule trading programs. Of course, for each 
trading program, the definition of ``State'' reflects differences in 
the specific states whose electric generating units are covered by the 
respective trading program.
    Under the general applicability provisions of the proposed rules, 
the Transport Rule trading programs would cover fossil-fuel-fired 
boilers and combustion turbines serving--at any time starting November 
15, 1990 or later--an electrical generator with a nameplate capacity 
exceeding 25 MWe and producing power for sale, with the exception of 
certain cogeneration units and solid waste incineration units. As 
discussed elsewhere in this preamble, the general applicability 
provisions in the final rules reference January 1, 2005 (about 5 years 
before this rule's promulgation), rather than November 15, 1990.
    Cogeneration unit exemption. Under the final rules (as well as the 
proposed rules) certain cogeneration units or solid waste incinerators 
otherwise covered by the general category of covered units are exempt 
from the FIP requirements. In particular, the final rules include an 
exemption for a unit that qualifies as a cogeneration unit throughout 
the later of 2005 or the first 12 months during which the unit first 
produces electricity and continues to qualify throughout each calendar 
year ending after the later of 2005 or such 12-month period and that 
meets the limitation on electricity sales to the grid. In order to 
qualify as a cogeneration unit (i.e., meet the definition of 
``cogeneration unit'') in the final rules, a unit (i.e., a boiler or 
combustion turbine) must operate as part of a ``cogeneration system,'' 
which is defined as an integrated group of equipment at a source 
(including a boiler or combustion turbine, and a steam turbine 
generator) designed to produce useful thermal energy for industrial, 
commercial, heating, or cooling purposes and electricity through the 
sequential use of energy. In addition, in order to qualify, a unit must 
be a topping-cycle unit or a bottoming cycle unit because units that 
produce useful thermal energy and useful power through sequential use 
of energy either produce useful power first (i.e., are topping-cycle 
units) or produce thermal energy first (i.e., are bottom-cycle units).
    Further, in order to qualify as a cogeneration unit, a unit also 
must meet, on a 12-month or annual basis, the above described 
efficiency and operating standards. As discussed elsewhere in this 
preamble, EPA clarifies that the electricity sales limitation under the 
exemption is applied in the same way whether a unit serves only one 
generator or serves more than one generator. In both cases, the total 
amount of electricity produced annually by a unit and sold to the grid 
cannot exceed the greater of one-third of the unit's potential electric 
output capacity or 219,000 MWhr.
    The final rules also clarify when a unit that meets the 
requirements for the cogeneration unit exemption and subsequently fails 
to meet all these requirements loses the exemption and becomes a 
covered unit. Such a unit loses the exemption starting the earlier of 
January 1 (or May 1 for the NOX ozone season trading 
program) after the first year during which the unit no longer meets the 
``cogeneration unit'' definition or January 1 (or May 1) of the first 
year during which the unit no longer meets the electricity sales 
limitation.
    Solid waste incineration unit exemption. The final rules also 
include an exemption for a unit that qualifies as a solid waste 
incineration unit during the later of 2005 or the first 12 months 
during which the unit first produces electricity, that continues to 
qualify throughout each calendar year ending after the later of 2005 or 
such 12-month period, and that meets the limitation on fossil-fuel use. 
In contrast, the exemption for solid waste incineration units in the 
proposed rules distinguished between units commencing operation before 
January 1, 1985 and those commencing operation on or after that date 
and established somewhat different criteria for these two categories of 
units. As discussed elsewhere in this preamble, the final rules remove 
the distinction based on whether a solid waste incineration unit 
commences operation before January 1, 1985 or on or after January 1, 
1985. In order to be exempt, the unit must qualify as a solid waste 
incineration units during the later of 2005 or the first 12 months 
during which the unit first produces electricity, must continue to 
qualify throughout each calendar year ending after the later of 2005 or 
such 12-month period, and must meet the limitation on fossil-fuel use 
on a three-year average basis during the first 3 years of operation 
starting no earlier than 2005 and every 3 years of operation 
thereafter.
    Retired unit exemption. The final rule provisions exempting 
permanently retired units from most of the requirements of the 
Transport Rule trading programs are essentially the same as in the 
proposed rules and for each of the Transport Rule trading programs. The 
retired unit provisions exempt these units from the requirements for 
emission monitoring, recordkeeping, and reporting and for holding 
allowances, as of the allowance transfer deadline, sufficient to cover 
their emissions. However, the permanently retired units in a state must 
be included in determining whether owners and operators must surrender 
allowances, and, if so, how many, to comply with the assurance 
provisions (which are discussed elsewhere in this preamble) if the 
state's total covered-unit emissions exceed the state assurance level.
    Specifically, a common designated representative must include these 
units in determining whether his or her share of total emissions of 
covered units in a state exceed his or her share (generally based on 
the allowances allocated to the units that he or she represents) of the 
state trading budget with the variability limit and thus whether the 
owners and operators of the units that he or she represents have to 
surrender allowances under the assurance provisions.
(iii) Sec. Sec.  97.406, 97.506, 97.606, and 97.706--Standard 
Requirements
    The basic requirements applicable to owners and operators of units 
and sources covered by the Transport Rule trading programs and 
presented as standard requirements in the final rules are, except as 
discussed herein, essentially the same as in proposed rules and for 
each of the Transport Rule trading programs. These basic requirements 
include: designated representative requirements; emissions monitoring, 
reporting, and recordkeeping requirements; emissions requirements 
comprising emissions limitations and assurance provisions; permit 
requirements; additional recordkeeping and reporting requirements; 
liability provisions; and provisions describing the effect of the 
Transport Rule trading program requirements on other CAA provisions.
    In particular, the paragraphs addressing emissions requirements for 
owners and operators describe these requirements in detail and 
reference

[[Page 48336]]

other sections of the final rules that set forth the procedures for 
determining compliance with the emissions limitations and assurance 
provisions. The paragraphs in the final rules concerning compliance 
with the emissions limitations clarify that owners and operators of a 
source and each covered unit at the source must hold allowances at 
least equaling the total control period emissions of all covered units 
at the source. Further, the paragraphs in the final rules concerning 
compliance with the assurance provisions differ from those in the 
proposed rules in that, as discussed elsewhere in this preamble, the 
final rules implement the assurance provisions based on groups of units 
with a common designated representative, instead of being implemented 
on an owner-by-owner basis, as proposed. Under the final rules, the 
assurance provisions are triggered when total control period emissions 
by covered units in a state (starting in 2012) exceed the state trading 
budget plus variability limit. If the assurance provisions are 
triggered for a state for a control period in a given year, owners' and 
operators' responsibility for the resulting penalty (i.e., the 
surrender of allowances for deduction through the transfer of such 
allowances to the assurance account created by the Administrator for 
such owners and operators) is determined on a common designated 
representative basis.
    For purposes of implementing the assurance provisions, covered 
units in a state are in effect grouped by common designated 
representative (which is defined as an individual (i.e., a natural 
person) who is the designated representative, as distinguished from the 
alternate designated representative, for a group of one or more units 
and sources as of April 1 after the control period for which the state 
exceeds the state assurance level). The control period emissions of all 
covered units with a common designated representative are compared with 
the allowance allocations of such units plus their share of the state 
variability limit. The owners and operators of the units and sources in 
each group that has emissions in excess of allocations plus share of 
variability are subject to the assurance provisions penalty. The owners 
and operators of the units and sources in each group must transfer to 
the assurance account created for such owners and operators a total 
amount of allowances equal to two times such owners' and operators' 
proportionate share of the state's excess of covered-unit emissions 
over the state trading budget plus variability.
    The group's proportionate share is the percentage resulting from 
division of the amount of the group's excess of emissions over 
allocations plus share of variability by the sum of these excess 
amounts for all groups of units with a common designated representative 
in the state. The final rule makes it clear that this percentage is not 
rounded to the nearest whole number, but rather that the calculated 
amount of allowances resulting from application of this percentage is 
rounded to the nearest whole number because, in the Transport Rule 
trading programs, only whole (not fractional) allowances are used. If 
instead this percentage were rounded before its application, each 
group's share would be either 100 percent or 0 percent, which would be 
contrary to the intent of the assurance provisions in both the final 
rules and the proposed rules.
    The provisions addressing the assurance requirements in the final 
rules reflect this common-designated-representative-based approach. For 
example, as discussed elsewhere in this preamble, these provisions use 
the terms, ``common designated representative's share'' and ``common 
designated representative's assurance level,'' in lieu of the terms, 
``owner's share'' and ``owner's assurance level,'' used in the proposed 
rules. By further example, these final rule provisions refer to both 
``common designated representatives'' and ``owners and operators,'' 
rather than simply ``owners.''
    The final rules also explain what vintage year (i.e., allocation 
year) of allowances can be used in order to comply with the requirement 
to cover emissions and with the requirements of the assurance 
provisions. With regard to emissions during a control period in a given 
year, only allowances allocated for that year or any prior year can be 
used to cover such emissions. Further, only allowances of the following 
vintage can be used to meet excess emissions penalties and assurance 
penalties concerning emissions during a control period in a given year: 
allowances allocated for that year, any year before that year, or the 
year immediately after that year. This approach makes the vintage years 
usable for excess emissions and assurance penalties consistent and 
helps ensure that allowances will be available to meet these 
obligations.
    The final rules also clarify the standard emission requirements by 
explaining further what is meant by the provision that an allowance is 
a limited authorization to emit. The final rules clarify that an 
allowance provides authorization to emit during the control period in 
one year and is limited in both its use and its duration. For example, 
each Transport Rule trading program's final rules state that an 
allowance provides an emission authorization that can only be used in 
accordance with the requirements of the respective trading program, 
such as the requirements specifying what allowances are available for 
use, and how such allowances must be held or transferred, in order to 
cover emissions or meet the assurance provisions. By further example, 
under the final rules, an allowance continues to provide an 
authorization to emit one ton of the relevant pollutant until the 
allowance is deducted, e.g., in order to be used for compliance with 
the requirement to cover emissions or the requirements of the assurance 
provisions. Moreover, under the final rules, the Administrator has the 
express authority to terminate or limit the authorization to emit, and 
thereby change the use and duration of the authorization, described in 
the final rules, to the extent he or she determines to be necessary or 
appropriate to implement any provision of the CAA.
    The remaining paragraphs in the standard requirements section 
address permitting, recordkeeping and reporting, liability provisions, 
and the effect on other CAA provisions. For example, the paragraphs 
concerning permitting requirements are limited to stating that no title 
V permit revisions are necessary to account for allowance allocation, 
holding, deduction, or transfer and that the minor permit modification 
procedures can be used to add or change general descriptions in the 
title V permits of the monitoring and reporting approach used by the 
units covered by each title V permit. These provisions remain 
essentially the same in the final rules as in the proposed rules.
(iv) Sec. Sec.  96.407, 97.507, 97.607, and 97.707--Computation of Time
    These sections address how to determine the deadlines referenced in 
the Transport Rule trading program rules and are, except as discussed 
herein, essentially the same as in the proposed rules and for each of 
the Transport Rule trading programs. The final rules revise the 
proposed rule provisions concerning the treatment of the final date in 
any time period in order to make the provision consistent with the 
approach discussed above with regard to the new definition of 
``business day.'' The revised provision states that, if the final date 
is not a

[[Page 48337]]

``business day'', then the time period is extended to the next 
``business day.''
(v) Sec. Sec.  97.408, 97.508, 97.608, 97.708 and Part 78--
Administrative Appeal Procedures
    Under the final Transport Rule, final decisions of the 
Administrator under the Transport Rule trading programs are appealable 
to EPA's Environmental Appeals Board under the regulations set forth in 
Part 78 (40 CFR part 78), which are revised by the final Transport Rule 
to accommodate such appeals. The provisions in the final Transport Rule 
concerning appeals are, except as discussed herein, essentially the 
same as in the proposed Transport Rule. The proposed Transport Rule 
would add a provision in Part 78 explaining who is an ``interested 
person'' with regard to a decision, i.e., a person who submitted 
comments, testimony, or objections as part of the process of making the 
decision or a person who submitted his or her name to the Administrator 
to be placed to an interested persons list. The final Transport Rule 
includes that provision, but with additional language that clarifies 
the process for submitting a name to be placed on such a list.
(2) Allowance Allocations
    Sections 97.410 through 97.412, 97.510 through 97.512, 97.610 
through 97.612, and 97.710 through 97.712 set forth: certain 
information related to allowance allocation and for implementation of 
the assurance provisions; the timing for allocation of allowances to 
existing and new units; and the procedures for new unit allocations. In 
particular, these sections include tables providing, for each state 
covered by the particular Transport Rule trading program and for each 
year, the state trading budget (without the variability limit), new 
unit set-aside, Indian country new unit set-aside (where applicable), 
and variability limit. These provisions in the final rules differ in 
several ways, from the proposed rules and are essentially the same for 
each of the Transport Rule trading programs.
    With regard to the tables in the final rules for the state trading 
budgets (without the variability limits), new unit set-asides, and 
variability limits, the identity of the specific states involved and 
the values for each state differ from the tables in the proposed rules. 
The final rule values reflect the determinations and modeling 
underlying the final rules and discussed elsewhere in this preamble. 
Further, as discussed elsewhere in this preamble, the variability 
limits are only those based on one-year variability and not those 
proposed to be based on three-year variability, and Indian country set-
asides are shown for states with Indian country within their borders.
    With regard to existing unit allocations, the final rules provide 
that these allocations will be set forth in a notice of data 
availability to be issued by the Administrator. In contrast, the 
proposed rules stated that existing unit allocations would be set forth 
in an appendix to the rules for each Transport Rule trading program. 
EPA believes that including these allocations in a notice of data 
availability referencing the EPA Web site (rather than publishing them 
in tables requiring a large number of pages in the Federal Register for 
each Transport Rule trading program) is a more efficient method of 
making these allocations public, particularly since these allocations 
may be changed for 2013 and thereafter by states through SIP revisions. 
In addition, under the final rules the allocations for an existing unit 
can change if the unit does not operate (i.e., has no heat input) for 2 
consecutive years starting in 2012. In that case, the unit continues to 
receive its existing unit allocation for those years plus only 2 more 
years. As explained elsewhere in this preamble, this is a modification 
of the proposed rules, under which a unit that did not operate for 3 
consecutive years would continue to receive its existing unit 
allocation for those years plus 3 more years.
    Under the final rule provisions for new units, the Administrator 
allocates allowances from the new unit set-aside for the state where 
the respective unit is located and for each year when the unit first 
becomes eligible for an allocation and each year thereafter. The units 
eligible for new unit set-aside allocations include units commencing 
commercial operation on or after January 1, 2010, as well as several 
other categories of units, such as, for example, existing units that 
were not initially but then become covered units, existing units whose 
allocations are lost due to lack of unit operation and that 
subsequently begin operating again, and units that lost their 
allocations because they changed location from one state to another. 
The approach in the final rules differs from the proposed rules, which 
required that owners and operators initially request allowances from 
the new unit set-aside when the unit first became eligible for an 
allocation. As discussed elsewhere in this preamble, under the final 
rules, EPA identifies which units become eligible and when they become 
eligible, based on information provided in other submissions (e.g., 
certificates of representation, monitoring system certifications, and 
quarterly emissions reports) that such units must make to EPA, and the 
requirement that owners and operators submit requests for new unit set-
aside allocations is removed in the final rules.
    The final rules also provide for two rounds of allocations from the 
new unit set-aside, in contrast with the proposed rules that provided 
for only one round. In the first round in the final rules (as in the 
single round in the proposed rules), a unit's new unit set-aside 
allocation initially equals that unit's emissions--as determined in 
accordance with Sec. Sec.  97.430-97.435, 97.530-97.535, 97.630-97.635, 
and 97.730-97.735 of the final rules and Part 75 (40 CFR part 75)--for 
the control period (annual or ozone season, depending on the Transport 
Rule trading program involved) in the preceding year. If the new unit 
set-aside lacks sufficient allowances to provide this initial 
allocation for all of the new units, then each new unit is allocated 
its proportionate share (based on its initial allocation amount) of the 
allowances in the new unit set-aside. The Administrator issues a notice 
of data availability informing the public of the specific new unit 
allocations and provides an opportunity for submission of objections on 
the grounds that the allocations are not consistent with the 
requirements of the relevant final rule provisions. A second notice of 
data availability is subsequently issued in order to make any necessary 
corrections in the specific new unit allocations. As discussed 
elsewhere in this preamble, the final rules establish a somewhat 
different schedule for issuance of these notices of data availability 
than the proposed rules. In particular, a single set of dates (i.e., 
for the first notice, June 1 of the year for which the new unit 
allocations are described in the notice and, for the second notice, 
August 1 of that year) is established for all of the Transport Rule 
trading programs. For the reasons discussed elsewhere in this preamble, 
the final rules provide for a second round of allocations to the extent 
that any allowances remain in the new unit set-aside after the 
allocations are made to new units in the first round. (In the proposed 
rules, remaining allowances were immediately allocated to existing 
units.) The units eligible for allocations in the second round are new 
units that commenced commercial operation during the control period for 
which allocations are being made and during the prior control period. 
The second round allocation for each such unit initially equals the 
positive difference (if any) between the unit's

[[Page 48338]]

first round allocation (if any) and the unit's emissions during the 
control period for which allocations are being made. If the amount of 
allowances remaining in the new unit set-aside after the first round is 
insufficient to provide this initial allocation for all of the second 
round new units, then each such new unit is allocated its proportionate 
share of the allowances remaining in the new unit set-aside. The 
Administrator uses notices of data availability (which are issued by 
December 15 (for the annual trading programs) and September 15 (for the 
ozone season trading program) of the control period involved and 
February 15 (for the annual trading programs) and November 15 (for the 
ozone season trading program) before the allowance transfer deadline 
for the control period involved, in a manner analogous to the use of 
such notices in the first round, to inform the public about the 
identification of the new units in the second round allocations and 
obtain and consider any objections. The February 15 and November 15 
notices also inform the public about the amounts of the second round 
allocations. If, after both rounds of allocations, any allowances 
remain in the new unit set-aside, those allowances are allocated to 
existing units in proportion to such units' allocations.
    The final rules also establish a separate Indian country new unit 
set-aside in each state where Indian country is located (i.e., in 
Florida, Iowa, Kansas, Louisiana, Michigan, Minnesota, Mississippi, 
Nebraska, New York, North Carolina, South Carolina, Texas, and 
Wisconsin). As discussed elsewhere in this preamble, the Administrator 
operates the Indian country new unit set-aside in essentially the same 
manner as state new unit set-aside, except that unallocated allowances 
remaining in the Indian country new unit set-aside after the two rounds 
of new unit set-aside allocations are first placed in the new unit set-
aside in the state where the Indian country involved is located and 
then, if still unallocated, are allocated to existing units in the 
state. As with the state new unit set-aside, EPA will identify the new 
units qualifying for the Indian country new unit set-aside, calculate 
the allocations, and issue notices of data availability using the same 
schedules as notices for the state new unit set-aside.
    Under the final rules (like under the proposed rules), if a unit in 
certain specified categories is allocated allowances that should not 
have received them, the Administrator applies procedures under which 
the allocation is not recorded or the amount of the recorded 
allocations is deducted as an incorrect allocation, with one exception. 
The exception is where the determination of compliance with the 
emissions limitation (i.e., requirement to hold allowances covering 
emissions, as distinguished from the assurance provisions) for the 
source that includes the unit has already been completed, in which case 
no action is taken to account for the erroneous allocation for the 
control period involved.
    While this procedure concerning recordation or deduction of 
allocations is the same as under the proposed rules, the final rules 
change the description of the circumstances under which this procedure 
concerning recordation or deduction of allocations is applied. Under 
both the final rules and the proposed rules, this procedure is applied 
to a unit (whether an existing unit or a new unit) that receives an 
allocation but is not actually a covered unit. However, under the final 
rules, another category of units--i.e., any existing unit that is not 
located--as of January 1 of the control period for which the allocation 
is received--in the state from whose trading budget the allocation was 
made is also subject to this procedure. Although relatively few units 
are moved from one state to another, EPA believes that it is important 
to address what happens to such units' allocations, both because each 
state has a limited trading budget out of which all allocations for a 
year to existing and new units in that state must be made and because, 
under the assurance provisions, determinations are made about owners' 
and operators' surrender of allowances based on, among other things, 
the allocations for units in a specific state. Because, under the final 
rules, a unit that is moved from one state to another may lose its 
existing unit allocation in the first state under the above-described 
procedure, the final rules also makes such a unit eligible for 
allocations from the new-unit set-aside of the second state.
    Finally, the final rules remove, as no longer necessary, one 
category of units that the proposed rules included as subject to this 
procedure. The proposed rules, treated, as existing units, some units 
that had not yet operated but were projected to operate by January 1, 
2012, and so the proposed rules made these units subject to the 
procedure for not recording or for deducting allocations if they 
actually were not required to certify their monitoring systems and hold 
allowances covering emissions starting January 1, 2012. The final rule 
does not treat projected units as existing units and so this category 
of units no longer needs to be made subject to this procedure.
(3) Designated Representatives and Alternate Designated Representatives
    Sections 97.413 through 97.418, 97.513 through 97.518, 97.613 
through 97.618, and 97.713 through 97.718 establish the procedures for 
certifying and authorizing the designated representative, and alternate 
designated representative, of the owners and operators of a source and 
the units at the source, and for changing the designated representative 
and alternate designated representative. These sections also describe 
the designated representative's and alternate designated 
representative's responsibilities and the process through which he or 
she can delegate to an agent the authority to make electronic 
submissions to the Administrator. Except as discussed herein, the 
provisions in the final rules are essentially the same as in the 
proposed rules and for each of the Transport Rule trading programs.
    The designated representative is the individual (i.e., the natural 
person) authorized to represent the owners and operators of each 
covered source and covered unit at the source in matters pertaining to 
all Transport Rule trading programs to which the source and units were 
subject. One alternate designated representative (also an individual) 
can be selected to act on behalf of, and legally bind, the designated 
representative and thus the owners and operators. Because the actions 
of the designated representative and alternate legally bind the owners 
and operators, the designated representative and alternate must submit 
a certificate of representation certifying that each was selected by an 
agreement binding on all such owners and operators and is authorized to 
act on their behalf.
    In the final rules (like in the proposed rules), the certificate of 
representation must contain: Specified identifying information for the 
covered source (including location) and the covered units at the source 
and for the designated representative and alternate; the name of every 
owner and operator of the source and units; and certification language 
and signatures of the designated representative and alternate. The 
final rules require an additional piece of identifying information, 
i.e., whether the unit is located in Indian country. This is necessary 
in order for the Administrator to implement the above-described Indian 
country new unit set-aside. All submissions (e.g., monitoring plans, 
monitoring system certifications, and allowance transfers) under the 
final rules for a covered

[[Page 48339]]

source or covered unit must be submitted, signed, and certified by the 
designated representative or alternate, except that electronic 
submission may be delegated.
    In order to change the designated representative or alternate, a 
new certificate of representation must be received by the 
Administrator. A new certificate of representation must also be 
submitted to reflect changes in the owners and operators of the source 
and units involved. The new certificate must be submitted within 30 
days of such changes.
    The final rules make explicit an implied requirement of the 
proposed rules, i.e., that, if a unit is added to a source or is moved 
from one source to a second source, a certificate of representation 
needs to be submitted to reflect the change. This requirement is 
implicit in the proposed rules when a unit is added to a source because 
the designated representative would not be authorized to make 
submissions concerning the added unit unless that unit were included on 
the certificate of representation. Similarly, where a unit is moved to 
another source, new certificates of representation would need to be 
submitted in order for the correct designated representative to be 
authorized to make submissions concerning the moved unit. Moreover, 
because compliance accounts in the Allowance Management System would 
cover all units at a given source and would be based on the information 
in the certificate of representation submitted by the designated 
representative for the source, when a unit is moved from a source to a 
second source, the designated representative of the second source would 
need to submit a certificate of representation removing the moved unit 
from the list of units.
    The final rules explicitly require that a new certificate of 
representation be submitted to reflect changes (whether caused by the 
addition or removal of units) in which units are located at a source. 
In addition, the final rules impose a deadline on the submission 
requirement of 30 days from the date of the change in the units. This 
is analogous to the maximum time period between a change in a unit's 
owner or operator and the deadline for submission of a new certificate 
of representative reflecting to the change. Long before any actual move 
of a unit to a new location, owners and operators will need to make 
decisions about, and plan the implementation of, such a move. 
Consequently, EPA believes that a 30-day deadline after any move for 
reflecting the move in the certificate of representation is reasonable. 
In the event the change involves the addition of a unit that operated 
before being located at the source, the final Transport Rule also 
requires that the designated representative provide in the certificate 
of representation information on the entity from which the unit was 
obtained, the date on which the unit was obtained, and the date on 
which the unit became located at the source. In the event of a change 
involving the removal of a unit, the designated representative must 
provide in the certificate of representation information on the entity 
that obtained the unit, the date on which that entity obtained the 
unit, and the date on which the unit became no longer located at the 
source. This information will enable the Administrator to determine 
what actions are necessary to reflect the change in units located at 
the sources involved. For example, if a covered unit is moved from one 
source to second source, the Administrator will have the information 
necessary to determine whether the unit's allocation should be changed 
to reflect movement of the unit from one state to another.
(4) Allowance Management System
    Sections 97.420 through 97.428, 97.520 through 97.528, 97.620 
through 97.628, and 97.720 through 97.728 establish the procedures and 
requirements for using and operating the Allowance Management System 
(which is the electronic data system through which the Administrator 
handles allowance allocation, holding, transfer, and deduction), and 
for determining compliance with the emissions limitations and assurance 
provisions, in an efficient and transparent manner. The Allowance 
Management System also provides the allowance markets with a record of 
ownership of allowances, dates of allowance transfers, buyer and seller 
information, and the serial numbers of allowances transferred. Except 
as discussed herein, these sections of the final rules are essentially 
the same as in the proposed rules and for each of the Transport Rule 
trading programs.
(i) Sec. Sec.  97.420, 97.520, 97.620, and 97.720--Compliance, 
Assurance, and General Accounts
    Under the final rules, the Allowance Management System contains 
three types of accounts. One type comprises compliance accounts, one of 
which the Administrator establishes for each covered source upon 
receipt of the certificate of representation for the source. A 
compliance account is the account in which all allowance allocations 
must be recorded and in which any allowances used by the covered source 
for compliance with the emission limitations must be held. The 
designated representative and alternate for the source are also the 
authorized account representative and alternate for the compliance 
account.
    A second type comprises general accounts, which can be established 
by any entity upon receipt by the Administrator of an application for a 
general account. General accounts can be used by any person or group 
for holding or trading allowances. To open a general account, a person 
or group must submit an application for a general account, which is 
similar in many ways to a certificate of representation. The provisions 
for changing the authorized account representative and alternate, for 
submitting a superseding application to take account of changes in the 
persons having an ownership interest with respect to allowances, and 
for delegating authority to make electronic submissions are analogous 
to those applicable to comparable matters for designated 
representatives and alternates.
    A third type comprises assurance accounts. The Administrator 
establishes one assurance account for each group of units having a 
common designated representative and located in a state where the 
assurance provisions are triggered by total emissions exceeding the 
state trading budget plus variability.
(ii) Sec. Sec.  97.421 Through 97.423, 97.521 Through 97.523, 97.621 
Through 97.623, and 97.721 Through 97.723--Recordation of Allowance 
Allocations and Transfers
    Under the final rules, by November 7, 2011, the Administrator must 
record allowance allocations for existing units, as set forth in a 
required notice of data availability, for the Transport Rule annual 
NOX, ozone-season NOX, and SO2 trading 
programs for 2012 and 2013, unless, as discussed elsewhere in this 
preamble, a state notifies the Administrator that the state will submit 
a SIP revision with existing-unit allocations for 2013 by May 1, 2012. 
If the Administrator approves that SIP revision by October 1, 2012, the 
Administrator will record the state-determined existing-unit 
allocations for 2013, and, in the absence of such approval by that 
date, the Administrator will record the EPA-determined existing-unit 
allocations for 2013. By July 1, 2013, the Administrator must record 
existing-unit allowance allocations (whether EPA- or state-determined) 
for each Transport Rule trading program for 2014 and 2015. By July 1, 
2014, the Administrator must

[[Page 48340]]

record existing-unit allowance allocations for each Transport Rule 
trading program for 2016 and 2017. By July 1, 2015, the Administrator 
must record existing-unit allowance allocations for each Transport Rule 
trading program for 2018 and 2019. By July 1, 2016 and July 1 of each 
year thereafter, the Administrator must record existing-unit allowance 
allocations for each Transport Rule trading program for the control 
period in the fourth year after the year of the applicable recordation 
deadline. By August 1, 2012 and August 1 of each year thereafter, the 
Administrator must record new-unit allowance allocations for each 
Transport Rule trading program for that year. These recordation 
deadlines differ from those in the proposed rules for two reasons. 
First, as discussed elsewhere in this preamble, EPA is adopting 
provisions that allow states to submit, and EPA to approve, SIP 
revisions (abbreviated or full SIPs) under which the state, rather than 
the Administrator, determines the distribution of allowances under one 
or more of the Transport Rule trading programs applicable in the state. 
In selecting allocation recordation deadlines, EPA took into account 
and balanced certain countervailing factors. On one hand, EPA 
considered the need to provide a reasonable time for a state to 
develop, propose, and finalize, and for EPA to review and propose and 
finalize approval of, the SIP revision and the desirability of 
providing a reasonable opportunity for state distributions to become 
effective for a year relatively soon after the 2012 commencement of the 
Transport Rule trading programs. EPA's experience with prior trading 
programs has shown that the process for development and submission of 
SIP revisions by states and approval by EPA in many cases is about 18 
months and in some cases even longer. On the other hand, EPA considered 
the desirability of owners and operators having allocations in their 
compliance accounts a reasonable time before the year for which the 
allocations are made (i.e., the vintage year). Having the allocations 
recorded, to the extent possible, before the vintage year facilitates 
compliance decisions and use of the allowance market in implementing 
such decisions. EPA believes that optimally allocations would be 
recorded at least 3 years in advance of the vintage year.
    In balancing these countervailing factors, EPA is adopting an 
allocation recordation schedule that provides initially for recordation 
ranging from 6 months to 18 months before the beginning of the control 
period in the first 2 years (i.e., 2012 and 2013) for which allocations 
are made and that, as allocations for control periods in subsequent 
years are recorded, gradually increases the amount of time between 
recordation and the beginning of the year of the control period 
involved until allocations are recorded about three and one-half years 
in advance. With regard to the need to facilitate states' distribution 
of allowances, this approach gives states multiple opportunities to 
develop, submit, and obtain EPA approval for SIPs under which the 
states (rather than EPA) will distribute allowances under the Transport 
Rule trading programs for control periods relatively early in the 
programs. Because of time (which has in the past ranged from about 6 
months to about 2 years) it may take for a state to develop and submit 
such a SIP and because of the time (which has in the past been at least 
6 months) it will likely take EPA to review and approve such a SIP, EPA 
believes that 2013 is the first year for which a state can determine 
allowance distributions and have them recorded some minimal time before 
the control period involved. With regard to the need to record 
allowances in advance, this approach achieves recordation at least 6 
months in advance and eventually achieves recordation by what EPA 
believes is an optimal amount of time (greater than 3 years) before the 
control period for which recorded allowances are issued.
    As discussed elsewhere in this preamble, the approach to allowance 
recordation in the final rules results in following schedule for 
submission of abbreviated or full SIPs under the final Transport Rule. 
SIP revisions with existing-unit allocations for 2013 control periods 
must be submitted to the Administrator by April 1, 2012. Complete 
abbreviated and full SIPs must be submitted to the Administrator by: 
December 1, 2012 in order to govern allowance allocation and auction 
for control periods in 2014 and 2015; December 1, 2013 in order to 
govern control periods in 2016 and 2017; December 1, 2014 in order to 
govern allowance allocation and auction for control periods in 2018 and 
2019; and December 1, 2015 and by January 1 of any year thereafter in 
order to govern allowance allocation and auction for control periods in 
the fifth year after the year of such submission deadline.
    The second reason for the differences in the recordation deadlines 
in the final rules, as compared to the proposed rules, is that, in 
order to simplify the recordation schedule for owners and operators and 
EPA, EPA set uniform recordation deadlines for all of the Transport 
Rule trading programs. EPA believes that these deadlines provide the 
Agency sufficient time, after receipt of any information necessary to 
determine allocations (e.g., for new unit set-aside allocations, the 
emission data from the control period in the prior year), to complete 
the recordation of allocations and, as discussed above, makes the 
allocations available to owners and operators before the year for which 
the allocations are made. EPA notes that these are deadlines and that 
the Administrator has the discretion, where feasible and appropriate, 
to record allocations before such deadlines.
    Under the final rules (as under the proposed rules), the process 
for transferring allowances from one account to another is quite 
simple. A transfer is submitted providing, in a format prescribed by 
the Administrator, the account numbers of the accounts involved, the 
serial numbers of the allowances involved, and the name and signature 
of the transferring authorized account representative or alternate. If 
the transfer form containing all the required information is submitted 
to the Administrator and, when the Administrator attempts to record the 
transfer, the transferor account includes the allowances identified in 
the form, the Administrator records the transfer by moving the 
allowances from the transferor account to the transferee account within 
5 business days of the receipt of the transfer form.
(iii) Sec. Sec.  97.424, 97.524, 97.624, and 97.724--Compliance With 
Emissions Limitations
    Under the final rules (as under the proposed rules), once a control 
period has ended (i.e., December 31 for the Transport Rule 
NOX and SO2 annual trading programs and September 
30 for the ozone-season NOX trading program), covered 
sources have a window of opportunity--until the allowance transfer 
deadline of midnight on March 1 or December 1 following the control 
period for the annual and ozone season trading programs respectively--
to evaluate their reported emissions and obtain any allowances that 
they need to cover their emissions during that control period. Each 
allowance issued in each Transport Rule trading program authorizes 
emission of one ton of the pollutant involved, and so is usable for 
compliance in that trading program, for a control period in the year 
for which the allowance was allocated or a later year. Consequently, 
each source needs--as of the allowance transfer deadline--to have in 
its compliance account, or

[[Page 48341]]

properly submit a transfer that moves into its compliance account, 
enough allowances usable for compliance to authorize the source's total 
emissions for the control period.
    If a source fails to hold sufficient allowances for compliance to 
cover the emissions, then the owners and operators must provide, for 
deduction by the Administrator, two allowances allocated for the 
control period, in the year of when the emissions occurred, any prior 
year, or the year immediately after the year of the emissions, for 
every allowance that the owners and operators failed to hold as 
required to cover emissions. In addition, the owners and operators are 
subject to discretionary civil penalties for each violation.
(iv) Sec. Sec.  97.425, 97.525, 97.625, and 97.725--Compliance With 
Assurance Provisions
    Under the final rules (as under the proposed rules), the assurance 
provisions ensure that each state will eliminate its significant 
contribution to nonattainment and interference with maintenance that 
EPA identifies in this action. A requirement that owners and operators 
surrender allowances under the assurance provisions is triggered only 
for certain owners and operators of sources and units in a state where 
the total state covered-unit emissions for a control period exceed the 
applicable state trading budget with the variability limit. Moreover, 
the surrender requirement is implemented based on groups of sources and 
units with a common designated representative. For each group of 
sources and units with a common designated representative, the owners 
and operators of such sources and units must surrender allowances only 
if the units' emissions (referred to as the common designated 
representative's share of emissions) during the control period involved 
exceed the units' allocations plus share of the state variability limit 
(referred to as the common designated representative's share of the 
state trading budget with variability).
    As discussed elsewhere in this preamble, EPA decided to implement 
the assurance provisions on a common designated representative basis, 
rather than on an owner basis. The final rules implement in a series of 
steps the process of determining which states have total covered-unit 
emissions sufficient to trigger the allowance surrender requirement for 
a given control period and determining, using the approach based on 
common designated representatives, which owners and operators are 
subject to the allowance surrender and whether those owners and 
operators are in compliance. This common-designated-representative-
based process is more streamlined than the owner-based process in the 
proposed rules.
    First, the Administrator performs the calculations necessary to 
determine whether any state has total covered-unit emissions for a 
control period greater than the state trading budget with the 1-year 
variability limit. As discussed elsewhere in this preamble, EPA decided 
not to use a 3-year variability limit because, among other things, such 
a limit seems unnecessary to ensuring elimination of significant 
contribution to nonattainment and interference with maintenance and 
would make compliance planning extremely difficult for owners and 
operators. By June 1, 2013 and June 1 of each year thereafter, the 
Administrator promulgates a notice of data availability of the results 
of these calculations.
    Second, by July 1, for states identified in the June 1 notice of 
data availability as having emissions exceeding the state trading 
budget with variability, the designated representative of each new unit 
in the state that operated during but did not receive an allocation for 
the year involved must submit a statement to the Administrator with 
certain information about the unit. This information--i.e., the unit's 
allowable emission rate for the pollutant involved (NOX or 
SO2) and heat rate--is used to calculate a surrogate 
allocation for the unit to be used solely for the purposes of 
determining whether the group of units with a common designated 
representative that includes the unit had emissions exceeding 
allocations plus share of the state's variability limit.
    Third, the Administrator calculates, for each state identified in 
the June 1 notice of data availability and for each common designated 
representative of a group of units (which groups can include one or 
more units and sources) in the state, the common designated 
representative's share of emissions, the common designated 
representative's share of the state trading budget with the variability 
limit, and the amount (if any) that the groups of owners and operators 
of units represented by the common designated representative (which 
groups can include one or more owners and operators) in the state must 
surrender under the assurance provisions (i.e., the common designated 
representative's proportionate share of the excess of state emissions 
over the state trading budget with the variability limit). The 
Administrator promulgates by August 1 a notice of data availability of 
the results of these calculations, provides an opportunity for 
submission of objections, and promulgates by October 1 a second notice 
of data availability of any necessary adjustments to the calculations. 
In contrast with the proposed rules, objections may be submitted 
concerning information in the August 1 notice, whether or not that 
information was also provided in the June 1 notice. In short, the 
process of issuing notices is shortened in the final rules by providing 
one, comprehensive opportunity to submit objections to the June 1 and 
August 1 notices, rather than two separate opportunities, one for each 
notice.
    Also in contrast with the proposed rules, the deadlines for 
issuance of notices of data availability for implementation of the 
assurance provisions are made uniform under the final rules for all of 
the Transport Rule trading programs. EPA is taking this approach for 
the same reasons that the deadlines for issuance of notices of data 
availability for new unit set-aside allocations are made uniform for 
all of these trading programs.
    Fourth, the owners and operators identified in the October 1 notice 
of data availability as being required to surrender allowances under 
the assurance provisions must transfer, by November 1, to the assurance 
account created by the Administrator for such owners and operators the 
amount of allowances (usable for compliance) that the Administrator 
determined in the October 1 notice of data availability. Where the 
October 1 notice indicates that a specified surrender amount is owed by 
a group of two or more owners and operators, all the group members are 
liable for the surrender amount, and it is up to the owners and 
operators in the group to decide who will actually surrender 
allowances. This is analogous to the situation where a group of two or 
more owners and operators of covered units at a source is required to 
hold allowances covering the unit's emissions and therefore the group 
of owners and operators is liable. See 58 FR 3590, 3599 (January 11, 
1993) (discussing liability of owners and operators under allowance-
holding requirements of the Acid Rain Program).
    EPA believes that the approach of making the owners and operators 
responsible for deciding which of them will actually surrender the 
necessary allowances under the assurance provisions is reasonable 
because the identity of who is an owner or operator (particularly who 
is an owner) of a unit or source and the percentage of an owner's share 
can change during the year and this information is available to the 
owners and operators on an ongoing

[[Page 48342]]

basis, and not to EPA unless EPA were to impose new requirements for 
reporting this information. Further, EPA believes that it is reasonable 
to leave to private agreements the establishment of procedures for 
determining when, and under what conditions, specific owners and 
operators will provide the allowances for surrender. Owners and 
operators already make these types of determinations with regard to the 
surrender requirements in meeting the emissions limitations and any 
excess emission penalties.
    As part of implementing the common-designated-representative-based 
approach of the assurance provisions in the final Transport Rule, the 
final rules provide that the Administrator (instead of the owners, as 
in the proposed rules) will create an assurance account for each group 
of the owners and operators of units and sources with a common 
designated representative in each state where the assurance provisions 
are triggered. Because the final rules require owners and operators to 
transfer surrendered allowances to the appropriate assurance account 
(rather than requiring the Administrator to deduct from accounts 
established by the owners), there is no need for the proposed rule 
provisions concerning identification of which allowances are to be 
deducted and first-in, first-out deduction in the absence of such 
identification.
    The final rules provide that, in general, the surrender amounts 
specified in the October 1 notice for owners and operators are final 
and will not be revised even if the underlying data (e.g., emission 
data) used in the calculations underlying the October 1 notice are 
subsequently revised. However, the final rules set forth limited 
exceptions to this: Where such data are revised as a result of a 
decision in or settlement of litigation concerning the data on appeal. 
EPA believes that the limitation on revisions of the surrender amounts 
specified in the October 1 notice are necessary to provide some 
certainty to owners and operators and avoid the potential for multiple 
changes in owners' and operators' required surrender amounts. Because 
the surrender amount for each group of owners and operators of units 
and sources with a common designated representative in a state is 
calculated using emission data from all of the covered units in that 
state, each change in one or a few units' emission data that might 
occur after issuance of the October 1 notice could otherwise change the 
calculated surrender amounts for all or many groups in the state. For 
the limited exceptions where the final rules provide that the surrender 
amounts specified in the August 1 notice may be revised, the final 
rules require the Administrator to set a new surrender deadline for any 
additional surrender required and to transfer allowances back out of 
the assurance account involved for any reduced surrender requirement, 
as appropriate.
    Under the final rules (as under the proposed rules), it is not a 
violation of the CAA for total state covered-unit emissions to exceed 
the state trading budget with the variability limit or for a group of 
owners and operators to become subject to the allowance surrender 
requirement under the assurance provisions. However, the failure of any 
group of owners and operators to surrender the required amount of 
allowances in the assurance account created for such owners and 
operators violates the CAA and is subject to discretionary penalties, 
with each required allowance that was not surrendered and each day of 
the control period involved constituting a violation.
(v) Sec. Sec.  97.426 Through 97.428, 97.526 Through 97.528, 97.626 
Through 97.628, and 97.726 Through 97.728--Miscellaneous Provisions
    These sections in the final rules (as in the proposed rules) 
include provisions allowing banking of the allowances issued in the 
Transport Rule trading programs, i.e., the retention of unused 
Transport Rule allowances allocated for a given control period for use 
or trading in a later control period. While this can potentially cause 
emissions from sources in some states in some control periods to be 
greater than the allowances allocated for those control periods, the 
assurance provisions limit such emissions in a way that ensures that 
each state's significant contribution to nonattainment and interference 
with maintenance that EPA has identified in this action will be 
eliminated.
    These sections also include provisions stating that the 
Administrator can, at his or her discretion and on his or her own 
motion, correct any type of error that he or she finds in an account in 
the Allowance Management System. In addition, the Administrator can 
review any submission under the Transport Rule trading programs, make 
adjustments to the information in the submission, and deduct or 
transfer allowances based on such adjusted information.
(5) Emissions Monitoring, Recordkeeping, and Reporting
    Sections 97.430 through 97.435, 97.530 through 97.535, 97.630 
through 97.635, and 97.730 through 97.735 establish emissions 
monitoring, recordkeeping, and reporting requirements for Transport 
Rule units. These provisions reference the relevant sections of Part 75 
(40 CFR part 75), where the specific procedures and requirements for 
monitoring and reporting NOX and SO2 mass 
emissions are set forth. The provisions in the final rules are 
virtually the same as the monitoring, recordkeeping, and reporting 
requirements in the proposed rules and under previous EPA-administered 
trading programs, e.g., the Acid Rain Program and NOX Budget 
and CAIR trading programs. The final rule provisions are also 
essentially the same for each of the Transport Rule trading programs, 
except for differences reflecting the different pollutants and control 
periods involved.
    Under the provisions of the final rules and under Part 75, a unit 
has several options for monitoring and reporting. A unit's options are 
to use: a CEMS; an excepted monitoring methodology (NOX mass 
monitoring for certain peaking units and SO2 mass monitoring 
for certain oil- and gas-fired units); low mass emissions monitoring 
for certain, non-coal-fired, low emitting units; or an alternative 
monitoring system approved by the Administrator through a petition 
process. In addition, unit owners and operators may submit, and the 
Administrator can approve, petitions for alternatives to Transport Rule 
and Part 75 monitoring, recordkeeping, and reporting requirements.
    As discussed elsewhere in this preamble, the final rules and Part 
75 specify that each CEMS must undergo rigorous initial certification 
testing and periodic quality assurance testing thereafter. In addition, 
when a monitoring system is not operating properly, standard substitute 
data procedures are applied and result in a conservative estimate of 
emissions for the period involved. Further, the final rules and Part 75 
require electronic submission, to the Administrator and in a format 
prescribed by the Administrator, of a quarterly emissions report.
    The final rules include revised language in Sec. Sec.  
97.430(b)(3), 97.530(b)(3), 97.630(b)(3), and 97.730(b)(3) that 
incorporates by reference, and thereby applies to units in the 
Transport Rule trading programs, clarification that EPA recently 
adopted in Sec.  75.4(e) of Part 75 (for Acid Rain Program units)

[[Page 48343]]

concerning the requirements for certification, recertification, and 
diagnostic testing of emission monitoring systems when a unit adds a 
new stack or new add-on SO2 or NOX emission 
control device. See 76 FR 17288, 17298-300 (March 28, 2011). The 
revised language is adopted for the reasons set forth in the preamble 
of that Acid Rain Program final rule and in order to continue the 
approach, in the Transport Rule trading program rules, of adopting 
monitoring, recordkeeping, and reporting requirements that are 
generally consistent with those in the Acid Rain Program, which covers 
many units in the Transport Rule trading programs.

XII. Statutory and Executive Order Reviews

    The projected impacts of this final rule as presented throughout 
the preamble do not reflect minor technical corrections to 
SO2 budgets in three states (KY, MI, and NY) made after the 
impact analyses were conducted. These projections also assumed 
preliminary variability limits that were smaller than the variability 
limits finalized in this rule. EPA conducted sensitivity analysis 
confirming that these differences do not meaningfully alter any of the 
Agency's findings or conclusions based on the projected cost, benefit, 
and air quality impacts presented for the final Transport Rule. The 
results of this sensitivity analysis are presented in Appendix F in the 
final Transport Rule RIA.

A. Executive Order 12866: Regulatory Planning and Review and Executive 
Order 13563: Improving Regulation and Regulatory Review

    Under EO 12866 (58 FR 51735, October 4, 1993), this action is an 
``economically significant regulatory action'' because it is likely to 
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.
    Accordingly, EPA submitted this action to the OMB for review under 
EO 12866 and EO 13563 (76 FR 3821, January 21, 2011) and any changes in 
response to OMB recommendations have been documented in the docket for 
this action. In addition, EPA prepared an analysis of the potential 
costs and benefits for this action. This analysis is contained in the 
Regulatory Impact Analysis (RIA) for this action. For more information 
on the costs and benefits for this rule, please refer to Table VIII.C-3 
of this preamble.
    When estimating the human health benefits and compliance costs in 
Table VIII.C-3 of this preamble, EPA applied methods and assumptions 
consistent with the state-of-the-science for human health impact 
assessment, economics, and air quality analysis. EPA applied its best 
professional judgment in performing this analysis and believes that 
these estimates provide a reasonable indication of the expected 
benefits and costs to the nation of this rulemaking. The RIA available 
in the docket describes in detail the empirical basis for EPA's 
assumptions and characterizes the various sources of uncertainties 
affecting the estimates below. In doing what is laid out above in this 
paragraph, EPA adheres to EO 13563, ``Improving Regulation and 
Regulatory Review,'' (76 FR 3,821, January 21, 2011), which is a 
supplement to EO 12866.
    In addition to estimating costs and benefits, EO 13563 focuses on 
the importance of a ``regulatory system [that] * * * promote[s] 
predictability and reduce[s] uncertainty'' and that ``identify[ies] and 
use[s] the best, most innovative, and least burdensome tools for 
achieving regulatory ends.'' EO 13563 also states that ``[i]n 
developing regulatory actions and identifying appropriate approaches, 
each agency shall attempt to promote such coordination, simplification, 
and harmonization. Each agency shall also seek to identify, as 
appropriate, means to achieve regulatory goals that are designed to 
promote innovation.'' We recognize that the utility sector has 
compliance obligations related to multiple environmental statutes 
authorizing regulatory action, including this rule's requirements to 
reduce interstate transport of harmful ozone and fine particles and 
their precursors, as well as other rules' requirements to reduce air 
toxic emissions, to reduce greenhouse gas emissions, to safely manage 
coal combustion wastes, and to protect aquatic wildlife from water 
intake procedures. In the wake of promulgating this final rule, EPA 
recognizes that moving forward the agency needs to approach these 
rulemakings in ways that allow the industry to make practical 
investment decisions that minimize costs in complying with all of the 
final rules, while still securing the fundamentally important 
environmental and public health benefits that led Congress to enact 
those authorities in the first place. At the same time, EPA notes that 
the flexibility inherent in the allowance-trading mechanism included in 
this rule affords utilities themselves a degree of latitude to 
determine how best to integrate compliance with the emission reduction 
requirements of this rule and those of the other rules.
    The final rule will also reduce emissions of directly emitted PM 
and ozone precursors, and estimates of the PM2.5-related 
benefits of these air quality improvements may be found in Tables 
VIII.C-1 and VIII.C-2 of this preamble. When characterizing uncertainty 
in the PM-mortality relationship, EPA has historically presented a 
sensitivity analysis applying alternate assumed thresholds in the PM 
concentration-response relationship. In its synthesis of the current 
state of the PM science, EPA's 2009 Integrated Science Assessment for 
Particulate Matter concluded that a no-threshold log-linear model most 
adequately portrays the PM-mortality concentration-response 
relationship. In the RIA accompanying this rulemaking, rather than 
segmenting out impacts predicted to be associated levels above and 
below a ``bright line'' threshold, EPA includes a ``lowest measured 
level'' (LML) analysis that illustrates the increasing uncertainty that 
characterizes exposure attributed to levels of PM2.5 below 
the LML of each epidemiological study used to estimate 
PM2.5-related premature death. Figures provided in the RIA 
show the distribution of baseline exposure to PM2.5, as well 
as the lowest air quality levels measured in each of the epidemiology 
cohort studies. This information provides a context for considering the 
likely portion of PM-related mortality benefits occurring above or 
below the LML of each study; in general, our confidence in the size of 
the estimated reduction PM2.5-related premature mortality 
diminishes as baseline concentrations of PM2.5 are lowered. 
Approximately 69 percent of the avoided impacts occur at or above an 
annual mean PM2.5 level of 10 [mu]g/m\3\ (the LML of the 
Laden et al. 2006 study); about 96 percent occur at or above an annual 
mean PM2.5 level of 7.5 [mu]g/m\3\ (the LML of the Pope et 
al. 2002 study). Although the LML analysis provides some insight into 
the level of uncertainty in the estimated PM mortality benefits, EPA 
does not view the LML as a threshold and continues to quantify PM-
related mortality impacts using a full range of modeled air quality 
concentrations. It is important to note that the monetized benefits 
include many but not all health effects associated with 
PM2.5 exposure. Benefits are shown as a range from Pope, et 
al., (2002) to Laden, et al., (2006). These models assume that all fine 
particles,

[[Page 48344]]

regardless of their chemical composition, are equally potent in causing 
premature mortality because there is no clear scientific evidence that 
would support the development of differential effects estimates by 
particle type.
    The cost analysis is also subject to uncertainties. Estimating the 
cost conversion from one process to another is more difficult than 
estimating the cost of adding control equipment because it is more 
dependent on plant specific information. More information on the cost 
uncertainties can be found in the RIA.
    A summary of the monetized benefits and net benefits for the final 
rule at discount rates of 3 percent and 7 percent is in Table VIII.C-3 
of this preamble. For more information on the benefits analysis, please 
refer to the RIA for this rulemaking, which is available in the docket.

B. Paperwork Reduction Act

    EPA is required to document the information collection burden 
imposed by the Transport Rule on industry, states, and EPA in an 
information collection request (ICR). The ICR describes the information 
collection requirements associated with the Transport Rule and 
estimates the incremental costs of compliance with all such 
requirements, such as the requirement for industry to monitor, record, 
and report emission data to EPA.
    The ICR for the final Transport Rule has been submitted for 
approval by OMB under the Paperwork Reduction Act, 44 U.S.C. 3501 et 
seq., and the information collection requirements it documents are not 
enforceable until such approval has been granted. An ICR was also 
submitted to OMB in support of the proposed Transport Rule; no adverse 
comment was received by EPA on either the information collection 
requirements or their associated cost estimates as described in that 
document.
    The costs associated with the information collection requirements 
of the Transport Rule include start-up and capital costs for units 
newly affected by an emission trading program, or whose reporting 
status has changed (e.g., from ozone-season-only to annual reporting), 
as well as the additional operation and maintenance costs for Transport 
Rule-affected units already participating in an EPA-administered cap 
and trade program. More information on the ICR analysis is included in 
the final Transport Rule docket.
    The records and reports generated by these activities will be used 
by EPA and states to ensure that affected facilities comply with 
emission limits and other requirements. Such records and reports are 
also helpful to EPA and states in both identifying affected facilities 
that may not be in compliance with applicable requirements and in 
discerning which units and what records or processes should be 
inspected.
    The incremental capital and operating costs associated with the 
recordkeeping and reporting burden to Transport Rule-affected sources 
in states participating in the Transport Rule trading programs are 
approximately $26 million annually in 2010 dollars. The total number of 
burden hours associated with the recordkeeping and reporting burden to 
Transport Rule-affected sources in states participating in the 
Transport Rule trading programs is approximately 185,000 hours 
annually. These estimates include the annualized cost of installing and 
operating appropriate SO2 and NOX emission 
monitoring equipment to measure and report the total emissions of these 
pollutants from affected EGUs (serving generators greater than 25 MW). 
The burden to state and local air agencies, as documented in the ICR, 
includes any necessary SIP revisions, performance of monitor 
certifications, and fulfillment of audit responsibilities. Burden is 
defined at 5 CFR 1320.3(b).
    The amendments do not require any notifications or reports beyond 
those required by the General Provisions. The recordkeeping 
requirements require only the specific information needed to determine 
compliance, which is specifically authorized by CAA section 114 (42 
U.S.C. 7414). All information submitted to EPA for which a claim of 
confidentiality is made will be safeguarded according to EPA policies 
in 40 CFR part 2, subpart B, Confidentiality of Business Information. 
An Agency may not conduct or sponsor, and a person is not required to 
respond to a collection of information unless it displays a currently 
valid OMB control number. The OMB control numbers for EPA's regulations 
in 40 CFR are listed in 40 CFR part 9. When this ICR is approved by 
OMB, the Agency will publish a technical amendment to 40 CFR part 9 in 
the Federal Register to display the OMB control number for the approved 
information collection requirements contained in this final rule.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) generally requires an agency 
to prepare a regulatory flexibility analysis of any rule subject to 
notice and comment rulemaking requirements under the Administrative 
Procedure Act or any other statute unless the agency certifies that the 
rule will not have a significant economic impact on a substantial 
number of small entities. Small entities include small businesses, 
small organizations, and small governmental jurisdictions.
    For purposes of assessing the impacts of this final rule on small 
entities, small entity is defined as:
    (1) A small business as defined by the Small Business 
Administration's (SBA) regulations at 13 CFR 121.201. For the electric 
power generation industry, the small business size standard is an 
ultimate parent entity defined as having a total electric output of 4 
million megawatt-hours (MWh) or less in the previous fiscal year.
    (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 XII.C-1--Potentially Regulated Categories and Entities a
------------------------------------------------------------------------
                                                 Examples of potentially
            Category             NAICS code \b\     regulated entities
------------------------------------------------------------------------
Industry.......................          221112  Fossil-fuel-fired
                                                  electric utility steam
                                                  generating units.
Federal Government.............      \c\ 221112  Fossil-fuel-fired
                                                  electric utility steam
                                                  generating units owned
                                                  by the federal
                                                  government.
State/Local Government.........      2\c\ 21112  Fossil-fuel-fired
                                                  electric utility steam
                                                  generating units owned
                                                  by municipalities.
Tribal Government..............          921150  Fossil-fuel-fired
                                                  electric utility steam
                                                  generating units in
                                                  Indian Country.
------------------------------------------------------------------------
\a\ Include NAICS categories for source categories that own and operate
  electric generating units only.
\b\ North American Industry Classification System.
\c\ Federal, state, or local government-owned and operated
  establishments are classified according to the activity in which they
  are engaged.

[[Page 48345]]

    EPA used Velocity Suite's Ventyx data as a basis for identifying 
plant ownership and compiling the list of potentially affected small 
entities. For plants burning fossil fuel as the primary fuel, plant-
level boiler and generator capacity, heat input, generation, and 
emission data were aggregated by owner and then parent company. For 
cooperatives, investor-owned utilities, and subdivisions that generate 
less than 4 billion kWh of electricity annually but may be part of a 
large entity, additional research on power sales, operating revenues, 
and other business activities was performed to make a final 
determination regarding size.
    After considering the economic impacts of this final rule on small 
entities, EPA certifies that this action will not have a significant 
economic impact on a substantial number of small entities (No SISNOSE). 
This certification is based on the economic impact of this final rule 
to all affected small entities across all industries affected. EPA 
assessed the potential impact of this action on small entities and 
found that there are about 660 potentially affected small units (i.e., 
greater than 25 MW and generating less than 4 million MWh) out of 3,625 
existing units in the Transport Rule states. The majority of these EGUs 
are owned by entities that do not meet the small entity definition. The 
remaining 271 of the 660 EGUs are owned by 108 potentially affected 
small entities and are likely to be affected by this rule. EPA 
estimates that 24 of the 108 identified small entities will have 
annualized costs greater than 1 percent of their revenues, and the 
other 84 are projected to incur costs less than 1 percent of revenues. 
Eleven small entities out of 108--approximately 10 percent--are 
estimated to have annualized costs greater than 3 percent of their 
revenues. EPA has lessened the impacts for small entities by excluding 
all units smaller than 25 MWe. This exclusion, in addition to the 
exemptions for cogeneration units and solid waste incineration units, 
eliminates the burden of higher costs for a substantial number of small 
entities located in the Transport Rule states.
    While the total number of small entities has increased compared to 
the proposal as a result of updated modeling and changes in geographic 
coverage, the number with compliance costs greater than 1 percent of 
revenues has fallen, and both the number and percentage of 
significantly impacted small entities (costs greater than 3 percent of 
revenues) are lower--now 10 percent compared to 17 percent in the 
proposal. The share of significantly impacted small entities has fallen 
because of updated modeling and the change in the allowance allocation 
methodology (see section VII.D for more information about allowance 
allocations).
    Although this final rule will not have a significant economic 
impact on a substantial number of small entities, EPA nonetheless has 
tried to reduce the impact of this rule on small entities. In EPA's 
modeling, most of the cost impacts for these small entities and their 
associated units are driven by lower electricity generation relative to 
the base case. Specifically, two small units reduce their generation by 
significant amounts, driving the bulk of the costs for all small 
entities. Excluding these two units, one of the main drivers of small 
entity impacts is higher fuel costs, which the affected units would 
incur irrespective of whether they had to comply with this rule. In 
addition, EPA's decision to exclude units smaller than 25 MWe has 
already significantly reduced the burden on approximately 390 small 
entities.
    For more information on the small entity impacts associated with 
the final rule, refer to the Regulatory Impact Analysis for this final 
rule, which can be found in the docket for this rule and on the Web 
site http://www.epa.gov/airtransport.

D. Unfunded Mandates Reform Act

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2 
U.S.C. 1531-1538, requires federal agencies, unless otherwise 
prohibited by law, to assess the effects of their regulatory actions on 
state, local, and tribal governments, and the private sector. This rule 
contains a federal mandate that may result in expenditures of $100 
million or more for state, local, and tribal governments, in the 
aggregate, or the private sector in any 1 year. Accordingly, EPA has 
prepared, under section 202 of the UMRA, a written statement which is 
summarized later.
    Consistent with the intergovernmental consultation provisions of 
section 204 of the UMRA, EPA held consultations with the governmental 
entities affected by this rule during the proposal phase. Subsequently, 
EPA sent a letter to the ten Representative National Organizations to 
draw their attention to the Transport Rule Notice of Data Availability 
(NODA) on allowance allocations and other related matters and to invite 
their comments. During the NODA comment period, EPA participated in 
informational calls with the Environmental Council of the States (ECOS) 
and the National Governors Association to provide information about the 
NODA directly to state and local officials. There were no new concerns 
raised during these informational calls. In addition, EPA also 
conducted consultations with federally recognized tribes prior to 
finalizing this rule and invited them to comment on the allowance 
allocation NODA. EPA has added a new unit set-aside provision to this 
final rule specifically for EGUs constructed in Indian country to 
ensure allowances are available to tribes and tribal sovereignty is 
respected.
    Consistent with section 205, EPA identified and considered a 
reasonable number of regulatory alternatives. In the proposal, EPA 
included three remedy options that it considered when developing this 
final rule: (1) The preferred remedy trading programs, (2) State 
Budgets/Intrastate Trading, and (3) Direct Controls. Moreover, section 
205 allows EPA to adopt an alternative other than the least costly, 
most cost-effective, or least burdensome alternative if the 
Administrator publishes with the final rule an explanation why that 
alternative was not adopted.
    EPA examined the potential economic impacts on state- and 
municipality-owned entities associated with this rulemaking based on 
assumptions of how the affected states will implement control measures 
to meet program requirements. Although EPA does not conclude that the 
requirements of the UMRA apply to the Transport Rule, these impacts 
have been calculated to provide additional understanding of the nature 
of potential impacts and additional information.
    EPA has determined that this rule contains a federal mandate that 
may result in expenditures of $100 million or more in 1 year. EPA has 
determined that this rule contains no regulatory requirements that 
might significantly or uniquely affect small governments and that 
development of a small government plan under section 203 of the Act is 
not required. The costs of compliance will be borne predominately by 
sources in the private sector although a small number of sources owned 
by state and local governments may also be impacted. The requirements 
in this action do not distinguish EGUs based on ownership, either for 
those units that are included within the scope of the rule or for those 
units that are exempted by the generating capacity cut-off. Therefore, 
this rule is not subject to the requirements of section 203 of UMRA 
because it contains no regulatory requirements that might significantly 
or uniquely affect small governments.

[[Page 48346]]

E. Executive Order 13132: Federalism

    This final 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 final rule primarily affects 
private industry, and does not impose significant economic costs on 
state or local governments. Thus, Executive Order 13132 does not apply 
to the final rule.
    Although section 6 of Executive Order 13132 does not apply to the 
final rule, EPA did provide information to state and local officials 
during development of both the proposal and final rule. EPA sent a 
letter to the ten Representative National Organizations to draw their 
attention to the Transport Rule NODA on allowance allocations and other 
related matters and to invite their comments. Following that letter in 
early 2011, EPA participated in informational calls with the 
Environmental Council of the States (ECOS) and the National Governors 
Association to provide information about the NODA directly to state and 
local officials. There were no new concerns raised during these 
informational calls.

F. Executive Order 13175: Consultation and Coordination With Indian 
Tribal Governments

    Under Executive Order 13175 (65 FR 67249, November 9, 2000), EPA 
may not issue a regulation that has tribal implications, that imposes 
substantial direct compliance costs, and that is not required by 
statute, unless the federal government provides the funds necessary to 
pay the direct compliance costs incurred by tribal governments, or EPA 
consults with tribal officials early in the process of developing the 
proposed regulation and develops a tribal summary impact statement.
    EPA has concluded that this action may have tribal implications if 
a new unit covered by the rule is built in Indian country. 
Additionally, tribes have a vested interest in how this final rule 
affects their air quality. However, it will neither impose substantial 
direct compliance costs on tribal governments, nor preempt tribal law. 
EPA consulted with tribal officials during the process of finalizing 
this regulation to permit them to have meaningful and timely input into 
its development.
    EPA received comments on the proposed Transport Rule that the 
Agency did not properly conduct consultation during the proposal phase 
of the rulemaking process. In response to these comments, EPA sent a 
letter to all federally-recognized tribes in the country offering 
consultation. In addition, several commenters also noted that the 
Agency did not adequately consider opportunities for tribes to enter 
into any of the trading programs and, in particular, did not consider 
sovereignty issues when addressing how to distribute allowances to 
potential new units in Indian country. On January 7, 2011, EPA issued a 
NODA requesting comment on allocations for new units in Indian country, 
among other topics.
    The Agency held a consultation call with three tribes on January 
21, 2011. A follow-up call was held on February 4, 2011 with two of the 
three original tribes plus 13 additional tribes, as well as 
representatives from the National Tribal Air Association. In all ten 
tribes participated in these calls as consultation and six participated 
as information-sharing. EPA considered the additional input from these 
consultation and information calls, in conjunction with the public 
comments, in the development of the final rule. Accordingly, EPA 
created an Indian country new unit set-aside to specifically address 
tribes' concerns regarding the protection of tribal sovereignty in the 
distribution of allowances for new units in Indian country. See section 
VII.D.2 of this preamble for details on the Indian country set-aside 
for new units constructed in Indian country within states covered by 
the Transport Rule.
    As required by section 7(a) of the Executive Order, EPA's Tribal 
Consultation Official has certified that the requirements of the 
Executive Order have been met in a meaningful and timely manner. A copy 
of the certification is included in the docket for this action.

G. Executive Order 13045: Protection of Children From Environmental 
Health and Safety Risks

    Executive Order 13045 (62 FR 19,885, April 23, 1997) applies to any 
rule that: (1) Is determined to be ``economically significant'' as 
defined under EO 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, the 
Agency must evaluate the environmental health or safety effects of this 
planned rule on children, and explain why this planned regulation is 
preferable to other potentially effective and reasonably feasible 
alternatives considered by the Agency.
    This action is not subject to Executive Order 13045 because it does 
not involve decisions on environmental health or safety risks that may 
disproportionately affect children. EPA believes that the emission 
reductions from the strategies in this rule will further improve air 
quality and will further improve children's health. Analyses by EPA 
that show how the emission reductions from the strategies in this rule 
will further improve air quality and children's health can be found in 
the RIA for this rule.

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 action'' 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 
proposed rulemaking, and notices of proposed rulemaking: (1)(i) That is 
a significant regulatory action under Executive Order 12866 or any 
successor order, and (ii) is likely to have a significant adverse 
effect on the supply, distribution, or use of energy; or (2) that is 
designated by the Administrator of the Office of Information and 
Regulatory Affairs as a significant energy action.'' This rule is a 
significant regulatory action under Executive Order 12866, and this 
rule is likely to have a significant adverse effect on the supply, 
distribution, or use of energy. EPA prepared a Statement of Energy 
Effects for this action as follows.
    Under the provisions of this rule, EPA projects that approximately 
4.8 GW of additional coal-fired generation may be removed from 
operation by 2014. 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. These units are predominantly small and infrequently-used 
generating units dispersed throughout the area affected by the rule. If 
current forecasts of either natural gas prices or electricity demand 
were revised in the future to be higher, that would create a greater 
incentive to keep these units operational.
    EPA estimates that average retail electricity prices could increase 
in the

[[Page 48347]]

contiguous U.S. by about 1.7 percent in 2012 and 0.8 percent in 2014. 
This is generally less of an increase than often occurs with 
fluctuating fuel prices and other market factors. Related to this, EPA 
projects limited impacts on coal and gas prices. The average delivered 
coal price decreases by about 1.4 percent in 2012 and 0.9 percent in 
2014 relative to the base case as a result of decreased coal demand and 
shifts in the type of coal demanded. EPA also projects that the 
electric power sector-delivered natural gas price will increase by 
about 0.3 percent over the 2012-2030 timeframe and that natural gas use 
for electricity generation will increase by approximately 200 billion 
cubic feet (BCF) by 2014. These impacts are well within the range of 
price variability that is regularly experienced in natural gas markets. 
Finally, under the Transport Rule, EPA projects that coal production 
for use by the power sector will increase above 2009 levels by 21 
million tons in 2012 and a further 14 million tons in 2014, as opposed 
to 30 million tons in 2012 and a further 26 million tons in 2014 
without the Transport Rule in place. The Transport Rule is not 
projected to impact production of coal for uses outside the power 
sector (e.g., export, industrial sources), which represent 
approximately 6 percent of total coal production in 2009. EPA does not 
believe that this rule will have any other impacts (e.g., on oil 
markets) that exceed the significance criteria.
    EPA believes that a number of features of the rulemaking serve to 
reduce its impact on energy supply. First, the trading component of the 
Transport Rule provides flexibility to the power sector and enables 
industry to comply with the emission reduction requirements in the most 
cost-effective manner compared to the alternative remedy approaches on 
which EPA took comment in the proposal, thus minimizing overall costs 
and the ultimate impact on energy supply. Second, the more stringent 
budgets for SO2 are set in two phases, providing adequate 
time for EGUs to install pollution controls. In addition, both the 
operational flexibility of trading and the ability to bank allowances 
for future years helps industry plan for and ensure reliability in the 
electrical system.
    For more details concerning energy impacts, see the RIA for the 
Transport Rule.

I. National Technology Transfer Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement 
Act of 1995 (NTTAA), Public Law 104-113, 12(d) (15 U.S.C. 272 note) 
directs EPA to use voluntary consensus standards in its regulatory 
activities unless to do so would be inconsistent with applicable law or 
otherwise impractical. Voluntary consensus standards are technical 
standards (e.g., materials specifications, test methods, sampling 
procedures, and business practices) that are developed or adopted by 
voluntary consensus standards bodies. NTTAA directs EPA to provide 
Congress, through OMB, explanations when the Agency decides not to use 
available and applicable voluntary consensus standards. This rule will 
require all sources to meet the applicable monitoring requirements of 
40 CFR 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 40 CFR 75.66 before 
they are used.

J. Executive Order 12898: Federal Actions To Address Environmental 
Justice in Minority Populations and Low-Income Populations

    Executive Order (EO) 12898 (59 FR 7629 (Feb. 16, 1994)) establishes 
federal executive policy on environmental justice. Its main provision 
directs federal agencies, to the greatest extent practicable and 
permitted by law, to make environmental justice part of their mission 
by identifying and addressing, as appropriate, disproportionately high 
and adverse human health or environmental effects of their programs, 
policies, and activities on minority, low-income, and Tribal 
populations in the United States. During development of this final 
Transport Rule, EPA considered its impacts on low-income, minority, and 
tribal communities in several ways and provided multiple opportunities 
for these communities to meaningfully participate in the rulemaking 
process. The proposed Transport Rule included an analysis of its 
effects on these populations; this section describes additional 
analysis conducted since proposal, EPA's responses to key comments on 
environmental justice issues raised during the comment period, and the 
public outreach and comment opportunities for this rule.
    A summary of the history, statutory authority, and key components 
of this final Transport Rule are described in the Executive Summary 
(section III) of this preamble. That section also summarizes a 
supplemental notice of proposed rulemaking (SNPR) that EPA is 
publishing to correct a procedural flaw by providing an opportunity for 
public comment on issues that arose from new analyses with updated 
inventories and modeling platforms.
    Briefly, this final Transport Rule will reduce emissions of 
SO2 and NOX in 23 eastern and central states in 
2012 and 2014 that contribute to annual and/or 24-hour PM2.5 
nonattainment or interfere with maintenance in downwind states. It will 
also reduce emissions of ozone-season NOX in 20 eastern and 
central states in 2012 and 2014 that contribute to the 1997 ozone 
nonattainment or interfere with maintenance in downwind states. This 
rule is replacing an earlier rule (the 2005 Clean Air Interstate Rule 
(CAIR)) that was first vacated and then remanded to EPA by the U.S. 
Court of Appeals for the District of Columbia Circuit in 2008.
1. Consideration of Environmental Justice in the Transport Rule 
Development Process and Response to Comments
    The effects of this final Transport Rule on the most highly exposed 
populations were integral in its development. This rule uses EPA's 
authority in CAA section 110(a)(2)(d) to reduce sulfur dioxide 
(SO2) and (nitrogen oxides) NOX pollution that 
significantly contributes to downwind PM2.5 and ozone 
nonattainment or maintenance areas. As a result, the rule will reduce 
exposures to ozone and PM2.5 in the most-contaminated areas 
(i.e., areas that are not meeting the 1997 ozone and 1997 and 2006 
PM2.5 National Ambient Air Quality Standards (NAAQS)). In 
addition, the rule separately identifies both nonattainment areas and 
maintenance areas (maintenance areas are those that are projected to 
meet the NAAQS but that, based on past data, are in danger of

[[Page 48348]]

exceeding the standards in the future). This requirement reduces the 
likelihood that any areas close to the level of the standard will 
exceed the current health-based standards in the future.
    This final Transport Rule implements these emission reductions 
using an emission trading mechanism with assurance provisions for power 
plants. EPA recognizes that many environmental justice communities have 
voiced concerns in the past about emission trading and the potential 
for any emission increases in any location. EPA also received several 
comments on this issue during the comment period for the proposed 
Transport Rule. As described below, we believe this final rule 
addresses the concerns raised on this issue during the comment period.
    PM2.5 and ozone pollution from power plants have both 
local and regional components: Part of the pollution in a given 
location--even in locations near emission sources--is due to emissions 
from nearby sources and part is due to emissions that travel hundreds 
of miles and mix with emissions from other sources. Therefore, in many 
instances the exact location of the upwind reductions does not affect 
the levels of air pollution downwind.
    It is important to note that the section of the Clean Air Act 
providing authority for this rule, section 110(a)(2)(D), unlike some 
other provisions, does not dictate levels of control for particular 
facilities. As at least one commenter noted, none of the alternatives 
put forward by EPA in the proposed rule could have ensured no emission 
increases at any facility. Under the direct control alternative, the 
emission rate for each facility would have been limited but each 
facility could emit more by increasing their power output in order to 
meet electricity reliability or other goals. Under the intrastate 
trading option, sources could not trade allowances with sources in 
other states but individual facilities within each state could have 
increased their emissions as long as another facility in the state had 
decreased theirs at some time.
    The final Transport Rule allows sources to trade allowances with 
other sources in the same or different states while firmly constraining 
any emissions shifting that may occur by requiring a strict emission 
ceiling in each state (the budget plus variability limit). In addition, 
assurance provisions in the rule outline the allowance surrender 
penalties for failing to meet the budget plus variability limits; there 
are additional allowance penalties as well as financial penalties for 
failing to hold an adequate number of allowances to cover emissions. 
This approach eliminates emissions in each state that significantly 
contribute to downwind nonattainment or maintenance areas, while 
allowing power companies to adjust generation as needed and ensure that 
the country's electricity needs will continue to be met. EPA maintains 
that the existence of these assurance provisions, including the 
penalties imposed when triggered, will ensure that state emissions will 
stay below the level of the budget plus variability limit.
    In addition, all sources must hold enough allowances to cover their 
emissions. Therefore, if a source emits more than its allocation in a 
given year, either another source must have used less than its 
allocation and be willing to sell some of its excess allowances, or the 
source itself had emitted less than its allocation in one or more 
previous years (i.e., banked allowances for future use).
    In summary, the final remedy addresses commenter concerns about 
localized hot spots and reduces ambient concentrations of pollution 
where they are most needed by sensitive and vulnerable populations by: 
Considering the science of ozone and PM2.5 transport to set 
strict state budgets to eliminate significant contributions to ozone 
and PM2.5 nonattainment and maintenance (i.e., the most 
polluted) areas; implementing air quality-assured trading; requiring 
any emissions above the level of the allocations to be offset by 
emission decreases; and imposing strict penalties for sources that 
contribute to a state's exceedance of its budget plus variability 
limit. In addition, it is important to note that nothing in this final 
rule allows sources to violate their title V permit or any other 
federal, state, or local emissions or air quality requirements.
    EPA received comments from several tribal commenters regarding the 
lack of allocations in the proposal to new units in Indian Country. EPA 
responded to these comments by changing the allocation approach in the 
final rule to create Indian country new unit set-asides. In order to 
protect tribal sovereignty, these set-asides will be managed and 
distributed by the federal government regardless of whether the 
Transport Rule in the adjoining or surrounding state is implemented 
through a FIP or SIP. While there are no existing power plants in 
Indian country covered by this Transport Rule, the Indian country set-
asides will ensure that any future new units built in Indian country 
will be able to get the necessary allowances. A full discussion of the 
Indian country new unit set-asides can be found in section VII.D.2.
    EPA also received several comments during the comment period from 
individuals and groups requesting additional emission reductions to 
further protect sensitive and vulnerable communities. While EPA has 
adjusted the emission requirements somewhat in the final rule to 
accommodate revised data and updated modeling results, we are 
finalizing emission reductions very similar to the level in the 
proposal. This is because EPA believes that the emission reductions 
required by this final rule are appropriate to meet the statutory 
requirements of CAA section 110(a)(2)(d) and respond to the concerns 
raised by the Court's opinion in North Carolina that remanded CAIR to 
the Agency in 2008.
    In addition, it is important to note that CAA section 110(a)(2)(d), 
which addresses transport of criteria pollutants between states, is 
only one of many provisions of the CAA that provide EPA, states, and 
local governments with authorities to reduce exposure to ozone and 
PM2.5 in communities. These legal authorities work together 
to reduce exposure to these pollutants in communities, including for 
minority, low-income, and tribal populations, and provide substantial 
health benefits to both the general public and sensitive sub-
populations.
    For example, the recently-proposed Mercury and Air Toxics Standards 
(MATS) would also result in significant reductions in SO2 
emissions and provide significant health and environmental benefits 
nationwide. This and other actions described in section III will have 
substantial and long-term effects on both the U.S. power industry and 
on communities currently breathing dirty air. Therefore, we anticipate 
significant interest in many, if not most, of these actions from 
environmental justice communities, among many others. EPA will continue 
to provide multiple opportunities for comment on these actions, similar 
to the opportunities provided during the comment process for this rule, 
detailed at the end of this section. We encourage environmental justice 
communities to review and comment on these actions.
2. Potential Environmental and Public Health Impacts Among Populations 
Susceptible or Vulnerable to Air Pollution
    EPA expects that this final rule will provide significant health 
and environmental benefits to, among others, people with asthma, people 
with heart disease, and people living in ozone or PM2.5 
nonattainment areas. EPA's analysis of the effects of this rule, 
including information on air quality changes and the resulting health 
benefits, is presented both in section

[[Page 48349]]

VIII of this preamble and in the Regulatory Impact Analysis (RIA) for 
this rule. These documents can be accessed through the rule docket No. 
EPA-HQ-OAR-2009-0491 and from the main EPA webpage for the rule at  
http://www.epa.gov/airtransport.
    EPA considered several aspects of the effects of the Transport Rule 
on minority, low-income, and tribal populations. These included: amount 
of emission reductions and where they take place (including any 
potential for areas of increased emissions); the changes in ambient 
concentrations across the affected area; the estimated health benefits; 
and how the estimated health benefits are distributed among different 
populations, including those susceptible and vulnerable to air 
pollution health impacts.
a. Emission Reductions
    EPA's emission modeling data indicate that implementation of the 
Transport Rule will substantially reduce SO2 emissions from 
electric generating units (EGUs). As noted in section III, emissions in 
states covered by the Transport Rule will decrease by 6.4 million tons 
(73 percent) in 2014 compared to 2005 (the year the Clean Air 
Interstate Rule was finalized). Emissions are also projected to 
decrease when compared to the base case (the base case estimates 
emissions in 2014 in the absence of this rule or the Clean Air 
Interstate Rule it is replacing). EPA estimates that SO2 
emissions in 2014 in covered states will be 3.9 million tons lower (62 
percent lower) compared to the base case.
    EPA also assessed emission changes in states not covered by the 
Transport Rule. Emissions in the states not covered by the Transport 
Rule are also projected to decrease substantially compared to 2005 
levels; in 2014 SO2 emissions are projected to be 
approximately 430,000 tons lower (30 percent lower) than in 2005.
    As described in section VI.C, EPA's modeling does project that some 
states not covered by any of the fine particle control programs in the 
final Transport Rule may experience increases of SO2 
emissions greater than 5,000 tons compared to the base case. These 
states are Arkansas, Colorado, Louisiana, Montana, and Wyoming. These 
emission increases are the result of forecasted changes in operation of 
power plant units outside of the Transport Rule states due to the 
interconnected nature of the utility grid (i.e., shifts in generation 
of electricity to sources outside the Transport Rule states) or 
influence of the rule on the market for lower sulfur coal. For example, 
EPA projects that the rule will raise demand for lower sulfur coal in 
the states covered by the Transport Rule for PM2.5 (thereby 
raising its price), which may lead sources in states not covered for 
PM2.5 to choose higher-sulfur coals that increase 
SO2 emissions in those states.
    EPA is not requiring SO2 emission reductions in these 
states under this rule because our modeling indicates none of these 
states' contributions would increase enough to cause them to meet or 
exceed the thresholds described in section V.D for either of the 
PM2.5 standards. EPA's authority under CAA section 
110(a)(2)(d) is limited to addressing this significant contribution to 
nonattainment and interference with maintenance. However, as noted 
above, EPA has recently proposed the Mercury and Air Toxics Standards 
that will apply nationwide and result in substantial additional 
SO2 emission reductions, including in states not covered by 
the Transport Rule.
    EPA's emission modeling data indicates that ozone-season 
NOX emissions from EGUs in states covered by the Transport 
Rule will be approximately 340,000 tons lower (36 percent lower) in 
2014 than they were in 2005. Emissions in states not covered by the 
Transport Rule are also expected to decrease somewhat (approximately 
82,000 tons or 25 percent). EPA's modeling does project that two states 
(California and Pennsylvania) may experience increases of 
NOX emissions greater than 5,000 tons in 2014 compared to 
2005 levels. California is not covered by the Transport Rule; in 
Pennsylvania, 2005 was an unusually low-emitting year and sources are 
projected to increase their heat input slightly (usually meaning they 
are generating more power) after the rule takes effect.
    EPA also assessed the expected changes in seasonal NOX 
emissions with implementation of the Transport Rule compared to the 
base case (i.e., without the rule) in 2014. The modeling indicates 
ozone-season NOX emissions from EGUs in both covered states 
and non-Transport Rule states under this rule will be lower than they 
would have been in 2014 in the base case. Ozone-season NOX 
emissions in covered states are projected to decrease by approximately 
74,000 tons (11 percent); ozone-season NOX emissions in non-
Transport Rule states are projected to decrease by approximately 10,000 
tons (4 percent). Both California and Pennsylvania are projected to 
have lower NOX emissions in 2014 under the Transport Rule as 
compared to the base case. In addition, EPA anticipates that additional 
upcoming actions, including likely additional interstate transport 
reductions to help states attain the upcoming new ozone NAAQS, will 
result in significant additional NOX reductions in the 
future.
b. Air Quality Improvements
    EPA assessed the air quality metrics (called ``design values'') for 
each NAAQS addressed in this rule: 24-hour PM2.5, annual 
PM2.5, and ozone. We then compared these metrics for the 
final rule to the same metrics in the recent past (2003-2007 average 
ambient air quality) and for the 2014 base case to assess improvements 
in air quality.
    EPA's modeling indicates that there will be significant 
improvements in air quality as measured by the 24-hour PM2.5 
standard. Throughout much of the eastern half of the U.S., 24-hour 
PM2.5 design values are projected to improve more than 10 
[mu]g/m\3\ compared to the 2003-2007 average levels. In addition, 
compared to the 2014 base case levels, we project the Transport Rule 
will result in improvements of 8-10 [mu]g/m\3\ in a broad swath of 
states stretching from far southwestern New York through Pennsylvania, 
Ohio, West Virginia, Maryland, Indiana, southern Illinois, eastern 
Missouri, eastern Arkansas, Kentucky, Tennessee, northern Alabama, and 
northern Mississippi. Isolated areas of Virginia and northern New 
Jersey are also expected to see this level of improvement. Improvements 
of 2-6 [mu]g/m\3\ are projected in surrounding states stretching from 
New England and New York to Minnesota, Iowa, the far eastern edge of 
Nebraska, Missouri, eastern Kansas, Oklahoma, Texas, the Gulf of Mexico 
states, and the states bordering the Atlantic Ocean from Florida to New 
Hampshire.
    EPA modeling indicates that air quality as measured by the annual 
PM2.5 design value will also improve. Improvements range 
from 2 to over 4 [mu]g/m\3\ compared to the 2003-2007 average levels 
throughout the eastern half of the U.S. Annual PM2.5 air 
quality with the Transport Rule is also projected to improve compared 
to the 2014 base case levels. The largest improvements of up to 4 
[mu]g/m\3\ are projected to occur in northern West Virginia and a small 
area in northwestern Tennessee. Improvements of up to 3 [mu]g/m\3\ are 
projected for portions of the Ohio River valley areas of southwestern 
Pennsylvania, Ohio, West Virginia, Kentucky, central Tennessee, and 
southern Indiana. Improvements of up to 2 [mu]g/m\3\ are projected to 
take place in a ring of surrounding states including all or most of New 
York, Michigan, Indiana,

[[Page 48350]]

Illinois, Missouri, Arkansas, the far eastern edge of Oklahoma, the 
northeastern edge of Texas, Louisiana, Mississippi, Alabama, Georgia, 
South Carolina, North Carolina, Virginia, Maryland, Delaware, 
Pennsylvania, and New Jersey. Smaller improvements are projected in New 
England, Wisconsin, the Plains states, southeastern New Mexico, and 
Florida.
    EPA modeling indicates that ozone air quality will improve greatly 
(10-12 ppb or more) across much of the eastern U.S. between the average 
levels seen in 2003-2007 and implementation of the Transport Rule. Most 
of the improvements take place in the base case; that is, they are the 
result of federal and state programs other than the Transport Rule. 
However, ozone air quality is projected to improve somewhat as a direct 
result of the Transport Rule. Improvements in ozone design values 
compared to the base case of more than 1 ppb are projected for portions 
of Florida, eastern Oklahoma, and areas along the upper reaches of the 
Ohio River. In addition, improvements in ozone design values of up to 1 
ppb are projected over a wide area across the eastern U.S. from New 
England to Texas and north to Minnesota. Improvements are also 
projected in north-central Colorado.
    EPA's modeling does indicate small increases in annual 
PM2.5 air quality design values in the final rule compared 
to the 2014 base case in two counties outside of the Transport Rule 
states: one county in northern Colorado and one county in eastern 
Montana. As noted above in the section on emissions, these increases 
are likely the result of forecasted changes in electricity generation 
due to the interconnected nature of both the utility grid and the 
national low-sulfur coal market. It should be noted that 2003-2007 
average air quality levels in these counties are well below the level 
of the NAAQS. In addition, other actions, including federal rules such 
as the recently proposed Mercury and Air Toxics Standards, state, or 
local actions may also improve air quality in these areas over the next 
few years.
    As described in section VIII.B, EPA anticipates that this final 
rule will reduce, but not eliminate, the number of nonattainment and 
maintenance areas for the 1997 ozone and PM2.5 and 2006 
PM2.5 NAAQS. As noted above, ozone and PM2.5 
concentrations are the result of both local emissions and long-range 
transport of pollution. Even when the significant contributions of 
upwind states are fully eliminated, additional emission reductions 
within the nonattainment area and/or the downwind state will be needed 
for some areas to attain and maintain the NAAQS.
c. Estimated Health Benefits
    This rule reduces concentrations of PM2.5 and ozone 
pollution. Exposure to these pollutants can cause, or contribute to, 
adverse health effects that affect many minority, low-income, and 
tribal individuals and communities. PM2.5 and ozone are 
particularly (but not exclusively) harmful to children, the elderly, 
and people with existing heart and lung diseases, including asthma. 
Exposure to these pollutants can cause premature death and trigger 
heart attacks, asthma attacks in those with asthma, chronic and acute 
bronchitis, emergency room visits and hospitalizations, as well as 
milder illnesses that keep children home from school and adults home 
from work. High rates of heart disease (e.g., high blood pressure) 
\123\ and asthma \124\ exist in many environmental justice communities, 
making these populations more susceptible to air pollution health 
impacts. In addition, many individuals in these communities lack access 
to high quality health care to treat these illnesses.\125\
---------------------------------------------------------------------------

    \123\ Neighborhood of Residence and Incidence of Coronary Heart 
Disease Ana V. Diez Roux, M.D., PhD et al. N Engl J Med 2001; 
345:99-106; July 12, 2001.
    \124\ Centers for Disease Control and Prevention. 2007 National 
Health 11. Interview Survey Data. Table 4-1. Current Asthma 
Prevalence Percents by Age, United States: National Health Interview 
Survey, 2007. Atlanta, GA: U.S. Department of Health and Human 
Services, CDC, 2010. Accessed June 1, 2010.
    \125\ R. Nelson, Eds. National Institute of Medicine, 2003.
---------------------------------------------------------------------------

    We estimate that in 2014 the PM-related annual benefits of the 
final rule include approximately 13,000 to 34,000 fewer premature 
mortalities, 8,700 fewer cases of chronic bronchitis, 15,000 fewer non-
fatal heart attacks, 8,500 fewer hospitalizations (for respiratory and 
cardiovascular disease combined), 10 million fewer days of restricted 
activity due to respiratory illness, and approximately 1.7 million 
fewer lost work days. We also estimate substantial health improvements 
for children in the form of fewer cases of 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 2014, annual ozone related 
health benefits are expected to include (in addition to the PM-related 
benefits above) between 27-120 fewer premature mortalities, 240 fewer 
hospital admissions for respiratory illnesses in children and older 
adults, 86 fewer emergency room admissions for asthma, 160,000 fewer 
days with restricted activity levels, and 51,000 fewer ``school 
absence'' days when children are absent from school due to illnesses. 
When adding the PM and ozone-related mortalities together, we find that 
the final rule will yield between 13,000 and 34,000 fewer premature 
mortalities.
    It should be noted that, as discussed in the RIA, there are other 
benefits to the emission reductions discussed here, including many 
other health benefits beyond reducing the risk of premature mortality. 
Additional benefits of reducing emissions of SO2 include 
improved visibility, reduced acidification of lakes and streams, and 
reduced mercury methylation in contaminated waters; additional benefits 
of NOX reductions include improved visibility, reduced 
acidification of lakes and streams, and reduced coastal eutrophication.
d. Distribution of Health Benefits Among Different Populations
    EPA also estimated the PM2.5 mortality risks according 
to race, income, and educational attainment before and after 
implementation of this Transport Rule. We used premature mortality for 
this analysis for several reasons: It is the most serious health effect 
of exposure to PM2.5, and EPA has access to nationwide 
incidence and demographic data at an appropriate scale to conduct this 
type of analysis. EPA included educational attainment in this 
assessment because research on the effects of PM2.5 has 
found that educational attainment is inversely related to the risk of 
all-cause mortality. That is, populations with lower levels of 
education (in particular, less than grade 12) experience higher rates 
of PM2.5 mortality. Krewski and colleagues \126\ note in 
their analysis of this relationship that the level of education 
attainment is likely to be a surrogate for the effects of complex 
socioeconomic processes (including factors such as race and income) on 
mortality.
---------------------------------------------------------------------------

    \126\ Krewski D, Jerrett M, Burnett RT, Ma R, Hughes E, Shi Y, 
Turner C, Pope CA, Thurston G, Calle EE, Thunt MJ. Extended follow-
up and spatial analysis of the American Cancer Society study linking 
particulate air pollution and mortality. HEI Research Report, 140, 
2009; Health Effects Institute, Boston, MA.
---------------------------------------------------------------------------

    In the first step of the analysis, we estimated baseline (2005) 
PM2.5 mortality risk by race (White, Black, Asian, Native 
American) among people living in the counties with the highest (top 5 
percent) PM2.5 mortality risk. We

[[Page 48351]]

also estimated baseline PM2.5 mortality risk by race among 
people living in the counties with both the highest (top 5 percent) 
poverty rate and the highest (top 5 percent) PM2.5 mortality 
risk in 2005. And, we estimated the baseline (2005) PM2.5 
mortality risk by educational attainment for people living in the 
highest PM2.5 mortality risk counties. In the second step, 
we estimated the changes in risk for different races among the people 
living in these ``high-risk'' and ``high risk and high-poverty'' 
counties resulting from implementation of other existing rules in 2014 
and from implementation of just the Transport Rule in 2014. Finally, in 
the third step, we compared the effects of the Transport Rule by race 
in the high-risk and high risk/high-poverty counties with the effects 
on people (by race) living in all other counties.
    In 2005, people living in the highest-risk counties and in the high 
risk/high poverty counties had substantially greater risks of 
PM2.5-related death than people living in the other 95 
percent of counties. This was true regardless of race: The difference 
among races in both groups of counties was very small and dwarfed by 
the large difference between the two groups of counties for all races. 
For educational attainment, in contrast, our analysis found that people 
with less than high school education had significantly greater risks 
from PM2.5 mortality than people with a greater than high 
school education. This was especially true for people living in the 
highest-risk counties, but also held true for people living in all 
other counties. In summary, in 2005, having less than a high school or 
high school education, living in one of the poorest counties, and 
living in a high air pollution risk county are associated with higher 
PM2.5 mortality risk; race is not.
    Our analysis of the effects of the Transport Rule on this 
underlying exposure pattern finds that the rule will significantly 
reduce the PM2.5 mortality among all populations of 
different races living throughout the U.S. compared to both 2005 and 
2014 pre-rule (i.e., base case) levels. No group will experience any 
increases in PM2.5 related deaths as a result of 
implementing the Transport Rule.
    The analysis indicates that the populations with the largest 
improvement (i.e., largest decline) in PM2.5 mortality risk 
as a result of the Transport Rule in 2014 (compared to the base case in 
2014) are people living in the highest-risk counties. Among these 
counties, the largest improvements are for people with less than high 
school or high school education. These reductions in risk within the 
highest-risk counties, as well as the reductions in risk within the 
other 95 percent of counties, are distributed among populations of 
different races fairly evenly. Therefore, there is no indication that 
people of particular race receive a greater benefit (or smaller 
benefit) than others.
    The analysis indicates that people living in the high risk/high 
poverty counties will experience larger improvements in risk from the 
Transport Rule compared to their counterparts in the other counties. 
This result suggests that the Transport Rule is providing the greatest 
risk reduction improvements among counties containing the poorest, and 
highest risk, populations. There is also little difference in the 
improvement in risk among races; in other words, people in the high 
risk/high poverty counties experience the same improvement in risk 
regardless of race.
    The analysis also indicates that this rule, in conjunction with the 
implementation of existing or proposed rules (e.g., the proposed 
Mercury and Air Toxics Standards), will reduce the disparity in risk 
between the highest-risk counties and the other 95 percent of counties 
for all races and educational levels. In addition, implementation of 
this Transport Rule and other rules will, together, reduce risks in the 
poorest and highest risk counties to the approximate level of risk for 
the rest of the counties before implementation. This analysis is 
presented in more detail in the RIA for this rule which is available in 
the rule docket No. EPA-HQ-OAR-2009-0491 and from the main EPA webpage 
for the rule at http://www.epa.gov/airtransport.
3. Meaningful Public Participation
    EPA defines ``Environmental Justice'' to include meaningful 
involvement of all people regardless of race, color, national origin, 
or income with respect to the development, implementation, and 
enforcement of environmental laws, regulations, and policies. To 
promote meaningful involvement, EPA developed a communication and 
outreach strategy to ensure that interested communities had access to 
the proposed Transport Rule, were aware of its content, and had an 
opportunity to comment during the comment period. These efforts are 
summarized below.
    As EPA began considering approaches to address the court remand of 
the 2005 Clean Air Interstate Rule, long before the rule was proposed, 
the agency also began gathering input from a large range of 
stakeholders. In the spring of 2009, EPA held a series of listening 
sessions to gather information and perspectives from stakeholders prior 
to the formal start of the rulemaking process. These stakeholders 
included a number of environmental groups who requested that EPA 
consider several potential environmental justice issues during 
development of this rule. In addition, many environmental justice 
organizations were represented at a November 2009 EPA-Health and Human 
Services White House Stakeholder Briefing titled, ``The Public Health 
Benefits of Energy Reform'' in which EPA discussed our intention to 
propose this rule in the spring of 2010 and participants had the 
opportunity to respond. Finally, EPA notified Indian Tribes of our 
intent to propose this rule in the fall of 2009 during a regularly 
scheduled meeting to update the National Tribal Air Association members 
of upcoming EPA policies and regulations and to receive input from them 
on the effects of these efforts in Indian country. These were not 
opportunities for stakeholders to comment on the specifics of the 
proposal, as they took place prior to its development, but they 
provided valuable information that EPA used in developing the proposal.
    Just after the rule was proposed in July 2010, EPA presented a 
summary of information related to the proposed Transport Rule at the 
National Environmental Justice Advisory Council (NEJAC) meeting in 
Washington, DC, and responded to questions from NEJAC members regarding 
the proposed rule. EPA also solicited suggestions for how to engage 
environmental justice communities during the rule comment period.
    During the public comment period, EPA held public hearings in 
Chicago, Philadelphia, and Atlanta. Each hearing was advertised by EPA 
through a variety of products targeted to general audiences (e.g., fact 
sheets, press release, slide presentation, etc.); on EPA's 
environmental justice listserve; and by non-profit organizations (e.g., 
American Lung Association). The public hearings were held in public 
buildings (i.e., no formal identification required to enter or to 
speak) and were open for 11 hours (9 a.m.-8 p.m.) to accommodate 
commenters with various work schedules. All three hearings were well-
attended by members of the general public. During hearing breaks, EPA 
staff spent time talking with individuals, including those representing 
environmental justice organizations or communities, to understand their 
perspectives in greater detail. As noted above, several commenters at 
each hearing made comments related to the need to protect communities 
living near power plants and the most vulnerable

[[Page 48352]]

individuals. Some of these commenters specifically mentioned 
environmental justice; others mentioned issues often of concern to 
environmental justice communities, such as hot spots, interest in 
additional emission reductions and greater environmental protection, 
and concern over the effects of the rule on the most sensitive and 
vulnerable populations.
    In September 2010, during the comment period, EPA held a webinar 
for EJ communities on the proposed Transport Rule. A presentation 
tailored for an audience of environmental justice, community, and 
tribal representatives was specifically designed for this webinar. It 
was sent to registered participants beforehand and put on the Transport 
Rule webpage, where it remains posted. The presentation included both 
information on the context of the rule, plain language information 
describing the rule itself, and directions on how to comment on the 
rule.
    EPA staff made a short presentation and answered questions about 
the Transport Rule on a standing bi-monthly community conference call 
targeted to environmental justice and tribal representatives and 
organizations. In addition, at the fall 2010 NEJAC meeting in Kansas 
City, Missouri, EPA provided details of the proposed Transport Rule as 
part of a larger discussion of a sector-based approach to utility 
regulation.
    Regarding tribal consultation, EPA sent letters to all 565 
federally-recognized Tribes in the country offering consultation on the 
proposed Transport Rule. In addition, the January 7 NODA on allowance 
allocation methodologies specifically requested comment on allocating 
allowances to new units in Indian Country. EPA held two consultation 
and information-sharing calls with 16 interested Tribes in late January 
and early February 2011. Tribes participating on these consultation and 
information calls provided comments on the proposed rule and the 
allowance allocation NODA. As noted above, this additional input from 
the consultation process was taken into account in the development of 
the final rule. See Section XII.F for more information on tribal 
consultation.
4. Summary
    EPA believes that the vast majority of communities and individuals 
in areas covered by this rule, including numerous low-income, minority, 
and tribal individuals and communities in both rural areas and inner 
cities in the eastern and central U.S., will see significant 
improvements in air quality and resulting improvements in health. EPA's 
assessment of the effects of the proposed and final Transport Rules on 
these communities included: (a) The structure of the rule and responses 
to comments received on issues specific to these communities; (b) 
expected SO2 and NOX emission reductions; (c) 
expected PM2.5 and ozone air quality improvements; (d) 
expected health benefits, including asthma and other health effects of 
particular concern for environmental justice communities; and (e) a 
quantitative assessment of the expected socioeconomic distribution of a 
key health benefit (reduction in premature mortality). All of these 
analyses indicate large health and environmental benefits for these 
communities; none shows evidence of adverse effects. As a result, EPA 
concludes that we do not expect disproportionately high and adverse 
human health or environmental effects on minority, low-income, or 
tribal populations in the United States as a result of implementing 
this final Transport Rule.

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. EPA will submit a report containing this rule and other 
required information to the U.S. Senate, the U.S. House of 
Representatives, and the Comptroller General of the United States prior 
to publication of the rule in the Federal Register. A major rule cannot 
take effect until 60 days after it is published in the Federal 
Register. This action is a ``major rule'' as defined by 5 U.S.C. 
804(2). This rule will be effective October 7, 2011.

L. Judicial Review

    Petitions for judicial review of this action must be filed in the 
United States Court of Appeals for the District of Columbia Circuit by 
October 7, 2011. Section 307(b)(1) of the CAA indicates which Federal 
Courts of Appeal have venue for petitions of review of final actions by 
EPA. This section provides, in part, that petitions for review must be 
filed in the Court of Appeals for the District of Columbia Circuit if 
(i) the agency action consists of ``nationally applicable regulations 
promulgated, or final action taken, by the Administrator,'' or (ii) 
such action is locally or regionally applicable, if ``such action is 
based on a determination of nationwide scope or effect and if in taking 
such action the Administrator finds and publishes that such action is 
based on such a determination.''
    Any final action related to the Transport Rule is ``nationally 
applicable'' within the meaning of section 307(b)(1). Through this 
rule, EPA interprets section 110 of the CAA, a provision which has 
nationwide applicability. In addition, the Transport Rule applies to 27 
States. The Transport Rule is also based on a common core of factual 
findings and analyses concerning the transport of pollutants between 
the different states subject to it. For these reasons, the 
Administrator also is determining that any final action regarding the 
Transport Rule is of nationwide scope and effect for purposes of 
section 307(b)(1). Thus, pursuant to section 307(b) any petitions for 
review of final actions regarding the Transport Rule 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.
    Filing a petition for reconsideration of this action does not 
affect the finality of this rule for the purposes of judicial review 
nor does it extend the time within which a petition for judicial review 
may be filed and shall not postpone the effectiveness of such rule or 
action. In addition, pursuant to CAA section 307(b)(2) this action may 
not be challenged later in proceedings to enforce its requirements.
    In addition, this action is subject to the provisions of section 
307(d). CAA section 307(d)(1)(B) provides that section 307(d) applies 
to, among other things, to ``the promulgation or revision of an 
implementation plan by the Administrator under CAA section 110(c)'' (42 
U.S.C. 7407(d)(1)(B)). The Agency has complied with procedural 
requirements of CAA section 307(d) during the course of this 
rulemaking.

List of Subjects

40 CFR Part 51

    Administrative practice and procedure, Air pollution control, 
Incorporation by reference, Intergovernmental relations, Nitrogen 
oxides, Ozone, Particulate matter, Regional haze, Reporting and 
recordkeeping requirements, Sulfur dioxide.

40 CFR Part 52

    Administrative practice and procedure, Air pollution control, 
Incorporation by reference, Intergovernmental relations, Nitrogen

[[Page 48353]]

oxides, Ozone, Particulate matter, Regional haze, Reporting and 
recordkeeping requirements, Sulfur dioxide.

40 CFR Part 72

    Acid rain, Administrative practice and procedure, Air pollution 
control, Electric utilities, Incorporation by reference, 
Intergovernmental relations, Nitrogen oxides, Reporting and 
recordkeeping requirements, Sulfur dioxide.

40 CFR Part 78

    Acid rain, Administrative practice and procedure, Air pollution 
control, Electric utilities, Intergovernmental relations, Nitrogen 
oxides, Reporting and recordkeeping requirements, Sulfur dioxide.

40 CFR Part 97

    Administrative practice and procedure, Air pollution control, 
Electric utilities, Nitrogen oxides, Reporting and recordkeeping 
requirements, Sulfur dioxide.

    Dated: July 6, 2011.
Lisa P. Jackson,
Administrator.

    For the reasons set forth in the preamble, parts 51, 52, 72, 78, 
and 97 of chapter I of title 40 of the Code of Federal Regulations are 
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. In Sec.  51.121 paragraph (r)(2) is amended by removing the words 
``Sec.  51.123(bb)'' and adding, in their place, the words ``Sec.  
51.123(bb) with regard to an ozone season that occurs before January 1, 
2012''.

0
3. Section 51.123 is amended by adding a new paragraph (ff) 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.

* * * * *
    (ff) Notwithstanding any provisions of paragraphs (a) through (ee) 
of this section, subparts AA through II and AAAA through IIII of part 
96 of this chapter, subparts AA through II and AAAA through IIII of 
part 97 of this chapter, and any State's SIP to the contrary:
    (1) With regard to any control period that begins after December 
31, 2011, the Administrator:
    (i) Rescinds the determination in paragraph (a) of this section 
that the States identified in paragraph (c) of this section must submit 
a SIP revision with respect to the fine particles (PM2.5) 
NAAQS and the 8-hour ozone NAAQS meeting the requirements of paragraphs 
(b) through (ee) of this section; and
    (ii) Will not carry out any of the functions set forth for the 
Administrator in subparts AA through II and AAAA through IIII of part 
96 of this chapter, subparts AA through II and AAAA through IIII of 
part 97 of this chapter, or in any emissions trading program provisions 
in a State's SIP approved under this section;
    (2) The Administrator will not deduct for excess emissions any CAIR 
NOX allowances or CAIR NOX Ozone Season 
allowances allocated for 2012 or any year thereafter;
    (3) By November 7, 2011, the Administrator will remove from the 
CAIR NOX Allowance Tracking System accounts all CAIR 
NOX allowances allocated for a control period in 2012 and 
any subsequent year, and, thereafter, no holding or surrender of CAIR 
NOX allowances will be required with regard to emissions or 
excess emissions for such control periods; and
    (4) By November 7, 2011, the Administrator will remove from the 
CAIR NOX Ozone Season Allowance Tracking System accounts all 
CAIR NOX Ozone Season allowances allocated for a control 
period in 2012 and any subsequent year, and, thereafter, no holding or 
surrender of CAIR NOX Ozone Season allowances will be 
required with regard to emissions or excess emissions for such control 
periods.

0
4. Section 51.124 is amended by adding a new paragraph (s) 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.

* * * * *
    (s) Notwithstanding any provisions of paragraphs (a) through (r) of 
this section, subparts AAA through III of part 96 of this chapter, 
subparts AAA through III of part 97 of this chapter, and any State's 
SIP to the contrary:
    (1) With regard to any control period that begins after December 
31, 2011, the Administrator:
    (i) Rescinds the determination in paragraph (a) of this section 
that the States identified in paragraph (c) of this section must submit 
a SIP revision with respect to the fine particles (PM2.5) 
NAAQS meeting the requirements of paragraphs (b) through (r) of this 
section; and
    (ii) Will not carry out any of the functions set forth for the 
Administrator in subparts AAA through III of part 96 of this chapter, 
subparts AAA through III of part 97 of this chapter, or in any 
emissions trading program in a State's SIP approved under this section; 
and
    (2) The Administrator will not deduct for excess emissions any CAIR 
SO2 allowances allocated for 2012 or any year thereafter.

Sec.  51.125  [Reserved]

0
5. Section 51.125 is removed and reserved.

PART 52--[AMENDED]

0
6. The authority citation for part 52 continues to read as follows:

    Authority:  42 U.S.C. 7401, et seq.

Subpart A--General Provisions

0
7. Section 52.35 is amended by adding a new paragraph (f) to read as 
follows:

Sec.  52.35  What are the requirements of the Federal Implementation 
Plans (FIPs) for the Clean Air Interstate Rule (CAIR) relating to 
emissions of nitrogen oxides?

* * * * *
    (f) Notwithstanding any provisions of paragraphs (a) through (d) of 
this section, subparts AA through II and AAAA through IIII of part 97 
of this chapter, and any State's SIP to the contrary:
    (1) With regard to any control period that begins after December 
31, 2011,
    (i) The provisions in paragraphs (a) through (d) of this section 
relating to NOX annual or ozone season emissions shall not 
be applicable; and
    (ii) The Administrator will not carry out any of the functions set 
forth for the Administrator in subparts AA through II and AAAA through 
IIII of part 97 of this chapter;
    (2) The Administrator will not deduct for excess emissions any CAIR 
NOX allowances or CAIR NOX Ozone Season 
allowances allocated for 2012 or any year thereafter;
    (3) By November 7, 2011, the Administrator will remove from the 
CAIR NOX Allowance Tracking System accounts all CAIR 
NOX allowances allocated for a control period in 2012 and 
any subsequent year, and, thereafter, no holding or surrender of CAIR 
NOX allowances will be required with regard to emissions or 
excess emissions for such control periods; and

[[Page 48354]]

    (4) By November 7, 2011, the Administrator will remove from the 
CAIR NOX Ozone Season Allowance Tracking System accounts all 
CAIR NOX Ozone Season allowances allocated for a control 
period in 2012 and any subsequent year, and, thereafter, no holding or 
surrender of CAIR NOX allowances will be required with 
regard to emissions or excess emissions for such control periods.

0
8. Section 52.36 is amended by adding a new paragraph (e) to read as 
follows:

Sec.  52.36  What are the requirements of the Federal Implementation 
Plans (FIPs) for the Clean Air Interstate Rule (CAIR) relating to 
emissions of sulfur dioxide?

* * * * *
    (e) Notwithstanding any provisions of paragraphs (a) through (c) of 
this section, subparts AAA through III of part 97 of this chapter and 
any State's SIP to the contrary:
    (1) With regard to any control period that begins after December 
31, 2011,
    (i) The provisions of paragraphs (a) through (e) of this section 
relating to SO2 emissions shall not be applicable; and
    (ii) The Administrator will not carry out any of the functions set 
forth for the Administrator in subparts AAA through III of part 97 of 
this chapter; and
    (2) The Administrator will not deduct for excess emissions any CAIR 
SO2 allowances allocated for 2012 or any year thereafter.

0
9. Sections Sec. Sec.  52.38 and 52.39 are added to subpart A to read 
as follows:

Sec.  52.38  What are the requirements of the Federal Implementation 
Plans (FIPs) under the Transport Rule (TR) relating to emissions of 
nitrogen oxides?

    (a)(1) The TR NOX Annual Trading Program provisions set 
forth in subpart AAAAA of part 97 of this chapter constitute the TR 
Federal Implementation Plan provisions that relate to annual emissions 
of nitrogen oxides (NOX).
    (2) The provisions of subpart AAAAA of part 97 of this chapter 
apply to the sources in the following States and Indian country located 
within the borders of such States: Alabama, Georgia, Illinois, Indiana, 
Iowa, Kansas, Kentucky, Maryland, Michigan, Minnesota, Missouri, 
Nebraska, New Jersey, New York, North Carolina, Ohio, Pennsylvania, 
South Carolina, Tennessee, Texas, Virginia, West Virginia, and 
Wisconsin.
    (3) Notwithstanding the provisions of paragraph (a)(1) of this 
section, a State listed in paragraph (a)(2) of this section may adopt 
and include in a SIP revision, and the Administrator will approve, as 
TR NOX Annual allowance allocation provisions replacing the 
provisions in Sec.  97.411(a) of this chapter with regard to the State 
and the control period in 2013, a list of TR NOX Annual 
units and the amount of TR NOX Annual allowances allocated 
to each unit on such list, provided that the list of units and 
allocations meets the following requirements:
    (i) All of the units on the list must be units that are in the 
State and commenced commercial operation before January 1, 2010;
    (ii) The total amount of TR NOX Annual allowance 
allocations on the list must not exceed the amount, under Sec.  
97.410(a) of this chapter for the State and the control period in 2013, 
of TR NOX Annual trading budget minus the sum of the new 
unit set-aside and Indian country new unit set-aside;
    (iii) The list must be submitted electronically in a format 
specified by the Administrator; and
    (iv) The SIP revision must not provide for any change in the units 
and allocations on the list after approval of the SIP revision by the 
Administrator and must not provide for any change in any allocation 
determined and recorded by the Administrator under subpart AAAAA of 
part 97 of this chapter;
    (v) Provided that:
    (A) By October 17, 2011, the State must notify the Administrator 
electronically in a format specified by the Administrator of the 
State's intent to submit to the Administrator a complete SIP revision 
meeting the requirements of paragraph (a)(3)(i) through (iv) of this 
section by April 1, 2012; and
    (B) The State must submit to the Administrator a complete SIP 
revision described in paragraph (a)(3)(v)(A) of this section by April 
1, 2012.
    (4) Notwithstanding the provisions of paragraph (a)(1) of this 
section, a State listed in paragraph (a)(2) of this section may adopt 
and include in a SIP revision, and the Administrator will approve, 
regulations revising subpart AAAAA of part 97 of this chapter as 
follows and not making any other substantive revisions of that subpart:
    (i) The State may adopt, as TR NOX Annual allowance 
allocation or auction provisions replacing the provisions in Sec. Sec.  
97.411(a) and (b)(1) and 97.412(a) of this chapter with regard to the 
State and the control period in 2014 or any subsequent year, any 
methodology under which the State or the permitting authority allocates 
or auctions TR NOX Annual allowances, and may adopt, in 
addition to the definitions in Sec.  97.402 of this chapter, one or 
more definitions that shall apply only to terms as used in the adopted 
TR NOX Annual allowance allocation or auction provisions, if 
such methodology--
    (A) Requires the State or the permitting authority to allocate and, 
if applicable, auction a total amount of TR NOX Annual 
allowances for any such control period not exceeding the amount, under 
Sec. Sec.  97.410(a) and 97.421 of this chapter for the State and such 
control period, of the TR NOX Annual trading budget minus 
the sum of the Indian country new unit set-aside and the amount of any 
TR NOX Annual allowances already allocated and recorded by 
the Administrator.
    (B) Requires, to the extent the State adopts provisions for 
allocations or auctions of TR NOX Annual allowances for any 
such control period to any TR NOX Annual units covered by 
Sec.  97.411(a) of this chapter, that the State or the permitting 
authority submit such allocations or the results of such auctions for 
such control period (except allocations or results of auctions to such 
units of TR NOX Annual allowances remaining in a set-aside 
after completion of the allocations or auctions for which the set-aside 
was created) to the Administrator no later than the following dates:

------------------------------------------------------------------------
  Year of the control period for which TR    Deadline for submission of
  NOX annual allowances are allocated or       allocations or auction
                 auctioned                    results to  administrator
------------------------------------------------------------------------
2014......................................  June 1, 2013.
2015......................................  June 1, 2013.
2016......................................  June 1, 2014.
2017......................................  June 1, 2014.
2018......................................  June 1, 2015.
2019......................................  June 1, 2015.
2020 and any year thereafter..............  June 1 of the fourth year
                                             before the year of the
                                             control period.
------------------------------------------------------------------------

     (C) Requires, to the extent the State adopts provisions for 
allocations or auctions of TR NOX Annual allowances for any 
such control period to any TR NOX Annual units covered by 
Sec. Sec.  97.411(b)(1) and 97.412(a) of this chapter, that the State 
or the permitting authority submit such allocations or the results of 
such auctions (except allocations or results of auctions to such units 
of TR NOX Annual allowances remaining in a set-aside after 
completion of the allocations or auctions for which the set-aside was 
created) to the Administrator by July 1 of the year of such control 
period.
    (D) Does not provide for any change, after the submission deadlines 
in paragraphs (a)(4)(i)(B) and (C) of this section, in the allocations 
submitted to the Administrator by such deadlines and does not provide 
for any change in

[[Page 48355]]

any allocation determined and recorded by the Administrator under 
subpart AAAAA of part 97 of this chapter;
    (ii) Provided that the State must submit a complete SIP revision 
meeting the requirements of paragraph (a)(4)(i) of this section by 
December 1 of the year before the year of the deadlines for submission 
of allocations or auction results under paragraphs (a)(4)(i)(B) and (C) 
of this section for the first control period for which the State wants 
to make allocations or hold an auction under paragraph (a)(4)(i) of 
this section.
    (5) Notwithstanding the provisions of paragraph (a)(1) of this 
section, a State listed in paragraph (a)(2) of this section may adopt 
and include in a SIP revision, and the Administrator will approve, as 
correcting in whole or in part, as appropriate, the deficiency in the 
SIP that is the basis for the TR Federal Implementation Plan set forth 
in paragraphs (a)(1) through (4) of this section, regulations that are 
substantively identical to the provisions of the TR NOX 
Annual Trading Program set forth in Sec. Sec.  97.402 through 97.435 of 
this chapter, except that the SIP revision:
    (i) May adopt, as TR NOX Annual allowance allocation or 
auction provisions replacing the provisions in Sec. Sec.  97.411(a) and 
(b)(1) and 97.412(a) of this chapter with regard to the State and the 
control period in 2014 or any subsequent year, any methodology under 
which the State or the permitting authority allocates or auctions TR 
NOX Annual allowances and that--
    (A) Requires the State or the permitting authority to allocate and, 
if applicable, auction a total amount of TR NOX Annual 
allowances for any such control period not exceeding the amount, under 
Sec. Sec.  97.410(a) and 97.421 of this chapter for the State and such 
control period, of the TR NOX Annual trading budget minus 
the sum of the Indian country new unit set-aside and the amount of any 
TR NOX Annual allowances already allocated and recorded by 
the Administrator.
    (B) Requires, to the extent the State adopts provisions for 
allocations or auctions of TR NOX Annual allowances for any 
such control period to any TR NOX Annual units covered by 
Sec.  97.411(a) of this chapter, that the State or the permitting 
authority submit such allocations or the results of such auctions for 
such control period (except allocations or results of auctions to such 
units of TR NOX Annual allowances remaining in a set-aside 
after completion of the allocations or auctions for which the set-aside 
was created) to the Administrator no later than the following dates:

------------------------------------------------------------------------
  Year of the control period for which TR    Deadline for submission of
  NOX annual allowances are allocated or       allocations or auction
                 auctioned                    results to  administrator
------------------------------------------------------------------------
2014......................................  June 1, 2013.
2015......................................  June 1, 2013.
2016......................................  June 1, 2014.
2017......................................  June 1, 2014.
2018......................................  June 1, 2015.
2019......................................  June 1, 2015.
2020 and any year thereafter..............  June 1 of the fourth year
                                             before the year of the
                                             control period.
------------------------------------------------------------------------

     (C) Requires, to the extent the State adopts provisions for 
allocations or auctions of TR NOX Annual allowances for any 
such control period to any TR NOX Annual units covered by 
Sec. Sec.  97.411(b)(1) and 97.412(a) of this chapter, that the State 
or the permitting authority submit such allocations or the results of 
such auctions (except allocations or results of auctions to such units 
of TR NOX Annual allowances remaining in a set-aside after 
completion of the allocations or auctions for which the set-aside was 
created) to the Administrator by July 1 of the year of such control 
period.
    (D) Does not provide for any change, after the submission deadlines 
in paragraphs (a)(5)(i)(B) and (C) of this section, in the allocations 
submitted to the Administrator by such deadlines and does not provide 
for any change in any allocation determined and recorded by the 
Administrator under subpart AAAAA of part 97 of this chapter;
    (ii) May adopt, in addition to the definitions in Sec.  97.402 of 
this chapter, one or more definitions that shall apply only to terms as 
used in the TR NOX Annual allowance allocation or auction 
provisions adopted under paragraph (a)(5)(i) of this section;
    (iii) May substitute the name of the State for the term ``State'' 
as used in subpart AAAAA of part 97 of this chapter, to the extent the 
Administrator determines that such substitutions do not make 
substantive changes in the provisions in Sec. Sec.  97.402 through 
97.435 of this chapter; and
    (iv) Must not include any of the references to, or requirements 
imposed on, any unit in Indian country within the borders of the State 
in the provisions in Sec. Sec.  97.402 through 97.435 of this chapter 
and must not include the provisions in Sec. Sec.  97.411(b)(2) and 
97.412(b), all of which provisions will continue to apply under the 
portion of the TR Federal Implementation Plan that is not replaced by 
the SIP revision;
    (v) Provided that, if and when any covered unit is located in 
Indian country within the borders of the State, the Administrator may 
modify his or her approval of the SIP revision to exclude the 
provisions in Sec. Sec.  97.402 (definitions of ``common designated 
representative'', ``common designated representative's assurance 
level'', and ``common designated representative's share''), 
97.406(c)(2), 97.425, and the portions of other provisions referencing 
these sections and may modify the portion of the TR Federal 
Implementation Plan that is not replaced by the SIP revision to include 
these provisions;
    (vi) Provided that the State must submit a complete SIP revision 
meeting the requirements of paragraphs (a)(5)(i) through (iv) of this 
section by December 1 of the year before the year of the deadlines for 
submission of allocations or auction results under paragraphs 
(a)(5)(i)(B) and (C) of this section applicable to the first control 
period for which the State wants to make allocations or hold an auction 
under paragraphs (a)(5)(i) and (ii) of this section.
    (6) Following promulgation of an approval by the Administrator of a 
State's SIP revision as correcting in whole or in part, as appropriate, 
the SIP's deficiency that is the basis for the TR Federal 
Implementation Plan described in paragraphs (a)(1) through (5) of this 
section, the provisions of paragraph (a)(2) of this section will no 
longer apply to the sources in the State, unless the Administrator's 
approval of the SIP revision is partial or conditional, and will 
continue to apply to sources in any Indian country within the borders 
of the State.
    (7) Notwithstanding the provisions of paragraph (a)(6) of this 
section, if, at the time of such approval of the State's SIP revision, 
the Administrator has already started recording any allocations of TR 
NOX Annual allowances under subpart AAAAA of part 97 of this 
chapter to units in a State for a control period in any year, the 
provisions of subpart AAAAA of part 97 of this chapter authorizing the 
Administrator to complete the allocation and recordation of TR 
NOX Annual allowances to units in the State for each such 
control period shall continue to apply, unless provided otherwise by 
such approval of the State's SIP revision.
    (b)(1) The TR NOX Ozone Season Trading Program 
provisions set forth in part 97 of this chapter constitute the TR 
Federal Implementation Plan provisions that relate to emissions of 
NOX during the ozone season, defined as May 1 through 
September 30 of a calendar year.
    (2) The provisions of subpart BBBBB of part 97 of this chapter 
apply to

[[Page 48356]]

sources in each of the following States and Indian country located 
within the borders of such States: Alabama, Arkansas, Florida, Georgia, 
Illinois, Indiana, Kentucky, Louisiana, Maryland, Mississippi, New 
Jersey, New York, North Carolina, Ohio, Pennsylvania, South Carolina, 
Tennessee, Texas, Virginia, and West Virginia.
    (3) Notwithstanding the provisions of paragraph (b)(1) of this 
section, a State listed in paragraph (b)(2) of this section may adopt 
and include in a SIP revision, and the Administrator will approve, as 
TR NOX Ozone Season allowance allocation provisions 
replacing the provisions in Sec.  97.511(a) of this chapter with regard 
to the State and the control period in 2013, a list of TR 
NOX Ozone Season units and the amount of TR NOX 
Ozone Season allowances allocated to each unit on such list, provided 
that the list of units and allocations meets the following 
requirements:
    (i) All of the units on the list must be units that are in the 
State and commenced commercial operation before January 1, 2010;
    (ii) The total amount of TR NOX Ozone Season allowance 
allocations on the list must not exceed the amount, under Sec.  
97.510(a) of this chapter for the State and the control period in 2013, 
of TR NOX Ozone Season trading budget minus the sum of the 
new unit set-aside and Indian country new unit set-aside;
    (iii) The list must be submitted electronically in a format 
specified by the Administrator; and
    (iv) The SIP revision must not provide for any change in the units 
and allocations on the list after approval of the SIP revision by the 
Administrator and must not provide for any change in any allocation 
determined and recorded by the Administrator under subpart BBBBB of 
part 97 of this chapter;
    (v) Provided that:
    (A) By October 17, 2011, the State must notify the Administrator 
electronically in a format specified by the Administrator of the 
State's intent to submit to the Administrator a complete SIP revision 
meeting the requirements of paragraph (b)(3)(i) through (iv) of this 
section by April 1, 2012; and
    (B) The State must submit to the Administrator a complete SIP 
revision described in paragraph (b)(3)(v)(A) of this section by April 
1, 2012.
    (4) Notwithstanding the provisions of paragraph (b)(1) of this 
section, a State listed in paragraph (b)(2) of this section may adopt 
and include in a SIP revision, and the Administrator will approve, 
regulations revising subpart BBBBB of part 97 of this chapter as 
follows and not making any other substantive revisions of that subpart:
    (i) The State may adopt, as applicability provisions replacing the 
provisions in Sec. Sec.  97.504(a)(1) and (2) of this chapter, 
provisions substantively identical to those provisions, except that the 
words ``more than 25 MWe'' are replaced, whenever such words appear, by 
words specifying a uniform lower limit on the amount of megawatts that 
is not greater than the amount specified by the words ``more than 25 
MWe'' and is not less than the amount specified by the words ``15 MWe 
or more''; or
    (ii) The State may adopt, as TR NOX Ozone Season 
allowance allocation or auction provisions replacing the provisions in 
Sec. Sec.  97.511(a) and (b)(1) and 97.512(a) of this chapter with 
regard to the control period in 2014 or any subsequent year, any 
methodology under which the State or the permitting authority allocates 
or auctions TR NOX Ozone Season allowances, and may adopt, 
in addition to the definitions in Sec.  97.502 of this chapter, one or 
more definitions that shall apply only to terms as used in the adopted 
TR NOX Ozone Season allowance allocation or auction 
provisions, if such methodology--
    (A) Requires the State or the permitting authority to allocate and, 
if applicable, auction a total amount of TR NOX Ozone Season 
allowances for any such control period not exceeding the amount, under 
Sec. Sec.  97.510(a) and 97.521 of this chapter for the State and such 
control period, of the TR NOX Ozone Season trading budget 
minus the sum of the Indian country new unit set-aside and the amount 
of any TR NOX Ozone Season allowances already allocated and 
recorded by the Administrator.
    (B) Requires, to the extent the State adopts provisions for 
allocations or auctions of TR NOX Ozone Season allowances 
for any such control period to any TR NOX Ozone Season units 
covered by Sec.  97.511(a) of this chapter, that the State or the 
permitting authority submit such allocations or the results of such 
auctions for such control period (except allocations or results of 
auctions to such units of TR NOX Ozone Season allowances 
remaining in a set-aside after completion of the allocations or 
auctions for which the set-aside was created) to the Administrator no 
later than the following dates:

------------------------------------------------------------------------
  Year of the control period for which TR    Deadline for submission of
 NOX Ozone Season allowances are allocated     allocations or auction
               or auctioned                   results to  administrator
------------------------------------------------------------------------
2014......................................  June 1, 2013.
2015......................................  June 1, 2013.
2016......................................  June 1, 2014.
2017......................................  June 1, 2014.
2018......................................  June 1, 2015.
2019......................................  June 1, 2015.
2020 and any year thereafter..............  June 1 of the fourth year
                                             before the year of the
                                             control period.
------------------------------------------------------------------------

     (C) Requires, to the extent the State adopts provisions for 
allocations or auctions of TR NOX Ozone Season allowances 
for any such control period to any TR NOX Ozone Season units 
covered by Sec. Sec.  97.511(b)(1) and 97.512(a) of this chapter, that 
the State or the permitting authority submit such allocations or the 
results of such auctions (except allocations or results of auctions to 
such units of TR NOX Ozone Season allowances remaining in a 
set-aside after completion of the allocations or auctions for which the 
set-aside was created) to the Administrator by July 1 of the year of 
such control period.
    (D) Does not provide for any change, after the submission deadlines 
in paragraphs (b)(4)(ii)(B) and (C) of this section, in the allocations 
submitted to the Administrator by such deadlines and does not provide 
for any change in any allocation determined and recorded by the 
Administrator under subpart BBBBB of part 97 of this chapter;
    (iii) Provided that the State must submit a complete SIP revision 
meeting the requirements of paragraph (b)(4)(i) or (ii) of this section 
by December 1 of the year before the year of the deadlines for 
submission of allocations or auction results under paragraphs 
(b)(4)(ii)(B) and (C) of this section applicable to the first control 
period for which the State wants to replace the applicability 
provisions, make allocations, or hold an auction under paragraph 
(b)(4)(i) or (ii) of this section.
    (5) Notwithstanding the provisions of paragraph (b)(1) of this 
section, a State listed in paragraph (b)(2) of this section may adopt 
and include in a SIP revision, and the Administrator will approve, as 
correcting in whole or in part, as appropriate, the deficiency in the 
SIP that is the basis for the TR Federal Implementation Plan set forth 
in paragraphs (b)(1) through (4) of this section, regulations that are 
substantively identical to the provisions of the TR NOX 
Ozone Season Trading Program set forth in Sec. Sec.  97.502 through 
97.535 of this chapter, except that the SIP revision:

[[Page 48357]]

    (i) May adopt, as applicability provisions replacing the provisions 
in Sec. Sec.  97.504(a)(1) and (2) of this chapter, provisions 
substantively identical to those provisions, except that the words 
``more than 25 MWe'' are replaced, whenever such words appear, by words 
specifying a uniform lower limit on the amount of megawatts that is not 
greater than the amount specified by the words ``more than 25 MWe'' and 
is not less than the amount specified by the words ``15 MWe or more''; 
or
    (ii) May adopt, as TR NOX Ozone Season allowance 
allocation provisions replacing the provisions in Sec. Sec.  97.511(a) 
and (b)(1) and 97.512(a) of this chapter with regard to the control 
period in 2014 and any subsequent year, any methodology under which the 
State or the permitting authority allocates auctions TR NOX 
Ozone Season allowances and that--
    (A) Requires the State or the permitting authority to allocate and, 
if applicable, auction a total amount of TR NOX Ozone Season 
allowances for any such control period not exceeding the amount, under 
Sec. Sec.  97.510(a) and 97.521 of this chapter for the State and such 
control period, of the TR NOX Ozone Season trading budget 
minus the sum of the Indian country new unit set-aside and the amount 
of any TR NOX Ozone Season allowances already allocated and 
recorded by the Administrator.
    (B) Requires, to the extent the State adopts provisions for 
allocations or auction of TR NOX Ozone Season allowances for 
any such control period to any TR NOX Ozone Season units 
covered by Sec.  97.511(a) of this chapter, that the State or the 
permitting authority submit such allocations or the results of such 
auctions for such control period (except allocations or results of 
auctions to such units of TR NOX Ozone Season allowances 
remaining in a set-aside after completion of the allocations or 
auctions for which the set-aside was created) to the Administrator no 
later than the following dates:

------------------------------------------------------------------------
  Year of the control period for which TR    Deadline for submission of
 NOX Ozone Season allowances are allocated     allocations or auction
               or auctioned                   results to  administrator
------------------------------------------------------------------------
2014......................................  June 1, 2013.
2015......................................  June 1, 2013.
2016......................................  June 1, 2014.
2017......................................  June 1, 2014.
2018......................................  June 1, 2015.
2019......................................  June 1, 2015.
2020 and any year thereafter..............  June 1 of the fourth year
                                             before the year of the
                                             control period.
------------------------------------------------------------------------

     (C) Requires, to the extent the State adopts provisions for 
allocations or auctions of TR NOX Ozone Season allowances 
for any control period to any TR NOX Ozone Season units 
covered by Sec. Sec.  97.511(b)(1) and 97.512(a) of this chapter, that 
the State or the permitting authority submit such allocations or the 
results of such auctions (except allocations or results of auctions to 
such units of TR NOX Ozone Season allowances remaining in a 
set-aside after completion of the allocations or auctions for which the 
set-aside was created) to the Administrator by July 1 of the year of 
such control period.
    (D) Does not provide for any change, after the submission deadlines 
in paragraphs (b)(5)(ii)(B) and (C) of this section, in the allocations 
submitted to the Administrator by such deadlines and does not provide 
for any change in any allocation determined and recorded by the 
Administrator under subpart BBBBB of part 97 of this chapter;
    (iii) May adopt in addition to the definitions in Sec.  97.502 of 
this chapter, one or more definitions that shall apply only to terms as 
used in the TR NOX Ozone Season allowance allocation or 
auction provisions adopted under paragraph (b)(5)(ii) of this section;
    (iv) May substitute the name of the State for the term ``State'' as 
used in subpart BBBBB of part 97 of this chapter, to the extent the 
Administrator determines that such substitutions do not make 
substantive changes in the provisions in Sec. Sec.  97.502 through 
97.535 of this chapter; and
    (v) Must not include any of the references to, or requirements 
imposed on, any unit in Indian country within the borders of the State 
in the provisions in Sec. Sec.  97.502 through 97.535 of this chapter 
and must not include the provisions in Sec. Sec.  97.511(b)(2) and 
97.512(b), all of which provisions will continue to apply under the 
portion of the TR Federal Implementation Plan that is not replaced by 
the SIP revision;
    (vi) Provided that, if and when any covered unit is located in 
Indian country within the borders of the State, the Administrator may 
modify his or her approval of the SIP revision to exclude the 
provisions in Sec. Sec.  97.502 (definitions of ``common designated 
representative'', ``common designated representative's assurance 
level'', and ``common designated representative's share''), 
97.506(c)(2), 97.525, and the portions of other provisions referencing 
these sections and may modify the portion of the TR Federal 
Implementation Plan that is not replaced by the SIP revision to include 
these provisions;
    (vii) Provided that the State must submit a complete SIP revision 
meeting the requirements of paragraph (b)(5)(i) through (v) of this 
section by December 1 of the year before the year of the deadlines for 
submission of allocations or auction results under paragraphs 
(5)(ii)(B) and (C) of this section applicable to the first control 
period for which the State wants to replace the applicability 
provisions, make allocations, or hold an auction under paragraphs 
(b)(5)(ii) and (iii) of this section.
    (6) Following promulgation of an approval by the Administrator of a 
State's SIP revision as correcting in whole or in part, as appropriate, 
the SIP's deficiency that is the basis for the TR Federal 
Implementation Plan set forth in paragraphs (b)(1) through (5) of this 
section, the provisions of paragraph (b)(2) of this section will no 
longer apply to sources in the State, unless the Administrator's 
approval of the SIP revision is partial or conditional, and will 
continue to apply to sources in any Indian country within the borders 
of the State.
    (7) Notwithstanding the provisions of paragraph (b)(6) of this 
section, if, at the time of such approval of the State's SIP revision, 
the Administrator has already started recording any allocations of TR 
NOX Ozone Season allowances under subpart BBBBB of part 97 
of this chapter to units in a State for a control period in any year, 
the provisions of subpart BBBBB of part 97 of this chapter authorizing 
the Administrator to complete the allocation and recordation of TR 
NOX Ozone Season allowances to units in the State for each 
such control period shall continue to apply, unless provided otherwise 
by such approval of the State's SIP revision.

Sec.  52.39  What are the requirements of the Federal Implementation 
Plans (FIPs) for the Transport Rule (TR) relating to emissions of 
sulfur dioxide?

    (a) The TR SO2 Group 1 Trading Program provisions and 
the TR SO2 Group 2 Trading Program provisions set forth 
respectively in subparts CCCCC and DDDDD of part 97 of this chapter 
constitute the TR Federal Implementation Plan provisions that relate to 
emissions of sulfur dioxide (SO2).
    (b) The provisions of subpart CCCCC of part 97 of this chapter 
apply to sources in each of the following States and Indian country 
located within the borders of such States: Illinois, Indiana, Iowa, 
Kentucky, Maryland, Michigan, Missouri, New Jersey, New York, North 
Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and 
Wisconsin.

[[Page 48358]]

    (c) The provisions of subpart DDDDD of part 97 of this chapter 
apply to sources in each of the following States and Indian country 
located within the borders of such States: Alabama, Georgia, Kansas, 
Minnesota, Nebraska, South Carolina, and Texas.
    (d) Notwithstanding the provisions of paragraph (a) of this 
section, a State listed in paragraph (b) of this section may adopt and 
include in a SIP revision, and the Administrator will approve, as TR 
SO2 Group 1 allowance allocation provisions replacing the 
provisions in Sec.  97.611(a) of this chapter with regard to the State 
and the control period in 2013, a list of TR SO2 Group 1 
units and the amount of TR SO2 Group 1 allowances allocated 
to each unit on such list, provided that the list of units and 
allocations meets the following requirements:
    (1) All of the units on the list must be units that are in the 
State and commenced commercial operation before January 1, 2010;
    (2) The total amount of TR SO2 Group 1 allowance 
allocations on the list must not exceed the amount, under Sec.  
97.610(a) of this chapter for the State and the control period in 2013, 
of TR SO2 Group 1 trading budget minus the sum of the new 
unit set-aside and Indian country new unit set-aside;
    (3) The list must be submitted electronically in a format specified 
by the Administrator; and
    (4) The SIP revision must not provide for any change in the units 
and allocations on the list after approval of the SIP revision by the 
Administrator and must not provide for any change in any allocation 
determined and recorded by the Administrator under subpart CCCCC of 
part 97 of this chapter;
    (5) Provided that:
    (i) By October 17, 2011, the State must notify the Administrator 
electronically in a format specified by the Administrator of the 
State's intent to submit to the Administrator a complete SIP revision 
meeting the requirements of paragraph (d)(1) through (4) of this 
section by April 1, 2012; and
    (ii) The State must submit to the Administrator a complete SIP 
revision described in paragraph (d)(5)(i) of this section by April 1, 
2012.
    (e) Notwithstanding the provisions of paragraph (a) of this 
section, a State listed in paragraph (b) of this section may adopt and 
include in a SIP revision, and the Administrator will approve, 
regulations revising subpart CCCCC of part 97 of this chapter as 
follows and not making any other substantive revisions of that subpart:
    (1) The State may adopt, as TR SO2 Group 1 allowance 
allocation or auction provisions replacing the provisions in Sec. Sec.  
97.611(a) and (b)(1) and 97.612(a) of this chapter with regard to the 
control period in 2014 or any subsequent year, any methodology under 
which the State or the permitting authority allocates or auctions TR 
SO2 Group 1 allowances and may adopt, in addition to the 
definitions in Sec.  97.602 of this chapter, one or more definitions 
that shall apply only to terms as used in the adopted TR SO2 
Group 1 allowance allocation or auction provisions, if such 
methodology--
    (i) Requires the State or the permitting authority to allocate and, 
if applicable, auction a total amount of TR SO2 Group 1 
allowances for any such control period not exceeding the amount, under 
Sec. Sec.  97.610(a) and 97.621 of this chapter for the State and such 
control period, of the TR SO2 Group 1 trading budget minus 
the sum of the Indian country new unit set-aside and the amount of any 
TR SO2 Group 1 allowances already allocated and recorded by 
the Administrator.
    (ii) Requires, to the extent the State adopts provisions for 
allocations or auction of TR SO2 Group 1 allowances for any 
such control period to any TR SO2 Group 1 units covered by 
Sec.  97.611(a) of this chapter, that the State or the permitting 
authority submit such allocations or the results of such auctions for 
such control period (except allocations or results of auctions to such 
units of TR SO2 Group 1 allowances remaining in a set-aside 
after completion of the allocations or auctions for which the set-aside 
was created) to the Administrator no later than the following dates:

------------------------------------------------------------------------
  Year of the control period for which TR    Deadline for submission of
  SO2 Group 1 allowances are allocated or      allocations or auction
                 auctioned                    results to  administrator
------------------------------------------------------------------------
2014......................................  June 1, 2013.
2015......................................  June 1, 2013.
2016......................................  June 1, 2014.
2017......................................  June 1, 2014.
2018......................................  June 1, 2015.
2019......................................  June 1, 2015.
2020 and any year thereafter..............  June 1 of the fourth year
                                             before the year of the
                                             control period.
------------------------------------------------------------------------

     (iii) Requires, to the extent the State adopts provisions for 
allocations or auctions of TR SO2 Group 1 allowances for any 
such control period to any TR SO2 Group 1 units covered by 
Sec. Sec.  97.611(b)(1) and 97.612(a) of this chapter, that the State 
or the permitting authority submit such allocations or the results of 
such auctions (except allocations or results of auctions to such units 
of TR SO2 Group 1 allowances remaining in a set-aside after 
completion of the allocations or auctions for which the set-aside was 
created) to the Administrator by July 1 of the year of such control 
period.
    (iv) Does not provide for any change, after the submission 
deadlines in paragraphs (e)(1)(ii) and (iii) of this section, in the 
allocations submitted to the Administrator by such deadlines and does 
not provide for any change in any allocation determined and recorded by 
the Administrator under subpart CCCCC of part 97 of this chapter;
    (2) Provided that the State must submit a complete SIP revision 
meeting the requirements of paragraph (e)(1) of this section by 
December 1 of the year before the year of the deadlines for submission 
of allocations or auction results under paragraphs (e)(1)(ii) and (iii) 
of this section applicable to the first control period for which the 
State wants to make allocations or hold an auction under paragraph 
(e)(1) of this section.
    (f) Notwithstanding the provisions of paragraph (a) of this 
section, a State listed in paragraph (b) of this section may adopt and 
include in a SIP revision, and the Administrator will approve, as 
correcting in whole or in part, as appropriate, the deficiency in the 
SIP that is the basis for the TR Federal Implementation Plan set forth 
in paragraphs (a), (b), (d), and (e) of this section, regulations that 
are substantively identical to the provisions of the TR SO2 
Group 1 Trading Program set forth in Sec. Sec.  97.602 through 97.635 
of this chapter, except that the SIP revision:
    (1) May adopt, as TR SO2 Group 1 allowance allocation or 
auction provisions replacing the provisions in Sec. Sec.  97.611(a) and 
(b)(1) and 97.612(a) of this chapter with regard to the control period 
in 2014 and any subsequent year, any methodology under which the State 
or the permitting authority allocates or auctions TR SO2 
Group 1 allowances and that--
    (i) Requires the State or the permitting authority to allocate and, 
if applicable, auction a total amount of TR SO2 Group 1 
allowances for such control period not exceeding the amount, under 
Sec. Sec.  97.610(a) and 97.621 of this chapter for the State and such 
control period, of the TR SO2 Group 1 trading budget minus 
the sum of the Indian country new unit set-aside and the amount of any 
TR SO2 Group 1 allowances already allocated and recorded by 
the Administrator.
    (ii) Requires, to the extent the State adopts provisions for 
allocations or auction of TR SO2 Group 1 allowances for any 
such control period to any TR

[[Page 48359]]

SO2 Group 1 units covered by Sec.  97.611(a) of this 
chapter, that the State or the permitting authority submit such 
allocations or the results of such auctions for such control period 
(except allocations or results of auctions to such units of TR 
SO2 Group 1 allowances remaining in a set-aside after 
completion of the allocations or auctions for which the set-aside was 
created) to the Administrator no later than the following dates:

------------------------------------------------------------------------
  Year of the control period for which TR    Deadline for submission of
  SO2 Group 1 allowances are allocated or      allocations or auction
                 auctioned                    results to  administrator
------------------------------------------------------------------------
2014......................................  June 1, 2013.
2015......................................  June 1, 2013.
2016......................................  June 1, 2014.
2017......................................  June 1, 2014.
2018......................................  June 1, 2015.
2019......................................  June 1, 2015.
2020 and any year thereafter..............  June 1 of the fourth year
                                             before the year of the
                                             control period.
------------------------------------------------------------------------

     (iii) Requires, to the extent the State adopts provisions for 
allocations or auctions of TR SO2 Group 1 allowances for any 
such control period to any TR SO2 Group 1 units covered by 
Sec. Sec.  97.611(b)(1) and 97.612(a) of this chapter, that the State 
or the permitting authority submit such allocations or the results of 
such auctions (except allocations or results of auctions to such units 
of TR SO2 Group 1 allowances remaining in a set-aside after 
completion of the allocations or auctions for which the set-aside was 
created) to the Administrator by July 1 of the year of such control 
period.
    (iv) Does not provide for any change, after the submission 
deadlines in paragraphs (f)(2)(ii) and (iii) of this section, in the 
allocations submitted to the Administrator by such deadlines and does 
not provide for any change in any allocation determined and recorded by 
the Administrator under subpart CCCCC of part 97 of this chapter;
    (2) May adopt, in addition to the definitions in Sec.  97.602 of 
this chapter, one or more definitions that shall apply only to terms as 
used in the TR SO2 Group 1 allowance allocation or auction 
provisions adopted under paragraph (f)(1) of this section;
    (3) May substitute the name of the State for the term ``State'' as 
used in subpart CCCCC of part 97 of this chapter, to the extent the 
Administrator determines that such substitutions do not make 
substantive changes in the provisions in Sec. Sec.  97.602 through 
97.635 of this chapter; and
    (4) Must not include any of the references to, or requirements 
imposed on, any unit in Indian country within the borders of the State 
in the provisions in Sec. Sec.  97.602 through 97.635 of this chapter 
and must not include the provisions in Sec. Sec.  97.611(b)(2) and 
97.612(b), all of which provisions will continue to apply under the 
portion of the TR Federal Implementation Plan that is not replaced by 
the SIP revision;
    (5) Provided that, if and when any covered unit is located in 
Indian country within the borders of the State, the Administrator may 
modify his or her approval of the SIP revision to exclude the 
provisions in Sec. Sec.  97.602 (definitions of ``common designated 
representative'', ``common designated representative's assurance 
level'', and ``common designated representative's share''), 
97.606(c)(2), 97.625, and the portions of other provisions referencing 
these sections and may modify the portion of the TR Federal 
Implementation Plan that is not replaced by the SIP revision to include 
these provisions;
    (6) Provided that the State must submit a complete SIP revision 
meeting the requirements of paragraphs (f)(1) through (4) of this 
section by December 1 of the year before the year of the deadlines for 
submission of allocations or auction results under paragraphs 
(f)(1)(ii) and (iii) of this section applicable to the first control 
period for which the State wants to make allocations or hold an auction 
under paragraph (f)(1)(ii) and (iii) of this section.
    (g) Notwithstanding the provisions of paragraph (a) of this 
section, a State listed in paragraph (c) of this section may adopt and 
include in a SIP revision, and the Administrator will approve, as TR 
SO2 Group 2 allowance allocation provisions replacing the 
provisions in Sec.  97.711(a) of this chapter with regard to the 
control period in 2013, a list of TR SO2 Group 2 units and 
the amount of TR SO2 Group 2 allowances allocated to each 
unit on such list, provided that the list of units and allocations 
meets the following requirements:
    (1) All of the units on the list must be units that are in the 
State and commenced commercial operation before January 1, 2010;
    (2) The total amount of TR SO2 Group 2 allowance 
allocations on the list must not exceed the amount, under Sec.  
97.710(a) of this chapter for the State and the control period in 2013, 
of TR SO2 Group 2 trading budget minus the sum of the new 
unit set-aside and Indian country new unit set-aside;
    (3) The list must be submitted electronically in a format specified 
by the Administrator; and
    (4) The SIP revision must not provide for any change in the units 
and allocations on the list after approval of the SIP revision by the 
Administrator and must not provide for any change in any allocation 
determined and recorded by the Administrator under subpart DDDDD of 
part 97 of this chapter;
    (5) Provided that:
    (i) By October 17, 2011, the State must notify the Administrator 
electronically in a format specified by the Administrator of the 
State's intent to submit to the Administrator a complete SIP revision 
meeting the requirements of paragraph (g)(1) through (4) of this 
section by April 1, 2012; and
    (ii) The State must submit to the Administrator a complete SIP 
revision described in paragraph (g)(5)(i) of this section by April 1, 
2012.
    (h) Notwithstanding the provisions of paragraph (a) of this 
section, a State listed in paragraph (c) of this section may adopt and 
include in a SIP revision, and the Administrator will approve, 
regulations revising subpart DDDDD of part 97 of this chapter as 
follows and not making any other substantive revisions of that subpart:
    (1) The State may adopt, as TR SO2 Group 2 allowance 
allocation or auction provisions replacing the provisions in Sec. Sec.  
97.711(a) and (b)(1) and 97.712(a) of this chapter with regard to the 
control period in 2014 and any subsequent year, any methodology under 
which the State or the permitting authority allocates or auctions TR 
SO2 Group 2 allowances and may adopt, in addition to the 
definitions in Sec.  97.702 of this chapter, one or more definitions 
that shall apply only to terms as used in the adopted TR SO2 
Group 2 allowance allocation or auction provisions, if such 
methodology--
    (i) Requires the State or the permitting authority to allocate and, 
if applicable, auction a total amount of TR SO2 Group 2 
allowances for any such control period not exceeding the amount, under 
Sec. Sec.  97.710(a) and 97.721 of this chapter for the State and such 
control period, of the TR SO2 Group 2 trading budget minus 
the sum of the Indian country new unit set-aside and the amount of any 
TR SO2 Group 2 allowances already allocated and recorded by 
the Administrator.
    (ii) Requires, to the extent the State adopts provisions for 
allocations or auction of TR SO2 Group 2 allowances for any 
such control period to any TR SO2 Group 2 units covered by 
Sec.  97.711(a) of this chapter, that the State or the permitting 
authority submit such

[[Page 48360]]

allocations or the results of such auctions for such control period 
(except allocations or results of auctions to such units of TR 
SO2 Group 2 allowances remaining in a set-aside after 
completion of the allocations or auctions for which the set-aside was 
created) to the Administrator no later than the following dates:

------------------------------------------------------------------------
  Year of the control period for which TR    Deadline for submission of
  SO2 Group 2 allowances are allocated or      allocations or auction
                 auctioned                    results to administrator
------------------------------------------------------------------------
2014......................................  June 1, 2013.
2015......................................  June 1, 2013.
2016......................................  June 1, 2014.
2017......................................  June 1, 2014.
2018......................................  June 1, 2015.
2019......................................  June 1, 2015.
2020 and any year thereafter..............  June 1 of the fourth year
                                             before the year of the
                                             control period.
------------------------------------------------------------------------

     (iii) Requires, to the extent the State adopts provisions for 
allocations or auctions of TR SO2 Group 2 allowances for any 
such control period to any TR SO2 Group 2 units covered by 
Sec. Sec.  97.711(b)(1) and 97.712(a) of this chapter, that the State 
or the permitting authority submit such allocations or the results of 
such auctions (except allocations or results of auctions to such units 
of TR SO2 Group 2 allowances remaining in a set-aside after 
completion of the allocations or auctions for which the set-aside was 
created) to the Administrator by July 1 of the year of such control 
period.
    (iv) Does not provide for any change, after the submission 
deadlines in paragraphs (h)(1)(ii) and (iii) of this section, in the 
allocations submitted to the Administrator by such deadlines and does 
not provide for any change in any allocation determined and recorded by 
the Administrator under subpart DDDDD of part 97 of this chapter;
    (2) Provided that the State must submit a complete SIP revision 
meeting the requirements of paragraph (h)(1) of this section by 
December 1 of the year before the year of the deadlines for submission 
of allocations or auction results under paragraphs (h)(1)(ii) and (iii) 
of this section applicable to the first control period for which the 
State wants to make allocations or hold an auction under paragraph 
(h)(1)(ii) and (iii) of this section.
    (i) Notwithstanding the provisions of paragraph (a) of this 
section, a State listed in paragraph (c) of this section may adopt and 
include in a SIP revision, and the Administrator will approve, as 
correcting in whole or in part, as appropriate, the deficiency in the 
SIP that is the basis for the TR Federal Implementation Plan set forth 
in paragraphs (a), (c), (g), and (h) of this section, regulations that 
are substantively identical to the provisions of the TR SO2 
Group 2 Trading Program set forth in Sec. Sec.  97.702 through 97.735 
of this chapter, except that the SIP revision:
    (1) May adopt, as TR SO2 Group 2 allowance allocation or 
auction provisions replacing the provisions in Sec. Sec.  97.711(a) and 
(b)(1) and 97.712(a) of this chapter with regard to the control period 
in 2014 and any subsequent year, any methodology under which the State 
or the permitting authority allocates or auctions TR SO2 
Group 2 allowances and that--
    (i) Requires the State or the permitting authority to allocate and, 
if applicable, auction a total amount of TR SO2 Group 2 
allowances for any such control period not exceeding the amount, under 
Sec. Sec.  97.710(a) and 97.721 of this chapter for the State and such 
control period, of the TR SO2 Group 2 trading budget minus 
the sum of the Indian country new unit set-aside and the amount of any 
TR SO2 Group 2 allowances already allocated and recorded by 
the Administrator.
    (ii) Requires, to the extent the State adopts provisions for 
allocations or auction of TR SO2 Group 2 allowances for any 
such control period to any TR SO2 Group 2 units covered by 
Sec.  97.711(a) of this chapter, that the State or the permitting 
authority submit such allocations or the results of such auctions for 
such control period (except allocations or results of auctions to such 
units of TR SO2 Group 1 allowances remaining in a set-aside 
after completion of the allocations or auctions for which the set-aside 
was created) to the Administrator no later than the following dates:

------------------------------------------------------------------------
  Year of the control period for which TR    Deadline for submission of
  SO2 Group 2 allowances are allocated or      allocations or auction
                 auctioned                    results to administrator
------------------------------------------------------------------------
2014......................................  June 1, 2013.
2015......................................  June 1, 2013.
2016......................................  June 1, 2014.
2017......................................  June 1, 2014.
2018......................................  June 1, 2015.
2019......................................  June 1, 2015.
2020 and any year thereafter..............  June 1 of the fourth year
                                             before the year of the
                                             control period.
------------------------------------------------------------------------

     (iii) Requires, to the extent the State adopts provisions for 
allocations or auctions of TR SO2 Group 2 allowances for any 
such control period to any TR SO2 Group 2 units covered by 
Sec. Sec.  97.711(b)(1) and 97.712(a) of this chapter, that the State 
or the permitting authority submit such allocations or the results of 
such auctions (except allocations or results of auctions to such units 
of TR SO2 Group 2 allowances remaining in a set-aside after 
completion of the allocations or auctions for which the set-aside was 
created) to the Administrator by July 1 of the year of such control 
period.
    (iv) Does not provide for any change, after the submission 
deadlines in paragraphs (i)(1)(ii) and (iii) of this section, in the 
allocations submitted to the Administrator by such deadlines and does 
not provide for any change in any allocation determined and recorded by 
the Administrator under subpart DDDDD of part 97 of this chapter;
    (2) May adopt, in addition to the definitions in Sec.  97.702 of 
this chapter, one or more definitions that shall apply only to terms as 
used in the TR SO2 Group 2 allowance allocation or auction 
provisions adopted under paragraph (i)(1) of this section;
    (3) May substitute the name of the State for the term ``State'' as 
used in subpart DDDDD of part 97 of this chapter, to the extent the 
Administrator determines that such substitutions do not make 
substantive changes in the provisions in Sec. Sec.  97.702 through 
97.735 of this chapter; and
    (4) Must not include any of the references to, or requirements 
imposed on, any unit in Indian country within the borders of the State 
in the provisions in Sec. Sec.  97.702 through 97.735 of this chapter 
and must not include the provisions in Sec. Sec.  97.711(b)(2) and 
97.712(b), all of which provisions will continue to apply under the 
portion of the TR Federal Implementation Plan that is not replaced by 
the SIP revision;
    (5) Provided that, if and when any covered unit is located in 
Indian country within the borders of the State, the Administrator may 
modify his or her approval of the SIP revision to exclude the 
provisions in Sec. Sec.  97.702 (definitions of ``common designated 
representative'', ``common designated representative's assurance 
level'', and ``common designated representative's share''), 
97.706(c)(2), 97.725, and the portions of other provisions referencing 
these sections and may modify the portion of the TR Federal 
Implementation Plan that is not replaced by the SIP revision to include 
these provisions;
    (6) Provided that the State must submit a complete SIP revision 
meeting the requirements of paragraphs (i)(1) through (4) of this 
section by December 1 of the year before the year of the deadlines for 
submission of allocations or auction results under paragraphs

[[Page 48361]]

(i)(1)(ii) and (iii) of this section applicable to the first control 
period for which the State wants to make allocations or hold an auction 
under paragraphs (i)(1)(ii) and (iii) of this section.
    (j) Following promulgation of an approval by the Administrator of a 
State's SIP revision as correcting in whole or in part, as appropriate, 
the SIP's deficiency that is the basis for the TR Federal 
Implementation Plan, the provisions of paragraph (b) and (c) of this 
section, as applicable, will no longer apply to sources in the State, 
unless the Administrator's approval of the SIP revision is partial or 
conditional, and will continue to apply to sources in any Indian 
country within the borders of the State.
    (k) Notwithstanding the provisions of paragraph (j) of this 
section, if, at the time of such approval of the State's SIP revision, 
the Administrator has already started recording any allocations of TR 
SO2 Group 1 allowances under subpart CCCCC of part 97 of 
this chapter, or allocations of TR SO2 Group 2 allowances 
under subpart DDDDD of part 97 of this chapter, to units in a State for 
a control period in any year, the provisions of subpart CCCCC of part 
97 of this chapter authorizing the Administrator to complete the 
allocation and recordation of TR SO2 Group 1 allowances, or 
of subpart DDDDD of part 97 of this chapter authorizing the 
Administrator to complete the allocation and recordation of TR 
SO2 Group 2 allowances, as applicable, to units in the State 
for each such control period shall continue to apply, unless provided 
otherwise by such approval of the State's SIP revision.

Subpart B--Alabama

0
10. Section 52.54 is added to read as follows:

Sec.  52.54  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

    (a)(1) The owner and operator of each source and each unit located 
in the State of Alabama and for which requirements are set forth under 
the TR NOX Annual Trading Program in subpart AAAAA of part 
97 of this chapter must comply with such requirements. The obligation 
to comply with such requirements will be eliminated by the promulgation 
of an approval by the Administrator of a revision to Alabama's State 
Implementation Plan (SIP) as correcting the SIP's deficiency that is 
the basis for the TR Federal Implementation Plan under Sec.  52.38(a), 
except to the extent the Administrator's approval is partial or 
conditional.
    (2) Notwithstanding the provisions of paragraph (a)(1) of this 
section, if, at the time of the approval of Alabama's SIP revision 
described in paragraph (a)(1) of this section, the Administrator has 
already started recording any allocations of TR NOX Annual 
allowances under subpart AAAAA of part 97 of this chapter to units in 
the State for a control period in any year, the provisions of subpart 
AAAAA of part 97 of this chapter authorizing the Administrator to 
complete the allocation and recordation of TR NOX Annual 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.
    (b)(1) The owner and operator of each source and each unit located 
in the State of Alabama and for which requirements are set forth under 
the TR NOX Ozone Season Trading Program in subpart BBBBB of 
part 97 of this chapter must comply with such requirements. The 
obligation to comply with such requirements will be eliminated by the 
promulgation of an approval by the Administrator of a revision to 
Alabama's State Implementation Plan (SIP) as correcting the SIP's 
deficiency that is the basis for the TR Federal Implementation Plan 
under Sec.  52.38(b), except to the extent the Administrator's approval 
is partial or conditional.
    (2) Notwithstanding the provisions of paragraph (b)(1) of this 
section, if, at the time of the approval of the Alabama's SIP revision 
described in paragraph (b)(1) of this section, the Administrator has 
already started recording any allocations of TR NOX Ozone 
Season allowances under subpart BBBBB of part 97 of this chapter to 
units in the State for a control period in any year, the provisions of 
subpart BBBBB of part 97 of this chapter authorizing the Administrator 
to complete the allocation and recordation of TR NOX Ozone 
Season allowances to units in the State for each such control period 
shall continue to apply, unless provided otherwise by such approval of 
the State's SIP revision.

0
11. Section 52.55 is added to read as follows:

Sec.  52.55  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of sulfur dioxide?

    (a) The owner and operator of each source and each unit located in 
the State of Alabama and for which requirements are set forth under the 
TR SO2 Group 2 Trading Program in subpart DDDDD of part 97 
of this chapter must comply with such requirements. The obligation to 
comply with such requirements will be eliminated by the promulgation of 
an approval by the Administrator of a revision to Alabama's State 
Implementation Plan (SIP) as correcting the SIP's deficiency that is 
the basis for the TR Federal Implementation Plan under Sec.  52.39, 
except to the extent the Administrator's approval is partial or 
conditional.
    (b) Notwithstanding the provisions of paragraph (a) of this 
section, if, at the time of the approval of Alabama's SIP revision 
described in paragraph (a) of this section, the Administrator has 
already started recording any allocations of TR SO2 Group 2 
allowances under subpart DDDDD of part 97 of this chapter to units in 
the State for a control period in any year, the provisions of subpart 
DDDDD of part 97 of this chapter authorizing the Administrator to 
complete the allocation and recordation of TR SO2 Group 2 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.

Subpart E--Arkansas

0
12. Section 52.184 is added to read as follows:

Sec.  52.184  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

    (a) The owner and operator of each source and each unit located in 
the State of Arkansas and for which requirements are set forth under 
the TR NOX Ozone Season Trading Program in subpart BBBBB of 
part 97 of this chapter must comply with such requirements. The 
obligation to comply with such requirements will be eliminated by the 
promulgation of an approval by the Administrator of a revision to 
Arkansas' State Implementation Plan (SIP) as correcting the SIP's 
deficiency that is the basis for the TR Federal Implementation Plan 
under Sec.  52.38(b), except to the extent the Administrator's approval 
is partial or conditional.
    (b) Notwithstanding the provisions of paragraph (a) of this 
section, if, at the time of the approval of Arkansas' SIP revision 
described in paragraph (a) of this section, the Administrator has 
already started recording any allocations of TR NOX Ozone 
Season allowances under subpart BBBBB of part 97 of this chapter to 
units in the State for a control period in any year, the provisions of 
subpart BBBBB of part 97 of this chapter authorizing the Administrator 
to complete the allocation and recordation of TR NOX Ozone 
Season allowances to

[[Page 48362]]

units in the State for each such control period shall continue to 
apply, unless provided otherwise by such approval of the State's SIP 
revision.

Subpart I--Delaware

0
13. Section 52.440 is amended by adding a new paragraph (c) to read as 
follows:

Sec.  52.440  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

* * * * *
    (c) Notwithstanding any provisions of paragraphs (a) and (b) of 
this section and subparts AA through II and AAAA through IIII of part 
97 of this chapter to the contrary:
    (1) With regard to any control period that begins after December 
31, 2011,
    (i) The provisions in paragraphs (a) and (b) of this section 
relating to NOX annual or ozone season emissions shall not 
be applicable; and
    (ii) The Administrator will not carry out any of the functions set 
forth for the Administrator in subparts AA through II and AAAA through 
IIII of part 97 of this chapter; and
    (2) The Administrator will not deduct for excess emissions any CAIR 
NOX allowances or CAIR NOX Ozone Season 
allowances allocated for 2012 or any year thereafter;
    (3) By November 7, 2011, the Administrator will remove from the 
CAIR NOX Allowance Tracking System accounts all CAIR 
NOX allowances allocated for a control period in 2012 and 
any subsequent year, and, thereafter, no holding or surrender of CAIR 
NOX allowances will be required with regard to emissions or 
excess emissions for such control periods; and
    (4) By November 7, 2011, the Administrator will remove from the 
CAIR NOX Ozone Season Allowance Tracking System accounts all 
CAIR NOX Ozone Season allowances allocated for a control 
period in 2012 and any subsequent year, and, thereafter, no holding or 
surrender of CAIR NOX Ozone Season allowances will be 
required with regard to emissions or excess emissions for such control 
periods.

0
14. Section 52.441 is amended by designating the existing text as 
paragraph (a) and adding a new paragraph (b) to read as follows:

Sec.  52.441  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of sulfur dioxide?

* * * * *
    (b) Notwithstanding any provisions of paragraph (a) of this section 
and subparts AAA through III of part 97 of this chapter and any State's 
SIP to the contrary:
    (1) With regard to any control period that begins after December 
31, 2011,
    (i) The provisions of paragraph (a) of this section relating to 
SO2 emissions shall not be applicable; and
    (ii) The Administrator will not carry out any of the functions set 
forth for the Administrator in subparts AAA through III of part 97 of 
this chapter; and
    (2) The Administrator will not deduct for excess emissions any CAIR 
SO2 allowances allocated for 2012 or any year thereafter.

Subpart J--District of Columbia

0
15. Section 52.484 is amended by adding a new paragraph (c) to read as 
follows:

Sec.  52.484  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

* * * * *
    (c) Notwithstanding any provisions of paragraphs (a) and (b) of 
this section and subparts AA through II and AAAA through IIII of part 
97 of this chapter to the contrary:
    (1) With regard to any control period that begins after December 
31, 2011,
    (i) The provisions in paragraphs (a) and (b) of this section 
relating to NOX annual or ozone season emissions shall not 
be applicable; and
    (ii) The Administrator will not carry out any of the functions set 
forth for the Administrator in subparts AA through II and AAAA through 
IIII of part 97 of this chapter; and
    (2) The Administrator will not deduct for excess emissions any CAIR 
NOX allowances or CAIR NOX Ozone Season 
allowances allocated for 2012 or any year thereafter;
    (3) By November 7, 2011, the Administrator will remove from the 
CAIR NOX Allowance Tracking System accounts all CAIR 
NOX allowances allocated for a control period in 2012 and 
any subsequent year, and, thereafter, no holding or surrender of CAIR 
NOX allowances will be required with regard to emissions or 
excess emissions for such control periods; and
    (4) By November 7, 2011, the Administrator will remove from the 
CAIR NOX Ozone Season Allowance Tracking System accounts all 
CAIR NOX Ozone Season allowances allocated for a control 
period in 2012 and any subsequent year, and, thereafter, no holding or 
surrender of CAIR NOX Ozone Season allowances will be 
required with regard to emissions or excess emissions for such control 
periods.

0
16. Section 52.485 is amended by designating the existing text as 
paragraph (a) and adding a new paragraph (b) to read as follows:

Sec.  52.485  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of sulfur dioxide?

* * * * *
    (b) Notwithstanding any provisions of paragraph (a) of this section 
and subparts AAA through III of part 97 of this chapter and any State's 
SIP to the contrary:
    (1) With regard to any control period that begins after December 
31, 2011,
    (i) The provisions of paragraph (a) of this section relating to 
SO2 emissions shall not be applicable; and
    (ii) The Administrator will not carry out any of the functions set 
forth for the Administrator in subparts AAA through III of part 97 of 
this chapter; and
    (2) The Administrator will not deduct for excess emissions any CAIR 
SO2 allowances allocated for 2012 or any year thereafter.

Subpart K--Florida

0
17. Section 52.540 is added to read as follows:

Sec.  52.540  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

    (a) The owner and operator of each source and each unit located in 
the State of Florida and Indian country within the borders of the State 
and for which requirements are set forth under the TR NOX 
Ozone Season Trading Program in subpart BBBBB of part 97 of this 
chapter must comply with such requirements. The obligation to comply 
with such requirements with regard to sources and units located in the 
State will be eliminated by the promulgation of an approval by the 
Administrator of a revision to Florida's State Implementation Plan 
(SIP) as correcting in part the SIP's deficiency that is the basis for 
the TR Federal Implementation Plan under Sec.  52.38(b), except to the 
extent the Administrator's approval is partial or conditional. The 
obligation to comply with such requirements with regard to sources and 
units located in Indian country within the borders of the State will 
not be eliminated by the promulgation of an approval by the 
Administrator of a revision to Florida's SIP.
    (b) Notwithstanding the provisions of paragraph (a) of this 
section, if, at the

[[Page 48363]]

time of the approval of Florida's SIP revision described in paragraph 
(a) of this section, the Administrator has already started recording 
any allocations of TR NOX Ozone Season allowances under 
subpart BBBBB of part 97 of this chapter to units in the State for a 
control period in any year, the provisions of subpart BBBBB of part 97 
of this chapter authorizing the Administrator to complete the 
allocation and recordation of TR NOX Ozone Season allowances 
to units in the State for each such control period shall continue to 
apply, unless provided otherwise by such approval of the State's SIP 
revision.

Subpart L--Georgia

0
18. Section 52.584 is added to read as follows:

Sec.  52.584  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

    (a)(1) The owner and operator of each source and each unit located 
in the State of Georgia and for which requirements are set forth under 
the TR NOX Annual Trading Program in subpart AAAAA of part 
97 of this chapter must comply with such requirements. The obligation 
to comply with such requirements will be eliminated by the promulgation 
of an approval by the Administrator of a revision to Georgia's State 
Implementation Plan (SIP) as correcting the SIP's deficiency that is 
the basis for the TR Federal Implementation Plan under Sec.  52.38(a), 
except to the extent the Administrator's approval is partial or 
conditional.
    (2) Notwithstanding the provisions of paragraph (a)(1) of this 
section, if, at the time of the approval of Georgia's SIP revision 
described in paragraph (a)(1) of this section, the Administrator has 
already started recording any allocations of TR NOX Annual 
allowances under subpart AAAAA of part 97 of this chapter to units in 
the State for a control period in any year, the provisions of subpart 
AAAAA of part 97 of this chapter authorizing the Administrator to 
complete the allocation and recordation of TR NOX Annual 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.
    (b)(1) The owner and operator of each source and each unit located 
in the State of Georgia and for which requirements are set forth under 
the TR NOX Ozone Season Trading Program in subpart BBBBB of 
part 97 of this chapter must comply with such requirements. The 
obligation to comply with such requirements will be eliminated by the 
promulgation of an approval by the Administrator of a revision to 
Georgia's State Implementation Plan (SIP) as correcting the SIP's 
deficiency that is the basis for the TR Federal Implementation Plan 
under Sec.  52.38(b), except to the extent the Administrator's approval 
is partial or conditional.
    (2) Notwithstanding the provisions of paragraph (b)(1) of this 
section, if, at the time of the approval of Georgia's SIP revision 
described in paragraph (b)(1) of this section, the Administrator has 
already started recording any allocations of TR NOX Ozone 
Season allowances under subpart BBBBB of part 97 of this chapter to 
units in the State for a control period in any year, the provisions of 
subpart BBBBB of part 97 of this chapter authorizing the Administrator 
to complete the allocation and recordation of TR NOX Ozone 
Season allowances to units in the State for each such control period 
shall continue to apply, unless provided otherwise by such approval of 
the State's SIP revision.

0
19. Section 52.585 is added to read as follows:

Sec.  52.585  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of sulfur dioxide?

    (a) The owner and operator of each source and each unit located in 
the State of Georgia and for which requirements are set forth under the 
TR SO2 Group 2 Trading Program in subpart DDDDD of part 97 
of this chapter must comply with such requirements. The obligation to 
comply with such requirements will be eliminated by the promulgation of 
an approval by the Administrator of a revision to Georgia's State 
Implementation Plan (SIP) as correcting the SIP's deficiency that is 
the basis for the TR Federal Implementation Plan under Sec.  52.39, 
except to the extent the Administrator's approval is partial or 
conditional.
    (b) Notwithstanding the provisions of paragraph (a) of this 
section, if, at the time of the approval of Georgia's SIP revision 
described in paragraph (a) of this section, the Administrator has 
already started recording any allocations of TR SO2 Group 2 
allowances under subpart DDDDD of part 97 of this chapter to units in 
the State for a control period in any year, the provisions of subpart 
DDDDD of part 97 of this chapter authorizing the Administrator to 
complete the allocation and recordation of TR SO2 Group 2 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.

Subpart O--Illinois

0
20. Section 52.745 is added to read as follows:

Sec.  52.745  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

    (a)(1) The owner and operator of each source and each unit located 
in the State of Illinois and for which requirements are set forth under 
the TR NOX Annual Trading Program in subpart AAAAA of part 
97 of this chapter must comply with such requirements. The obligation 
to comply with such requirements will be eliminated by the promulgation 
of an approval by the Administrator of a revision to Illinois' State 
Implementation Plan (SIP) as correcting the SIP's deficiency that is 
the basis for the TR Federal Implementation Plan under Sec.  52.38(a), 
except to the extent the Administrator's approval is partial or 
conditional.
    (2) Notwithstanding the provisions of paragraph (a)(1) of this 
section, if, at the time of the approval of Illinois' SIP revision 
described in paragraph (a)(1) of this section, the Administrator has 
already started recording any allocations of TR NOX Annual 
allowances under subpart AAAAA of part 97 of this chapter to units in 
the State for a control period in any year, the provisions of subpart 
AAAAA of part 97 of this chapter authorizing the Administrator to 
complete the allocation and recordation of TR NOX Annual 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.
    (b)(1) The owner and operator of each source and each unit located 
in the State of Illinois and for which requirements are set forth under 
the TR NOX Ozone Season Trading Program in subpart BBBBB of 
part 97 of this chapter must comply with such requirements. The 
obligation to comply with such requirements will be eliminated by the 
promulgation of an approval by the Administrator of a revision to 
Illinois' State Implementation Plan (SIP) as correcting the SIP's 
deficiency that is the basis for the TR Federal Implementation Plan 
under Sec.  52.38(b), except to the extent the Administrator's approval 
is partial or conditional.
    (2) Notwithstanding the provisions of paragraph (b)(1) of this 
section, if, at the time of the approval of Illinois' SIP revision 
described in paragraph (b)(1) of this section, the Administrator has 
already started recording any allocations of TR NOX Ozone 
Season allowances under subpart BBBBB of part 97 of this

[[Page 48364]]

chapter to units in the State for a control period in any year, the 
provisions of subpart BBBBB of part 97 of this chapter authorizing the 
Administrator to complete the allocation and recordation of TR 
NOX Ozone Season allowances to units in the State for each 
such control period shall continue to apply, unless provided otherwise 
by such approval of the State's SIP revision.

0
21. Section 52.746 is added to read as follows:

Sec.  52.746  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of sulfur dioxide?

    (a) The owner and operator of each source and each unit located in 
the State of Illinois and for which requirements are set forth under 
the TR SO2 Group 1 Trading Program in subpart CCCCC of part 
97 of this chapter must comply with such requirements. The obligation 
to comply with such requirements will be eliminated by the promulgation 
of an approval by the Administrator of a revision to Illinois' State 
Implementation Plan (SIP) as correcting the SIP's deficiency that is 
the basis for the TR Federal Implementation Plan under Sec.  52.39, 
except to the extent the Administrator's approval is partial or 
conditional.
    (b) Notwithstanding the provisions of paragraph (a) of this 
section, if, at the time of the approval of Illinois' SIP revision 
described in paragraph (a) of this section, the Administrator has 
already started recording any allocations of TR SO2 Group 1 
allowances under subpart CCCCC of part 97 of this chapter to units in 
the State for a control period in any year, the provisions of subpart 
CCCCC of part 97 of this chapter authorizing the Administrator to 
complete the allocation and recordation of TR SO2 Group 1 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.

Subpart P--Indiana

0
22. Section 52.789 is added to read as follows:

Sec.  52.789  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

    (a)(1) The owner and operator of each source and each unit located 
in the State of Indiana and for which requirements are set forth under 
the TR NOX Annual Trading Program in subpart AAAAA of part 
97 of this chapter must comply with such requirements. The obligation 
to comply with such requirements will be eliminated by the promulgation 
of an approval by the Administrator of a revision to Indiana's State 
Implementation Plan (SIP) as correcting the SIP's deficiency that is 
the basis for the TR Federal Implementation Plan under Sec.  52.38(a), 
except to the extent the Administrator's approval is partial or 
conditional.
    (2) Notwithstanding the provisions of paragraph (a)(1) of this 
section, if, at the time of the approval of Indiana's SIP revision 
described in paragraph (a)(1) of this section, the Administrator has 
already started recording any allocations of TR NOX Annual 
allowances under subpart AAAAA of part 97 of this chapter to units in 
the State for a control period in any year, the provisions of subpart 
AAAAA of part 97 of this chapter authorizing the Administrator to 
complete the allocation and recordation of TR NOX Annual 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.
    (b)(1) The owner and operator of each source and each unit located 
in the State of Indiana and for which requirements are set forth under 
the TR NOX Ozone Season Trading Program in subpart BBBBB of 
part 97 of this chapter must comply with such requirements. The 
obligation to comply with such requirements will be eliminated by the 
promulgation of an approval by the Administrator of a revision to 
Indiana's State Implementation Plan (SIP) as correcting the SIP's 
deficiency that is the basis for the TR Federal Implementation Plan 
under Sec.  52.38(b), except to the extent the Administrator's approval 
is partial or conditional.
    (2) Notwithstanding the provisions of paragraph (b)(1) of this 
section, if, at the time of the approval of Indiana's SIP revision 
described in paragraph (b)(1) of this section, the Administrator has 
already started recording any allocations of TR NOX Ozone 
Season allowances under subpart BBBBB of part 97 of this chapter to 
units in the State for a control period in any year, the provisions of 
subpart BBBBB of part 97 of this chapter authorizing the Administrator 
to complete the allocation and recordation of TR NOX Ozone 
Season allowances to units in the State for each such control period 
shall continue to apply, unless provided otherwise by such approval of 
the State's SIP revision.

0
23. Section 52.790 is added to read as follows:

Sec.  52.790  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of sulfur dioxide?

    (a) The owner and operator of each source and each unit located in 
the State of Indiana and for which requirements are set forth under the 
TR SO2 Group 1 Trading Program in subpart CCCCC of part 97 
of this chapter must comply with such requirements. The obligation to 
comply with such requirements will be eliminated by the promulgation of 
an approval by the Administrator of a revision to Indiana's State 
Implementation Plan (SIP) as correcting the SIP's deficiency that is 
the basis for the TR Federal Implementation Plan under Sec.  52.39 
except to the extent the Administrator's approval is partial or 
conditional.
    (b) Notwithstanding the provisions of paragraph (a) of this 
section, if, at the time of the approval of Indiana's SIP revision 
described in paragraph (a) of this section, the Administrator has 
already started recording any allocations of TR SO2 Group 1 
allowances under subpart CCCCC of part 97 of this chapter to units in 
the State for a control period in any year, the provisions of subpart 
CCCCC of part 97 of this chapter authorizing the Administrator to 
complete the allocation and recordation of TR SO2 Group 1 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.

Subpart Q--Iowa

0
24. Section 52.840 is added to read as follows:

Sec.  52.840  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

    (a)(1) The owner and operator of each source and each unit located 
in the State of Iowa and Indian country within the borders of the State 
and for which requirements are set forth under the TR NOX 
Annual Trading Program in subpart AAAAA of part 97 of this chapter must 
comply with such requirements. The obligation to comply with such 
requirements with regard to sources and units in the State will be 
eliminated by the promulgation of an approval by the Administrator of a 
revision to Iowa's State Implementation Plan (SIP) as correcting in 
part the SIP's deficiency that is the basis for the TR Federal 
Implementation Plan under Sec.  52.38(a), except to the extent the 
Administrator's approval is partial or conditional. The obligation to 
comply with such requirements with regard to

[[Page 48365]]

sources and units located in Indian country within the borders of the 
State will not be eliminated by the promulgation of an approval by the 
Administrator of a revision to Iowa's SIP.
    (2) Notwithstanding the provisions of paragraph (a)(1) of this 
section, if, at the time of the approval of Iowa's SIP revision 
described in paragraph (a)(1) of this section, the Administrator has 
already started recording any allocations of TR NOX Annual 
allowances under subpart AAAAA of part 97 of this chapter to units in 
the State for a control period in any year, the provisions of subpart 
AAAAA of part 97 of this chapter authorizing the Administrator to 
complete the allocation and recordation of TR NOX Annual 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.
    (b) [Reserved]

0
25. Section 52.841 is added to read as follows:

Sec.  52.841  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of sulfur dioxide?

    (a) The owner and operator of each source and each unit located in 
the State of Iowa and Indian country within the borders of the State 
and for which requirements are set forth under the TR SO2 
Group 1 Trading Program in subpart CCCCC of part 97 of this chapter 
must comply with such requirements. The obligation to comply with such 
requirements with regard to sources and units in the State will be 
eliminated by the promulgation of an approval by the Administrator of a 
revision to Iowa's State Implementation Plan (SIP) as correcting in 
part the SIP's deficiency that is the basis for the TR Federal 
Implementation Plan under Sec.  52.39, except to the extent the 
Administrator's approval is partial or conditional. The obligation to 
comply with such requirements with regard to sources and units located 
in Indian country within the borders of the State will not be 
eliminated by the promulgation of an approval by the Administrator of a 
revision to Iowa's SIP.
    (b) Notwithstanding the provisions of paragraph (a) of this 
section, if, at the time of the approval of Iowa's SIP revision 
described in paragraph (a) of this section, the Administrator has 
already started recording any allocations of TR SO2 Group 1 
allowances under subpart CCCCC of part 97 of this chapter to units in 
the State for a control period in any year, the provisions of subpart 
CCCCC of part 97 of this chapter authorizing the Administrator to 
complete the allocation and recordation of TR SO2 Group 1 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.

Subpart R--Kansas

0
26. Section 52.882 is added to read as follows:

Sec.  52.882  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

    (a)(1) The owner and operator of each source and each unit located 
in the State of Kansas and Indian country within the borders of the 
State and for which requirements are set forth under the TR 
NOX Annual Trading Program in subpart AAAAA of part 97 of 
this chapter must comply with such requirements. The obligation to 
comply with such requirements with regard to sources and units in the 
State will be eliminated by the promulgation of an approval by the 
Administrator of a revision to Kansas' State Implementation Plan (SIP) 
as correcting in part the SIP's deficiency that is the basis for the TR 
Federal Implementation Plan under Sec.  52.38(a), except to the extent 
the Administrator's approval is partial or conditional. The obligation 
to comply with such requirements with regard to sources and units 
located in Indian country within the borders of the State will not be 
eliminated by the promulgation of an approval by the Administrator of a 
revision to Kansas' SIP.
    (2) Notwithstanding the provisions of paragraph (a)(1) of this 
section, if, at the time of the approval of Kansas' SIP revision 
described in paragraph (a)(1) of this section, the Administrator has 
already started recording any allocations of TR NOX Annual 
allowances under subpart AAAAA of part 97 of this chapter to units in 
the State for a control period in any year, the provisions of subpart 
AAAAA of part 97 of this chapter authorizing the Administrator to 
complete the allocation and recordation of TR NOX Annual 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.
    (b) [Reserved]

0
27. Section 52.883 is added to read as follows:

Sec.  52.883  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of sulfur dioxide?

    (a) The owner and operator of each source and each unit located in 
the State of Kansas and Indian country within the borders of the State 
and for which requirements are set forth under the TR SO2 
Group 2 Trading Program in subpart DDDDD of part 97 of this chapter 
must comply with such requirements. The obligation to comply with such 
requirements will be eliminated with regard to sources and units in the 
State by the promulgation of an approval by the Administrator of a 
revision to Kansas' State Implementation Plan (SIP) as correcting in 
part the SIP's deficiency that is the basis for the TR Federal 
Implementation Plan under Sec.  52.39, except to the extent the 
Administrator's approval is partial or conditional. The obligation to 
comply with such requirements with regard to sources and units located 
in Indian country within the borders of the State will not be 
eliminated by the promulgation of an approval by the Administrator of a 
revision to Kansas' SIP.
    (b) Notwithstanding the provisions of paragraph (a) of this 
section, if, at the time of the approval of Kansas' SIP revision 
described in paragraph (a) of this section, the Administrator has 
already started recording any allocations of TR SO2 Group 2 
allowances under subpart DDDDD of part 97 of this chapter to units in 
the State for a control period in any year, the provisions of subpart 
DDDDD of part 97 of this chapter authorizing the Administrator to 
complete the allocation and recordation of TR SO2 Group 2 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.

Subpart S--Kentucky

0
28. Section 52.940 is added to read as follows:

Sec.  52.940  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

    (a)(1) The owner and operator of each source and each unit located 
in the State of Kentucky and for which requirements are set forth under 
the TR NOX Annual Trading Program in subpart AAAAA of part 
97 of this chapter must comply with such requirements. The obligation 
to comply with such requirements will be eliminated by the promulgation 
of an approval by the Administrator of a revision to Kentucky's State

[[Page 48366]]

Implementation Plan (SIP) as correcting the SIP's deficiency that is 
the basis for the TR Federal Implementation Plan under Sec.  52.38(a), 
except to the extent the Administrator's approval is partial or 
conditional.
    (2) Notwithstanding the provisions of paragraph (a)(1) of this 
section, if, at the time of the approval of Kentucky's SIP revision 
described in paragraph (a)(1) of this section, the Administrator has 
already started recording any allocations of TR NOX Annual 
allowances under subpart AAAAA of part 97 of this chapter to units in 
the State for a control period in any year, the provisions of subpart 
AAAAA of part 97 of this chapter authorizing the Administrator to 
complete the allocation and recordation of TR NOX Annual 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.
    (b)(1) The owner and operator of each source and each unit located 
in the State of Kentucky and for which requirements are set forth under 
the TR NOX Ozone Season Trading Program in subpart BBBBB of 
part 97 of this chapter must comply with such requirements. The 
obligation to comply with such requirements will be eliminated by the 
promulgation of an approval by the Administrator of a revision to 
Kentucky's State Implementation Plan (SIP) as correcting the SIP's 
deficiency that is the basis for the TR Federal Implementation Plan 
under Sec.  52.38(b), except to the extent the Administrator's approval 
is partial or conditional.
    (2) Notwithstanding the provisions of paragraph (b)(1) of this 
section, if, at the time of the approval of Kentucky's SIP revision 
described in paragraph (b)(1) of this section, the Administrator has 
already started recording any allocations of TR NOX Ozone 
Season allowances under subpart BBBBB of part 97 of this chapter to 
units in the State for a control period in any year, the provisions of 
subpart BBBBB of part 97 of this chapter authorizing the Administrator 
to complete the allocation and recordation of TR NOX Ozone 
Season allowances to units in the State for each such control period 
shall continue to apply, unless provided otherwise by such approval of 
the State's SIP revision.

0
29. Section 52.941 is added to read as follows:

Sec.  52.941  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of sulfur dioxide?

    (a) The owner and operator of each source and each unit located in 
the State of Kentucky and for which requirements are set forth under 
the TR SO2 Group 1 Trading Program in subpart CCCCC of part 
97 of this chapter must comply with such requirements. The obligation 
to comply with such requirements will be eliminated by the promulgation 
of an approval by the Administrator of a revision to Kentucky's State 
Implementation Plan (SIP) as correcting the SIP's deficiency that is 
the basis for the TR Federal Implementation Plan under Sec.  52.39, 
except to the extent the Administrator's approval is partial or 
conditional.
    (b) Notwithstanding the provisions of paragraph (a) of this 
section, if, at the time of the approval of Kentucky's SIP revision 
described in paragraph (a) of this section, the Administrator has 
already started recording any allocations of TR SO2 Group 1 
allowances under subpart CCCCC of part 97 of this chapter to units in 
the State for a control period in any year, the provisions of subpart 
CCCCC of part 97 of this chapter authorizing the Administrator to 
complete the allocation and recordation of TR SO2 Group 1 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.

Subpart T--Louisiana

0
30. Section 52.984 is amended by adding new paragraphs (c) and (d) to 
read as follows:

Sec.  52.984  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

* * * * *
    (c) Notwithstanding any provisions of paragraphs (a) and (b) of 
this section and subparts AA through II and AAAA through IIII of part 
97 of this chapter to the contrary:
    (1) With regard to any control period that begins after December 
31, 2011,
    (i) The provisions in paragraphs (a) and (b) of this section 
relating to NOX annual or ozone season emissions shall not 
be applicable; and
    (ii) The Administrator will not carry out any of the functions set 
forth for the Administrator in subparts AA through II and AAAA through 
IIII of part 97 of this chapter;
    (2) The Administrator will not deduct for excess emissions any CAIR 
NOX allowances or CAIR NOX Ozone Season 
allowances allocated for 2012 or any year thereafter;
    (3) By November 7, 2011, the Administrator will remove from the 
CAIR NOX Allowance Tracking System accounts all CAIR 
NOX allowances allocated for a control period in 2012 and 
any subsequent year, and, thereafter, no holding or surrender of CAIR 
NOX allowances will be required with regard to emissions or 
excess emissions for such control periods; and
    (4) By November 7, 2011, the Administrator will remove from the 
CAIR NOX Ozone Season Allowance Tracking System accounts all 
CAIR NOX Ozone Season allowances allocated for a control 
period in 2012 and any subsequent year, and, thereafter, no holding or 
surrender of CAIR NOX Ozone Season allowances will be 
required with regard to emissions or excess emissions for such control 
periods.
    (d)(1) The owner and operator of each source and each unit located 
in the State of Louisiana and Indian country within the borders of the 
State and for which requirements are set forth under the TR 
NOX Ozone Season Trading Program in subpart BBBBB of part 97 
of this chapter must comply with such requirements. The obligation to 
comply with such requirements with regard to sources and units in the 
State will be eliminated by the promulgation of an approval by the 
Administrator of a revision to Louisiana's State Implementation Plan 
(SIP) as correcting in part the SIP's deficiency that is the basis for 
the TR Federal Implementation Plan under Sec.  52.38(b), except to the 
extent the Administrator's approval is partial or conditional. The 
obligation to comply with such requirements with regard to sources and 
units located in Indian country within the borders of the State will 
not be eliminated by the promulgation of an approval by the 
Administrator of a revision to Louisiana's SIP.
    (2) Notwithstanding the provisions of paragraph (d)(1) of this 
section, if, at the time of the approval of Louisiana's SIP revision 
described in paragraph (d)(1) of this section, the Administrator has 
already started recording any allocations of TR NOX Ozone 
Season allowances under subpart BBBBB of part 97 of this chapter to 
units in the State for a control period in any year, the provisions of 
subpart BBBBB of part 97 of this chapter authorizing the Administrator 
to complete the allocation and recordation of TR NOX Ozone 
Season allowances to units in the State for each such control period 
shall continue to apply, unless provided otherwise by such approval of 
the State's SIP revision.

Subpart V--Maryland

0
31. Section 52.1084 is added to read as follows:

[[Page 48367]]

Sec.  52.1084  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

    (a)(1) The owner and operator of each source and each unit located 
in the State of Maryland and for which requirements are set forth under 
the TR NOX Annual Trading Program in subpart AAAAA of part 
97 of this chapter must comply with such requirements. The obligation 
to comply with such requirements will be eliminated by the promulgation 
of an approval by the Administrator of a revision to Maryland's State 
Implementation Plan (SIP) as correcting the SIP's deficiency that is 
the basis for the TR Federal Implementation Plan under Sec.  52.38(a), 
except to the extent the Administrator's approval is partial or 
conditional.
    (2) Notwithstanding the provisions of paragraph (a)(1) of this 
section, if, at the time of the approval of Maryland's SIP revision 
described in paragraph (a)(1) of this section, the Administrator has 
already started recording any allocations of TR NOX Annual 
allowances under subpart AAAAA of part 97 of this chapter to units in 
the State for a control period in any year, the provisions of subpart 
AAAAA of part 97 of this chapter authorizing the Administrator to 
complete the allocation and recordation of TR NOX Annual 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.
    (b)(1) The owner and operator of each source and each unit located 
in the State of Maryland and for which requirements are set forth under 
the TR NOX Ozone Season Trading Program in subpart BBBBB of 
part 97 of this chapter must comply with such requirements. The 
obligation to comply with such requirements will be eliminated by the 
promulgation of an approval by the Administrator of a revision to 
Maryland's State Implementation Plan (SIP) as correcting the SIP's 
deficiency that is the basis for the TR Federal Implementation Plan 
under Sec.  52.38(b), except to the extent the Administrator's approval 
is partial or conditional.
    (2) Notwithstanding the provisions of paragraph (b)(1) of this 
section, if, at the time of the approval of Maryland's SIP revision 
described in paragraph (b)(1) of this section, the Administrator has 
already started recording any allocations of TR NOX Ozone 
Season allowances under subpart BBBBB of part 97 of this chapter to 
units in the State for a control period in any year, the provisions of 
subpart BBBBB of part 97 of this chapter authorizing the Administrator 
to complete the allocation and recordation of TR NOX Ozone 
Season allowances to units in the State for each such control period 
shall continue to apply, unless provided otherwise by such approval of 
the State's SIP revision.

0
32. Section 52.1085 is added to read as follows:

Sec.  52.1085  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of sulfur dioxide?

    (a) The owner and operator of each source and each unit located in 
the State of Maryland and for which requirements are set forth under 
the TR SO2 Group 1 Trading Program in subpart CCCCC of part 
97 of this chapter must comply with such requirements. The obligation 
to comply with such requirements will be eliminated by the promulgation 
of an approval by the Administrator of a revision to Maryland's State 
Implementation Plan (SIP) as correcting the SIP's deficiency that is 
the basis for the TR Federal Implementation Plan under Sec.  52.39, 
except to the extent the Administrator's approval is partial or 
conditional.
    (b) Notwithstanding the provisions of paragraph (a) of this 
section, if, at the time of the approval of Maryland's SIP revision 
described in paragraph (a) of this section, the Administrator has 
already started recording any allocations of TR SO2 Group 1 
allowances under subpart CCCCC of part 97 of this chapter to units in 
the State for a control period in any year, the provisions of subpart 
CCCCC of part 97 of this chapter authorizing the Administrator to 
complete the allocation and recordation of TR SO2 Group 1 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.

Subpart X--Michigan

0
33. Section 52.1186 is amended by adding new paragraphs (c) and (d) to 
read as follows:

Sec.  52.1186  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

* * * * *
    (c) Notwithstanding any provisions of paragraphs (a) and (b) of 
this section and subparts AA through II and AAAA through IIII of part 
97 of this chapter to the contrary:
    (1) With regard to any control period that begins after December 
31, 2011,
    (i) The provisions in paragraphs (a) and (b) of this section 
relating to NOX annual or ozone season emissions shall not 
be applicable; and
    (ii) The Administrator will not carry out any of the functions set 
forth for the Administrator in subparts AA through II and AAAA through 
IIII of part 97 of this chapter;
    (2) The Administrator will not deduct for excess emissions any CAIR 
NOX allowances or CAIR NOX Ozone Season 
allowances allocated for 2012 or any year thereafter;
    (3) By November 7, 2011, the Administrator will remove from the 
CAIR NOX Allowance Tracking System accounts all CAIR 
NOX allowances allocated for a control period in 2012 and 
any subsequent year, and, thereafter, no holding or surrender of CAIR 
NOX allowances will be required with regard to emissions or 
excess emissions for such control periods; and
    (4) By November 7, 2011, the Administrator will remove from the 
CAIR NOX Ozone Season Allowance Tracking System accounts all 
CAIR NOX Ozone Season allowances allocated for a control 
period in 2012 and any subsequent year, and, thereafter, no holding or 
surrender of CAIR NOX Ozone Season allowances will be 
required with regard to emissions or excess emissions for such control 
periods.
    (d)(1) The owner and operator of each source and each unit located 
in the State of Michigan and Indian country within the borders of the 
State and for which requirements are set forth under the TR 
NOX Annual Trading Program in subpart AAAAA of part 97 of 
this chapter must comply with such requirements. The obligation to 
comply with such requirements with regard to sources and units in the 
State will be eliminated by the promulgation of an approval by the 
Administrator of a revision to Michigan's State Implementation Plan 
(SIP) as correcting in part the SIP's deficiency that is the basis for 
the TR Federal Implementation Plan under Sec.  52.38(a), except to the 
extent the Administrator's approval is partial or conditional. The 
obligation to comply with such requirements with regard to sources and 
units located in Indian country within the borders of the State will 
not be eliminated by the promulgation of an approval by the 
Administrator of a revision to Michigan's SIP.
    (2) Notwithstanding the provisions of paragraph (d)(1) of this 
section, if, at the time of the approval of Michigan's SIP revision 
described in paragraph (d)(1) of this section, the Administrator has 
already started recording any allocations of TR NOX Annual 
allowances under subpart AAAAA of part 97 of this chapter to units in 
the State for a control period in any year, the provisions of

[[Page 48368]]

subpart AAAAA of part 97 of this chapter authorizing the Administrator 
to complete the allocation and recordation of TR NOX Annual 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.
    (e) [Reserved]

0
34. Section 52.1187 is amended by designating the existing text as 
paragraph (a) and adding new paragraphs (b) and (c) to read as follows:

Sec.  52.1187  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of sulfur dioxide?

* * * * *
    (b) Notwithstanding any provisions of paragraph (a) of this section 
and subparts AAA through III of part 97 of this chapter and any State's 
SIP to the contrary:
    (1) With regard to any control period that begins after December 
31, 2011,
    (i) The provisions of paragraph (a) of this section relating to 
SO2 emissions shall not be applicable; and
    (ii) The Administrator will not carry out any of the functions set 
forth for the Administrator in subparts AAA through III of part 97 of 
this chapter; and
    (2) The Administrator will not deduct for excess emissions any CAIR 
SO2 allowances allocated for 2012 or any year thereafter.
    (c)(1) The owner and operator of each source and each unit located 
in the State of Michigan and Indian country within the borders of the 
State and for which requirements are set forth under the TR 
SO2 Group 1 Trading Program in subpart CCCCC of part 97 of 
this chapter must comply with such requirements. The obligation to 
comply with such requirements with regard to sources and units in the 
State will be eliminated by the promulgation of an approval by the 
Administrator of a revision to Michigan's State Implementation Plan 
(SIP) as correcting in part the SIP's deficiency that is the basis for 
the TR Federal Implementation Plan under Sec.  52.39, except to the 
extent the Administrator's approval is partial or conditional. The 
obligation to comply with such requirements with regard to sources and 
units located in Indian country within the borders of the State will 
not be eliminated by the promulgation of an approval by the 
Administrator of a revision to Michigan's SIP.
    (2) Notwithstanding the provisions of paragraph (c)(1) of this 
section, if, at the time of the approval of Maryland's SIP revision 
described in paragraph (c)(1) of this section, the Administrator has 
already started recording any allocations of TR SO2 Group 1 
allowances under subpart CCCCC of part 97 of this chapter to units in 
the State for a control period in any year, the provisions of subpart 
CCCCC of part 97 of this chapter authorizing the Administrator to 
complete the allocation and recordation of TR SO2 Group 1 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.

Subpart Y--Minnesota

0
35. Section 52.1240 is amended by adding paragraph (c) to read as 
follows:

Sec.  52.1240  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

* * * * *
    (c)(1) The owner and operator of each source and each unit located 
in the State of Minnesota and Indian country within the borders of the 
State and for which requirements are set forth under the TR 
NOX Annual Trading Program in subpart AAAAA of part 97 of 
this chapter must comply with such requirements. The obligation to 
comply with such requirements with regard to sources and units in the 
State will be eliminated by the promulgation of an approval by the 
Administrator of a revision to Minnesota's State Implementation Plan 
(SIP) as correcting in part the SIP's deficiency that is the basis for 
the TR Federal Implementation Plan under Sec.  52.38(a), except to the 
extent the Administrator's approval is partial or conditional. The 
obligation to comply with such requirements with regard to sources and 
units located in Indian country within the borders of the State will 
not be eliminated by the promulgation of an approval by the 
Administrator of a revision to Minnesota's SIP.
    (2) Notwithstanding the provisions of paragraph (c)(1) of this 
section, if, at the time of the approval of Minnesota's SIP revision 
described in paragraph (c)(1) of this section, the Administrator has 
already started recording any allocations of TR NOX Annual 
allowances under subpart AAAAA of part 97 of this chapter to units in 
the State for a control period in any year, the provisions of subpart 
AAAAA of part 97 of this chapter authorizing the Administrator to 
complete the allocation and recordation of TR NOX Annual 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.

0
36. Section 52.1241 is amended by adding paragraph (c) to read as 
follows:

Sec.  52.1241  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of sulfur dioxide?

* * * * *
    (c)(1) The owner and operator of each source and each unit located 
in the State of Minnesota and Indian country within the borders of the 
State and for which requirements are set forth under the TR 
SO2 Group 2 Trading Program in subpart DDDDD of part 97 of 
this chapter must comply with such requirements. The obligation to 
comply with such requirements with regard to sources and units in the 
State will be eliminated by the promulgation of an approval by the 
Administrator of a revision to Minnesota's State Implementation Plan 
(SIP) as correcting in part the SIP's deficiency that is the basis for 
the TR Federal Implementation Plan under Sec.  52.39, except to the 
extent the Administrator's approval is partial or conditional. The 
obligation to comply with such requirements with regard to sources and 
units located in Indian country within the borders of the State will 
not be eliminated by the promulgation of an approval by the 
Administrator of a revision to Minnesota's SIP.
    (2) Notwithstanding the provisions of paragraph (c)(1) of this 
section, if, at the time of the approval of Minnesota's SIP revision 
described in paragraph (c)(1) of this section, the Administrator has 
already started recording any allocations of TR SO2 Group 2 
allowances under subpart DDDDD of part 97 of this chapter to units in 
the State for a control period in any year, the provisions of subpart 
DDDDD of part 97 of this chapter authorizing the Administrator to 
complete the allocation and recordation of TR SO2 Group 2 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.

Subpart Z--Mississippi

0
37. Section 52.1284 is added to read as follows:

Sec.  52.1284  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

    (a) The owner and operator of each source and each unit located in 
the State of Mississippi and Indian country within the borders of the 
State and for which requirements are set forth under the TR 
NOX Ozone Season Trading Program in subpart BBBBB of part 97 
of

[[Page 48369]]

this chapter must comply with such requirements. The obligation to 
comply with such requirements with regard to sources and units in the 
State will be eliminated by the promulgation of an approval by the 
Administrator of a revision to Mississippi's State Implementation Plan 
(SIP) as correcting in part the SIP's deficiency that is the basis for 
the TR Federal Implementation Plan under Sec.  52.38(b), except to the 
extent the Administrator's approval is partial or conditional. The 
obligation to comply with such requirements with regard to sources and 
units located in Indian country within the borders of the State will 
not be eliminated by the promulgation of an approval by the 
Administrator of a revision to Mississippi's SIP.
    (b) Notwithstanding the provisions of paragraph (a) of this 
section, if, at the time of the approval of Mississippi's SIP revision 
described in paragraph (a) of this section, the Administrator has 
already started recording any allocations of TR NOX Ozone 
Season allowances under subpart BBBBB of part 97 of this chapter to 
units in the State for a control period in any year, the provisions of 
subpart BBBBB of part 97 of this chapter authorizing the Administrator 
to complete the allocation and recordation of TR NOX Ozone 
Season allowances to units in the State for each such control period 
shall continue to apply, unless provided otherwise by such approval of 
the State's SIP revision.

Subpart AA--Missouri

0
38. Section 52.1326 is added to read as follows:

Sec.  52.1326  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

    (a)(1) The owner and operator of each source and each unit located 
in the State of Missouri and for which requirements are set forth under 
the TR NOX Annual Trading Program in subpart AAAAA of part 
97 of this chapter must comply with such requirements. The obligation 
to comply with such requirements will be eliminated by the promulgation 
of an approval by the Administrator of a revision to Missouri's State 
Implementation Plan (SIP) as correcting the SIP's deficiency that is 
the basis for the TR Federal Implementation Plan under Sec.  52.38(a), 
except to the extent the Administrator's approval is partial or 
conditional.
    (2) Notwithstanding the provisions of paragraph (a)(1) of this 
section, if, at the time of the approval of Missouri's SIP revision 
described in paragraph (a)(1) of this section, the Administrator has 
already started recording any allocations of TR NOX Annual 
allowances under subpart AAAAA of part 97 of this chapter to units in 
the State for a control period in any year, the provisions of subpart 
AAAAA of part 97 of this chapter authorizing the Administrator to 
complete the allocation and recordation of TR NOX Annual 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.
    (b) [Reserved]

0
39. Section 52.1327 is added to read as follows:

Sec.  52.1327  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of sulfur dioxide?

    (a) The owner and operator of each source and each unit located in 
the State of Missouri and for which requirements are set forth under 
the TR SO2 Group 1 Trading Program in subpart CCCCC of part 
97 of this chapter must comply with such requirements. The obligation 
to comply with such requirements will be eliminated by the promulgation 
of an approval by the Administrator of a revision to Missouri's State 
Implementation Plan (SIP) as correcting the SIP's deficiency that is 
the basis for the TR Federal Implementation Plan under Sec.  52.39, 
except to the extent the Administrator's approval is partial or 
conditional.
    (b) Notwithstanding the provisions of paragraph (a) of this 
section, if, at the time of the approval of Missouri's SIP revision 
described in paragraph (a) of this section, the Administrator has 
already started recording any allocations of TR SO2 Group 1 
allowances under subpart CCCCC of part 97 of this chapter to units in 
the State for a control period in any year, the provisions of subpart 
CCCCC of part 97 of this chapter authorizing the Administrator to 
complete the allocation and recordation of TR SO2 Group 1 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.

Subpart CC--Nebraska

0
40. Section 52.1428 is added to read as follows:

Sec.  52.1428  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

    (a) The owner and operator of each source and each unit located in 
the State of Nebraska and Indian country within the borders of the 
State and for which requirements are set forth under the TR 
NOX Annual Trading Program in subpart AAAAA of part 97 of 
this chapter must comply with such requirements. The obligation to 
comply with such requirements with regard to sources and units in the 
State will be eliminated by the promulgation of an approval by the 
Administrator of a revision to Nebraska's State Implementation Plan 
(SIP) as correcting in part the SIP's deficiency that is the basis for 
the TR Federal Implementation Plan under Sec.  52.38(a), except to the 
extent the Administrator's approval is partial or conditional. The 
obligation to comply with such requirements with regard to sources and 
units located in Indian country within the borders of the State will 
not be eliminated by the promulgation of an approval by the 
Administrator of a revision to Nebraska's SIP.
    (b) Notwithstanding the provisions of paragraph (a) of this 
section, if, at the time of the approval of Nebraska's SIP revision 
described in paragraph (a) of this section, the Administrator has 
already started recording any allocations of TR NOX Annual 
allowances under subpart AAAAA of part 97 of this chapter to units in 
the State for a control period in any year, the provisions of subpart 
AAAAA of part 97 of this chapter authorizing the Administrator to 
complete the allocation and recordation of TR NOX Annual 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.

0
41. Section 52.1429 is added to read as follows:

Sec.  52.1429  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of sulfur dioxide?

    (a) The owner and operator of each source and each unit located in 
the State of Nebraska and Indian country within the borders of the 
State and for which requirements are set forth under the TR 
SO2 Group 2 Trading Program in subpart DDDDD of part 97 of 
this chapter must comply with such requirements. The obligation to 
comply with such requirements with regard to sources and units in the 
State will be eliminated by the promulgation of an approval by the 
Administrator of a revision to Nebraska's State Implementation Plan 
(SIP) as correcting in part the SIP's deficiency that is the basis for 
the TR Federal Implementation Plan under Sec.  52.39, except to the 
extent the Administrator's approval is partial or conditional. The 
obligation to comply with such requirements with regard to

[[Page 48370]]

sources and units located in Indian country within the borders of the 
State will not be eliminated by the promulgation of an approval by the 
Administrator of a revision to Nebraska's SIP.
    (b) Notwithstanding the provisions of paragraph (a) of this 
section, if, at the time of the approval of Nebraska's SIP revision 
described in paragraph (a) of this section, the Administrator has 
already started recording any allocations of TR SO2 Group 2 
allowances under subpart DDDDD of part 97 of this chapter to units in 
the State for a control period in any year, the provisions of subpart 
DDDDD of part 97 of this chapter authorizing the Administrator to 
complete the allocation and recordation of TR SO2 Group 2 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.

Subpart FF--New Jersey

0
42. Section 52.1584 is amended by adding new paragraphs (c), (d), and 
(e) to read as follows:

Sec.  52.1584  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

* * * * *
    (c) Notwithstanding any provisions of paragraphs (a) and (b) of 
this section and subparts AA through II and AAAA through IIII of part 
97 of this chapter to the contrary:
    (1) With regard to any control period that begins after December 
31, 2011,
    (i) The provisions in paragraphs (a) and (b) of this section 
relating to NOX annual or ozone season emissions shall not 
be applicable; and
    (ii) The Administrator will not carry out any of the functions set 
forth for the Administrator in subparts AA through II and AAAA through 
IIII of part 97 of this chapter;
    (2) The Administrator will not deduct for excess emissions any CAIR 
NOX allowances or CAIR NOX Ozone Season 
allowances allocated for 2012 or any year thereafter;
    (3) By November 7, 2011, the Administrator will remove from the 
CAIR NOX Allowance Tracking System accounts all CAIR 
NOX allowances allocated for a control period in 2012 and 
any subsequent year, and, thereafter, no holding or surrender of CAIR 
NOX allowances will be required with regard to emissions or 
excess emissions for such control periods; and
    (4) By November 7, 2011, the Administrator will remove from the 
CAIR NOX Ozone Season Allowance Tracking System accounts all 
CAIR NOX Ozone Season allowances allocated for a control 
period in 2012 and any subsequent year, and, thereafter, no holding or 
surrender of CAIR NOX Ozone Season allowances will be 
required with regard to emissions or excess emissions for such control 
periods.
    (d)(1) The owner and operator of each source and each unit located 
in the State of New Jersey and for which requirements are set forth 
under the TR NOX Annual Trading Program in subpart AAAAA of 
part 97 of this chapter must comply with such requirements. The 
obligation to comply with such requirements will be eliminated by the 
promulgation of an approval by the Administrator of a revision to New 
Jersey's State Implementation Plan (SIP) as correcting the SIP's 
deficiency that is the basis for the TR Federal Implementation Plan 
under Sec.  52.38(a), except to the extent the Administrator's approval 
is partial or conditional.
    (2) Notwithstanding the provisions of paragraph (d)(1) of this 
section, if, at the time of the approval of New Jersey's SIP revision 
described in paragraph (d)(1) of this section, the Administrator has 
already started recording any allocations of TR NOX Annual 
allowances under subpart AAAAA of part 97 of this chapter to units in 
the State for a control period in any year, the provisions of subpart 
AAAAA of part 97 of this chapter authorizing the Administrator to 
complete the allocation and recordation of TR NOX Annual 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.
    (e)(1) The owner and operator of each source and each unit located 
in the State of New Jersey and for which requirements are set forth 
under the TR NOX Ozone Season Trading Program in subpart 
BBBBB of part 97 of this chapter must comply with such requirements. 
The obligation to comply with such requirements will be eliminated by 
the promulgation of an approval by the Administrator of a revision to 
New Jersey's State Implementation Plan (SIP) as correcting the SIP's 
deficiency that is the basis for the TR Federal Implementation Plan 
under Sec.  52.38(b), except to the extent the Administrator's approval 
is partial or conditional.
    (2) Notwithstanding the provisions of paragraph (e)(1) of this 
section, if, at the time of the approval of New Jersey's SIP revision 
described in paragraph (e)(1) of this section, the Administrator has 
already started recording any allocations of TR NOX Ozone 
Season allowances under subpart BBBBB of part 97 of this chapter to 
units in the State for a control period in any year, the provisions of 
subpart BBBBB of part 97 of this chapter authorizing the Administrator 
to complete the allocation and recordation of TR NOX Ozone 
Season allowances to units in the State for each such control period 
shall continue to apply, unless provided otherwise by such approval of 
the State's SIP revision.

0
43. Section 52.1585 is amended by designating the existing text as 
paragraph (a) and adding new paragraphs (b) and (c) to read as follows:

Sec.  52.1585  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of sulfur dioxide?

* * * * *
    (b) Notwithstanding any provisions of paragraph (a) of this section 
and subparts AAA through III of part 97 of this chapter and any State's 
SIP to the contrary:
    (1) With regard to any control period that begins after December 
31, 2011,
    (i) The provisions of paragraph (a) of this section relating to 
SO2 emissions shall not be applicable; and
    (ii) The Administrator will not carry out any of the functions set 
forth for the Administrator in subparts AAA through III of part 97 of 
this chapter; and
    (2) The Administrator will not deduct for excess emissions any CAIR 
SO2 allowances allocated for 2012 or any year thereafter.
    (c)(1) The owner and operator of each source and each unit located 
in the State of New Jersey and for which requirements are set forth 
under the TR SO2 Group 1 Trading Program in subpart CCCCC of 
part 97 of this chapter must comply with such requirements. The 
obligation to comply with such requirements will be eliminated by the 
promulgation of an approval by the Administrator of a revision to New 
Jersey's State Implementation Plan (SIP) as correcting the SIP's 
deficiency that is the basis for the TR Federal Implementation Plan 
under Sec.  52.39, except to the extent the Administrator's approval is 
partial or conditional.
    (2) Notwithstanding the provisions of paragraph (c)(1) of this 
section, if, at the time of the approval of New Jersey's SIP revision 
described in paragraph (c)(1) of this section, the Administrator has 
already started recording any allocations of TR SO2 Group 1 
allowances under subpart CCCCC of part 97 of this chapter to units in 
the State for a control period in any year, the provisions of subpart 
CCCCC of part 97 of this chapter authorizing the Administrator to 
complete the allocation and recordation

[[Page 48371]]

of TR SO2 Group 1 allowances to units in the State for each 
such control period shall continue to apply, unless provided otherwise 
by such approval of the State's SIP revision.

Subpart HH--New York

0
44. Section 52.1684 is revised to read as follows:

Sec.  52.1684  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

    (a)(1) The owner and operator of each source and each unit located 
in the State of New York and Indian country within the borders of the 
State and for which requirements are set forth under the TR 
NOX Annual Trading Program in subpart AAAAA of part 97 of 
this chapter must comply with such requirements. The obligation to 
comply with such requirements with regard to sources and units in the 
State will be eliminated by the promulgation of an approval by the 
Administrator of a revision to New York's State Implementation Plan 
(SIP) as correcting in part the SIP's deficiency that is the basis for 
the TR Federal Implementation Plan under Sec.  52.38(a), except to the 
extent the Administrator's approval is partial or conditional. The 
obligation to comply with such requirements with regard to sources and 
units located in Indian country within the borders of the State will 
not be eliminated by the promulgation of an approval by the 
Administrator of a revision to New York's SIP.
    (2) Notwithstanding the provisions of paragraph (a)(1) of this 
section, if, at the time of the approval of New York's SIP revision 
described in paragraph (a)(1) of this section, the Administrator has 
already started recording any allocations of TR NOX Annual 
allowances under subpart AAAAA of part 97 of this chapter to units in 
the State for a control period in any year, the provisions of subpart 
AAAAA of part 97 of this chapter authorizing the Administrator to 
complete the allocation and recordation of TR NOX Annual 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.
    (b)(1) The owner and operator of each source and each unit located 
in the State of New York and Indian country within the borders of the 
State and for which requirements are set forth under the TR 
NOX Ozone Season Trading Program in subpart BBBBB of part 97 
of this chapter must comply with such requirements. The obligation to 
comply with such requirements with regard to sources and units in the 
State will be eliminated by the promulgation of an approval by the 
Administrator of a revision to New York's State Implementation Plan 
(SIP) as correcting in part the SIP's deficiency that is the basis for 
the TR Federal Implementation Plan under Sec.  52.38(b), except to the 
extent the Administrator's approval is partial or conditional. The 
obligation to comply with such requirements with regard to sources and 
units located in Indian country within the borders of the State will 
not be eliminated by the promulgation of an approval by the 
Administrator of a revision to New York's SIP.
    (2) Notwithstanding the provisions of paragraph (b)(1) of this 
section, if, at the time of the approval of New York's SIP revision 
described in paragraph (b)(1) of this section, the Administrator has 
already started recording any allocations of TR NOX Ozone 
Season allowances under subpart BBBBB of part 97 of this chapter to 
units in the State for a control period in any year, the provisions of 
subpart BBBBB of part 97 of this chapter authorizing the Administrator 
to complete the allocation and recordation of TR NOX Ozone 
Season allowances to units in the State for each such control period 
shall continue to apply, unless provided otherwise by such approval of 
the State's SIP revision.

0
45. Section 52.1685 is added to read as follows:

Sec.  52.1685  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of sulfur dioxide?

    (a) The owner and operator of each source and each unit located in 
the State of New York and Indian country within the borders of the 
State and for which requirements are set forth under the TR 
SO2 Group 1 Trading Program in subpart CCCCC of part 97 of 
this chapter must comply with such requirements. The obligation to 
comply with such requirements with regard to sources and units in the 
State will be eliminated by the promulgation of an approval by the 
Administrator of a revision to New York's State Implementation Plan 
(SIP) as correcting in part the SIP's deficiency that is the basis for 
the TR Federal Implementation Plan under Sec.  52.39, except to the 
extent the Administrator's approval is partial or conditional. The 
obligation to comply with such requirements with regard to sources and 
units located in Indian country within the borders of the State will 
not be eliminated by the promulgation of an approval by the 
Administrator of a revision to New York's SIP.
    (b) Notwithstanding the provisions of paragraph (a) of this 
section, if, at the time of the approval of New York's SIP revision 
described in paragraph (a) of this section, the Administrator has 
already started recording any allocations of TR SO2 Group 1 
allowances under subpart CCCCC of part 97 of this chapter to units in 
the State for a control period in any year, the provisions of subpart 
CCCCC of part 97 of this chapter authorizing the Administrator to 
complete the allocation and recordation of TR SO2 Group 1 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.

Subpart II--North Carolina

0
46. Section 52.1784 is revised to read as follows:

Sec.  52.1784  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

    (a)(1) The owner and operator of each source and each unit located 
in the State of North Carolina and Indian country within the borders of 
the State and for which requirements are set forth under the TR 
NOX Annual Trading Program in subpart AAAAA of part 97 of 
this chapter must comply with such requirements. The obligation to 
comply with such requirements with regard to sources and units in the 
State will be eliminated by the promulgation of an approval by the 
Administrator of a revision to North Carolina's State Implementation 
Plan (SIP) as correcting in part the SIP's deficiency that is the basis 
for the TR Federal Implementation Plan under Sec.  52.38(a), except to 
the extent the Administrator's approval is partial or conditional. The 
obligation to comply with such requirements with regard to sources and 
units located in Indian country within the borders of the State will 
not be eliminated by the promulgation of an approval by the 
Administrator of a revision to North Carolina's SIP.
    (2) Notwithstanding the provisions of paragraph (a)(1) of this 
section, if, at the time of the approval of North Carolina's SIP 
revision described in paragraph (a)(1) of this section, the 
Administrator has already started recording any allocations of TR 
NOX Annual allowances under subpart AAAAA of part 97 of this 
chapter to units in the State for a control period in any year, the 
provisions of subpart AAAAA of part 97 of this chapter authorizing the 
Administrator to complete the allocation and recordation of TR 
NOX Annual allowances to units in the State for each such 
control period shall

[[Page 48372]]

continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.
    (b)(1) The owner and operator of each source and each unit located 
in the State of North Carolina and Indian country within the borders of 
the State and for which requirements are set forth under the TR 
NOX Ozone Season Trading Program in subpart BBBBB of part 97 
of this chapter must comply with such requirements. The obligation to 
comply with such requirements with regard to sources and units in the 
State will be eliminated by the promulgation of an approval by the 
Administrator of a revision to North Carolina's State Implementation 
Plan (SIP) as correcting in part the SIP's deficiency that is the basis 
for the TR Federal Implementation Plan under Sec.  52.38(b), except to 
the extent the Administrator's approval is partial or conditional. The 
obligation to comply with such requirements with regard to sources and 
units located in Indian country within the borders of the State will 
not be eliminated by the promulgation of an approval by the 
Administrator of a revision to North Carolina's SIP.
    (2) Notwithstanding the provisions of paragraph (b)(1) of this 
section, if, at the time of the approval of North Carolina's SIP 
revision described in paragraph (b)(1) of this section, the 
Administrator has already started recording any allocations of TR 
NOX Ozone Season allowances under subpart BBBBB of part 97 
of this chapter to units in the State for a control period in any year, 
the provisions of subpart BBBBB of part 97 of this chapter authorizing 
the Administrator to complete the allocation and recordation of TR 
NOX Ozone Season allowances to units in the State for each 
such control period shall continue to apply, unless provided otherwise 
by such approval of the State's SIP revision.

0
47. Section 52.1785 is revised to read as follows:

Sec.  52.1785  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of sulfur dioxide?

    (a) The owner and operator of each source and each unit located in 
the State of North Carolina and Indian country within the borders of 
the State and for which requirements are set forth under the TR 
SO2 Group 1 Trading Program in subpart CCCCC of part 97 of 
this chapter must comply with such requirements. The obligation to 
comply with such requirements with regard to sources and units in the 
State will be eliminated by the promulgation of an approval by the 
Administrator of a revision to North Carolina's State Implementation 
Plan (SIP) as correcting in part the SIP's deficiency that is the basis 
for the TR Federal Implementation Plan under Sec.  52.39, except to the 
extent the Administrator's approval is partial or conditional. The 
obligation to comply with such requirements with regard to sources and 
units located in Indian country within the borders of the State will 
not be eliminated by the promulgation of an approval by the 
Administrator of a revision to North Carolina's SIP.
    (b) Notwithstanding the provisions of paragraph (a) of this 
section, if, at the time of the approval of North Carolina's SIP 
revision described in paragraph (a) of this section, the Administrator 
has already started recording any allocations of TR SO2 
Group 1 allowances under subpart CCCCC of part 97 of this chapter to 
units in the State for a control period in any year, the provisions of 
subpart CCCCC of part 97 of this chapter authorizing the Administrator 
to complete the allocation and recordation of TR SO2 Group 1 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.

Subpart KK--Ohio

0
48. Section 52.1882 is added to read as follows:

Sec.  52.1882  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

    (a)(1) The owner and operator of each source and each unit located 
in the State of Ohio and for which requirements are set forth under the 
TR NOX Annual Trading Program in subpart AAAAA of part 97 of 
this chapter must comply with such requirements. The obligation to 
comply with such requirements will be eliminated by the promulgation of 
an approval by the Administrator of a revision to Ohio's State 
Implementation Plan (SIP) as correcting the SIP's deficiency that is 
the basis for the TR Federal Implementation Plan under Sec.  52.38(a), 
except to the extent the Administrator's approval is partial or 
conditional.
    (2) Notwithstanding the provisions of paragraph (a)(1) of this 
section, if, at the time of the approval of Ohio's SIP revision 
described in paragraph (a)(1) of this section, the Administrator has 
already started recording any allocations of TR NOX Annual 
allowances under subpart AAAAA of part 97 of this chapter to units in 
the State for a control period in any year, the provisions of subpart 
AAAAA of part 97 of this chapter authorizing the Administrator to 
complete the allocation and recordation of TR NOX Annual 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.
    (b)(1) The owner and operator of each source and each unit located 
in the State of Ohio and for which requirements are set forth under the 
TR NOX Ozone Season Trading Program in subpart BBBBB of part 
97 of this chapter must comply with such requirements. The obligation 
to comply with such requirements will be eliminated by the promulgation 
of an approval by the Administrator of a revision to Ohio's State 
Implementation Plan (SIP) as correcting the SIP's deficiency that is 
the basis for the TR Federal Implementation Plan under Sec.  52.38(b), 
except to the extent the Administrator's approval is partial or 
conditional.
    (2) Notwithstanding the provisions of paragraph (b)(1) of this 
section, if, at the time of the approval of Ohio's SIP revision 
described in paragraph (b)(1) of this section, the Administrator has 
already started recording any allocations of TR NOX Ozone 
Season allowances under subpart BBBBB of part 97 of this chapter to 
units in the State for a control period in any year, the provisions of 
subpart BBBBB of part 97 of this chapter authorizing the Administrator 
to complete the allocation and recordation of TR NOX Ozone 
Season allowances to units in the State for each such control period 
shall continue to apply, unless provided otherwise by such approval of 
the State's SIP revision.

0
49. Section 52.1883 is added to read as follows:

Sec.  52.1883  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of sulfur dioxide?

    (a) The owner and operator of each source and each unit located in 
the State of Ohio and for which requirements are set forth under the TR 
SO2 Group 1 Trading Program in subpart CCCCC of part 97 of 
this chapter must comply with such requirements. The obligation to 
comply with such requirements will be eliminated by the promulgation of 
an approval by the Administrator of a revision to Ohio's State 
Implementation Plan (SIP) as correcting the SIP's deficiency that is 
the basis for the TR Federal Implementation Plan under Sec.  52.39, 
except to the extent the Administrator's approval is partial or 
conditional.
    (b) Notwithstanding the provisions of paragraph (a) of this 
section, if, at the time of the approval of Ohio's SIP

[[Page 48373]]

revision described in paragraph (a) of this section, the Administrator 
has already started recording any allocations of TR SO2 
Group 1 allowances under subpart CCCCC of part 97 of this chapter to 
units in the State for a control period in any year, the provisions of 
subpart CCCCC of part 97 of this chapter authorizing the Administrator 
to complete the allocation and recordation of TR SO2 Group 1 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.

Subpart NN--Pennsylvania

0
50. Section 52.2040 is added to read as follows:

Sec.  52.2040  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

    (a)(1) The owner and operator of each source and each unit located 
in the State of Pennsylvania and for which requirements are set forth 
under the TR NOX Annual Trading Program in subpart AAAAA of 
part 97 of this chapter must comply with such requirements. The 
obligation to comply with such requirements will be eliminated by the 
promulgation of an approval by the Administrator of a revision to 
Pennsylvania's State Implementation Plan (SIP) as correcting the SIP's 
deficiency that is the basis for the TR Federal Implementation Plan 
under Sec.  52.38(a), except to the extent the Administrator's approval 
is partial or conditional.
    (2) Notwithstanding the provisions of paragraph (a)(1) of this 
section, if, at the time of the approval of Pennsylvania's SIP revision 
described in paragraph (a)(1) of this section, the Administrator has 
already started recording any allocations of TR NOX Annual 
allowances under subpart AAAAA of part 97 of this chapter to units in 
the State for a control period in any year, the provisions of subpart 
AAAAA of part 97 of this chapter authorizing the Administrator to 
complete the allocation and recordation of TR NOX Annual 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.
    (b)(1) The owner and operator of each source and each unit located 
in the State of Pennsylvania and for which requirements are set forth 
under the TR NOX Ozone Season Trading Program in subpart 
BBBBB of part 97 of this chapter must comply with such requirements. 
The obligation to comply with such requirements will be eliminated by 
the promulgation of an approval by the Administrator of a revision to 
Pennsylvania's State Implementation Plan (SIP) as correcting the SIP's 
deficiency that is the basis for the TR Federal Implementation Plan 
under Sec.  52.38(b), except to the extent the Administrator's approval 
is partial or conditional.
    (2) Notwithstanding the provisions of paragraph (b)(1) of this 
section, if, at the time of the approval of Pennsylvania's SIP revision 
described in paragraph (b)(1) of this section, the Administrator has 
already started recording any allocations of TR NOX Ozone 
Season allowances under subpart BBBBB of part 97 of this chapter to 
units in the State for a control period in any year, the provisions of 
subpart BBBBB of part 97 of this chapter authorizing the Administrator 
to complete the allocation and recordation of TR NOX Ozone 
Season allowances to units in the State for each such control period 
shall continue to apply, unless provided otherwise by such approval of 
the State's SIP revision.

0
51. Section 52.2041 is added to read as follows:

Sec.  52.2041  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of sulfur dioxide?

    (a) The owner and operator of each source and each unit located in 
the State of Pennsylvania and for which requirements are set forth 
under the TR SO2 Group 1 Trading Program in subpart CCCCC of 
part 97 of this chapter must comply with such requirements. The 
obligation to comply with such requirements will be eliminated by the 
promulgation of an approval by the Administrator of a revision to 
Pennsylvania's State Implementation Plan (SIP) as correcting the SIP's 
deficiency that is the basis for the TR Federal Implementation Plan 
under Sec.  52.39, except to the extent the Administrator's approval is 
partial or conditional.
    (b) Notwithstanding the provisions of paragraph (a) of this 
section, if, at the time of the approval of Pennsylvania's SIP revision 
described in paragraph (a) of this section, the Administrator has 
already started recording any allocations of TR SO2 Group 1 
allowances under subpart CCCCC of part 97 of this chapter to units in 
the State for a control period in any year, the provisions of subpart 
CCCCC of part 97 of this chapter authorizing the Administrator to 
complete the allocation and recordation of TR SO2 Group 1 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.

Subpart PP--South Carolina

0
52. Section 52.2140 is revised to read as follows:

Sec.  52.2140  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

    (a)(1) The owner and operator of each source and each unit located 
in the State of South Carolina and Indian country within the borders of 
the State and for which requirements are set forth under the TR 
NOX Annual Trading Program in subpart AAAAA of part 97 of 
this chapter must comply with such requirements. The obligation to 
comply with such requirements with regard to sources and units in the 
State will be eliminated by the promulgation of an approval by the 
Administrator of a revision to South Carolina's State Implementation 
Plan (SIP) as correcting in part the SIP's deficiency that is the basis 
for the TR Federal Implementation Plan under Sec.  52.38(a), except to 
the extent the Administrator's approval is partial or conditional. The 
obligation to comply with such requirements with regard to sources and 
units located in Indian country within the borders of the State will 
not be eliminated by the promulgation of an approval by the 
Administrator of a revision to South Carolina's SIP.
    (2) Notwithstanding the provisions of paragraph (a)(1) of this 
section, if, at the time of the approval of South Carolina's SIP 
revision described in paragraph (a)(1) of this section, the 
Administrator has already started recording any allocations of TR 
NOX Annual allowances under subpart AAAAA of part 97 of this 
chapter to units in the State for a control period in any year, the 
provisions of subpart AAAAA of part 97 of this chapter authorizing the 
Administrator to complete the allocation and recordation of TR 
NOX Annual allowances to units in the State for each such 
control period shall continue to apply, unless provided otherwise by 
such approval of the State's SIP revision.
    (b)(1) The owner and operator of each source and each unit located 
in the State of South Carolina and Indian country within the borders of 
the State and for which requirements are set forth under the TR 
NOX Ozone Season Trading Program in subpart BBBBB of part 97 
of this chapter must comply with such requirements. The obligation to 
comply with such requirements with regard to sources and units in the 
State will be

[[Page 48374]]

eliminated by the promulgation of an approval by the Administrator of a 
revision to South Carolina's State Implementation Plan (SIP) as 
correcting in part the SIP's deficiency that is the basis for the TR 
Federal Implementation Plan under Sec.  52.38(b), except to the extent 
the Administrator's approval is partial or conditional. The obligation 
to comply with such requirements with regard to sources and units 
located in Indian country within the borders of the State will not be 
eliminated by the promulgation of an approval by the Administrator of a 
revision to South Carolina's SIP.
    (2) Notwithstanding the provisions of paragraph (b)(1) of this 
section, if, at the time of the approval of South Carolina's SIP 
revision described in paragraph (b)(1) of this section, the 
Administrator has already started recording any allocations of TR 
NOX Ozone Season allowances under subpart BBBBB of part 97 
of this chapter to units in the State for a control period in any year, 
the provisions of subpart BBBBB of part 97 of this chapter authorizing 
the Administrator to complete the allocation and recordation of TR 
NOX Ozone Season allowances to units in the State for each 
such control period shall continue to apply, unless provided otherwise 
by such approval of the State's SIP revision.

0
53. Section 52.2141 is revised to read as follows:

Sec.  52.2141  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of sulfur dioxide?

    (a) The owner and operator of each source and each unit located in 
the State of South Carolina and Indian country within the borders of 
the State and for which requirements are set forth under the TR 
SO2 Group 2 Trading Program in subpart DDDDD of part 97 of 
this chapter must comply with such requirements. The obligation to 
comply with such requirements with regard to sources and units in the 
State will be eliminated by the promulgation of an approval by the 
Administrator of a revision to South Carolina's State Implementation 
Plan (SIP) as correcting in part the SIP's deficiency that is the basis 
for the TR Federal Implementation Plan under Sec.  52.39, except to the 
extent the Administrator's approval is partial or conditional. The 
obligation to comply with such requirements with regard to sources and 
units located in Indian country within the borders of the State will 
not be eliminated by the promulgation of an approval by the 
Administrator of a revision to South Carolina's SIP.
    (b) Notwithstanding the provisions of paragraph (a) of this 
section, if, at the time of the approval of South Carolina's SIP 
revision described in paragraph (a) of this section, the Administrator 
has already started recording any allocations of TR SO2 
Group 1 allowances under subpart CCCCC of part 97 of this chapter to 
units in the State for a control period in any year, the provisions of 
subpart CCCCC of part 97 of this chapter authorizing the Administrator 
to complete the allocation and recordation of TR SO2 Group 1 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.

Subpart RR--Tennessee

0
54. Section 52.2240 is amended by adding new paragraphs (c), (d), and 
(e) to read as follows:

Sec.  52.2240  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

* * * * *
    (c) Notwithstanding any provisions of paragraphs (a) and (b) of 
this section and subparts AA through II and AAAA through IIII of part 
97 of this chapter to the contrary:
    (1) With regard to any control period that begins after December 
31, 2011,
    (i) The provisions in paragraphs (a) and (b) of this section 
relating to NOX annual or ozone season emissions shall not 
be applicable; and
    (ii) The Administrator will not carry out any of the functions set 
forth for the Administrator in subparts AA through II and AAAA through 
IIII of part 97 of this chapter; and
    (2) The Administrator will not deduct for excess emissions any CAIR 
NOX allowances or CAIR NOX Ozone Season 
allowances allocated for 2012 or any year thereafter;
    (3) By November 7, 2011, the Administrator will remove from the 
CAIR NOX Allowance Tracking System accounts all CAIR 
NOX allowances allocated for a control period in 2012 and 
any subsequent year, and, thereafter, no holding or surrender of CAIR 
NOX allowances will be required with regard to emissions or 
excess emissions for such control periods; and
    (4) By November 7, 2011, the Administrator will remove from the 
CAIR NOX Ozone Season Allowance Tracking System accounts all 
CAIR NOX Ozone Season allowances allocated for a control 
period in 2012 and any subsequent year, and, thereafter, no holding or 
surrender of CAIR NOX Ozone Season allowances will be 
required with regard to emissions or excess emissions for such control 
periods.
    (d)(1) The owner and operator of each source and each unit located 
in the State of Tennessee and for which requirements are set forth 
under the TR NOX Annual Trading Program in subpart AAAAA of 
part 97 of this chapter must comply with such requirements. The 
obligation to comply with such requirements will be eliminated by the 
promulgation of an approval by the Administrator of a revision to 
Tennessee's State Implementation Plan (SIP) as correcting the SIP's 
deficiency that is the basis for the TR Federal Implementation Plan 
under Sec.  52.38(a), except to the extent the Administrator's approval 
is partial or conditional. The obligation to comply with such 
requirements with regard to sources and units located in Indian country 
within the borders of the State will not be eliminated by the 
promulgation of an approval by the Administrator of a revision to 
Tennessee's SIP.
    (2) Notwithstanding the provisions of paragraph (d)(1) of this 
section, if, at the time of the approval of Tennessee's SIP revision 
described in paragraph (d)(1) of this section, the Administrator has 
already started recording any allocations of TR NOX Annual 
allowances under subpart AAAAA of part 97 of this chapter to units in 
the State for a control period in any year, the provisions of subpart 
AAAAA of part 97 of this chapter authorizing the Administrator to 
complete the allocation and recordation of TR NOX Annual 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.
    (e)(1) The owner and operator of each source and each unit located 
in the State of Tennessee and for which requirements are set forth 
under the TR NOX Ozone Season Trading Program in subpart 
BBBBB of part 97 of this chapter must comply with such requirements. 
The obligation to comply with such requirements will be eliminated by 
the promulgation of an approval by the Administrator of a revision to 
Tennessee's State Implementation Plan (SIP) as correcting the SIP's 
deficiency that is the basis for the TR Federal Implementation Plan 
under Sec.  52.38(b), except to the extent the Administrator's approval 
is partial or conditional. The obligation to comply with such 
requirements with regard to sources and units located in Indian country 
within the borders of the State will not be eliminated by the 
promulgation of an

[[Page 48375]]

approval by the Administrator of a revision to Tennessee's SIP.
    (2) Notwithstanding the provisions of paragraph (e)(1) of this 
section, if, at the time of the approval of Tennessee's SIP revision 
described in paragraph (e)(1) of this section, the Administrator has 
already started recording any allocations of TR NOX Ozone 
Season allowances under subpart BBBBB of part 97 of this chapter to 
units in the State for a control period in any year, the provisions of 
subpart BBBBB of part 97 of this chapter authorizing the Administrator 
to complete the allocation and recordation of TR NOX Ozone 
Season allowances to units in the State for each such control period 
shall continue to apply, unless provided otherwise by such approval of 
the State's SIP revision.

0
55. Section 52.2241 is amended by designating the existing text as 
paragraph (a) and adding new paragraphs (b) and (c) to read as follows:

Sec.  52.2241  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of sulfur dioxide?

* * * * *
    (b) Notwithstanding any provisions of paragraph (a) of this section 
and subparts AAA through III of part 97 of this chapter and any State's 
SIP to the contrary:
    (1) With regard to any control period that begins after December 
31, 2011,
    (i) The provisions of paragraph (a) of this section relating to 
SO2 emissions shall not be applicable; and
    (ii) The Administrator will not carry out any of the functions set 
forth for the Administrator in subparts AAA through III of part 97 of 
this chapter; and
    (2) The Administrator will not deduct for excess emissions any CAIR 
SO2 allowances allocated for 2012 or any year thereafter.
    (c)(1) The owner and operator of each source and each unit located 
in the State of Tennessee and for which requirements are set forth 
under the TR SO2 Group 1 Trading Program in subpart CCCCC of 
part 97 of this chapter must comply with such requirements. The 
obligation to comply with such requirements will be eliminated by the 
promulgation of an approval by the Administrator of a revision to 
Tennessee's State Implementation Plan (SIP) as correcting the SIP's 
deficiency that is the basis for the TR Federal Implementation Plan 
under Sec.  52.39, except to the extent the Administrator's approval is 
partial or conditional. The obligation to comply with such requirements 
with regard to sources and units located in Indian country within the 
borders of the State will not be eliminated by the promulgation of an 
approval by the Administrator of a revision to Tennessee's SIP.
    (2) Notwithstanding the provisions of paragraph (c)(1) of this 
section, if, at the time of the approval of Tennessee's SIP revision 
described in paragraph (c)(1) of this section, the Administrator has 
already started recording any allocations of TR SO2 Group 1 
allowances under subpart CCCCC of part 97 of this chapter to units in 
the State for a control period in any year, the provisions of subpart 
CCCCC of part 97 of this chapter authorizing the Administrator to 
complete the allocation and recordation of TR SO2 Group 1 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.

Subpart SS--Texas

0
56. Section 52.2283 is amended by adding new paragraphs (b), (c) and 
(d) to read as follows:

Sec.  52.2283  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

* * * * *
    (b) Notwithstanding any provisions of paragraph (a) of this section 
and subparts AA through II of part 97 of this chapter to the contrary:
    (1) With regard to any control period that begins after December 
31, 2011,
    (i) The provisions in paragraph (a) of this section relating to 
NOX annual emissions shall not be applicable; and
    (ii) The Administrator will not carry out any of the functions set 
forth for the Administrator in subparts AA through II of part 97 of 
this chapter;
    (2) The Administrator will not deduct for excess emissions any CAIR 
NOX allowances allocated for 2012 or any year thereafter;
    (3) By November 7, 2011, the Administrator will remove from the 
CAIR NOX Allowance Tracking System accounts all CAIR 
NOX allowances allocated for a control period in 2012 and 
any subsequent year, and, thereafter, no holding or surrender of CAIR 
NOX allowances will be required with regard to emissions or 
excess emissions for such control periods.
    (c)(1) The owner and operator of each source and each unit located 
in the State of Texas and Indian country within the borders of the 
State and for which requirements are set forth under the TR 
NOX Annual Trading Program in subpart AAAAA of part 97 of 
this chapter must comply with such requirements. The obligation to 
comply with such requirements with regard to sources and units in the 
State will be eliminated by the promulgation of an approval by the 
Administrator of a revision to Texas' State Implementation Plan (SIP) 
as correcting in part the SIP's deficiency that is the basis for the TR 
Federal Implementation Plan under Sec.  52.38(a), except to the extent 
the Administrator's approval is partial or conditional. The obligation 
to comply with such requirements with regard to sources and units 
located in Indian country within the borders of the State will not be 
eliminated by the promulgation of an approval by the Administrator of a 
revision to Texas' SIP.
    (2) Notwithstanding the provisions of paragraph (c)(1) of this 
section, if, at the time of the approval of Texas' SIP revision 
described in paragraph (c)(1) of this section, the Administrator has 
already started recording any allocations of TR NOX Annual 
allowances under subpart AAAAA of part 97 of this chapter to units in 
the State for a control period in any year, the provisions of subpart 
AAAAA of part 97 of this chapter authorizing the Administrator to 
complete the allocation and recordation of TR NOX Annual 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.
    (d)(1) The owner and operator of each source and each unit located 
in the State of Texas and Indian country within the borders of the 
State and for which requirements are set forth under the TR 
NOX Ozone Season Trading Program in subpart BBBBB of part 97 
of this chapter must comply with such requirements. The obligation to 
comply with such requirements with regard to sources and units in the 
State will be eliminated by the promulgation of an approval by the 
Administrator of a revision to Texas' State Implementation Plan (SIP) 
as correcting in part the SIP's deficiency that is the basis for the TR 
Federal Implementation Plan under Sec.  52.38(b), except to the extent 
the Administrator's approval is partial or conditional. The obligation 
to comply with such requirements with regard to sources and units 
located in Indian country within the borders of the State will not be 
eliminated by the promulgation of an approval by the Administrator of a 
revision to Texas' SIP.
    (2) Notwithstanding the provisions of paragraph (d)(1) of this 
section, if, at the time of the approval of Texas' SIP revision 
described in paragraph (d)(1) of this section, the Administrator has 
already started recording any allocations of TR NOX Ozone 
Season allowances under subpart BBBBB of part 97 of this

[[Page 48376]]

chapter to units in the State for a control period in any year, the 
provisions of subpart BBBBB of part 97 of this chapter authorizing the 
Administrator to complete the allocation and recordation of TR 
NOX Ozone Season allowances to units in the State for each 
such control period shall continue to apply, unless provided otherwise 
by such approval of the State's SIP revision.

0
57. Section 52.2284 is amended by designating the existing text as 
paragraph (a) and adding new paragraphs (b) and (c) to read as follows:

Sec.  52.2284  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of sulfur dioxide?

* * * * *
    (b) Notwithstanding any provisions of paragraph (a) of this section 
and subparts AAA through III of part 97 of this chapter and any State's 
SIP to the contrary:
    (1) With regard to any control period that begins after December 
31, 2011,
    (i) The provisions of paragraph (a) of this section relating to 
SO2 emissions shall not be applicable; and
    (ii) The Administrator will not carry out any of the functions set 
forth for the Administrator in subparts AAA through III of part 97 of 
this chapter; and
    (2) The Administrator will not deduct for excess emissions any CAIR 
SO2 allowances allocated for 2012 or any year thereafter.
    (c)(1) The owner and operator of each source and each unit located 
in the State of Texas and Indian country within the borders of the 
State and for which requirements are set forth under the TR 
SO2 Group 2 Trading Program in subpart DDDDD of part 97 of 
this chapter must comply with such requirements. The obligation to 
comply with such requirements with regard to sources and units in the 
State will be eliminated by the promulgation of an approval by the 
Administrator of a revision to Texas' State Implementation Plan (SIP) 
as correcting in part the SIP's deficiency that is the basis for the TR 
Federal Implementation Plan under Sec.  52.39, except to the extent the 
Administrator's approval is partial or conditional. The obligation to 
comply with such requirements with regard to sources and units located 
in Indian country within the borders of the State will not be 
eliminated by the promulgation of an approval by the Administrator of a 
revision to Texas' SIP.
    (2) Notwithstanding the provisions of paragraph (c)(1) of this 
section, if, at the time of the approval of Texas' SIP revision 
described in paragraph (c)(1) of this section, the Administrator has 
already started recording any allocations of TR SO2 Group 2 
allowances under subpart DDDDD of part 97 of this chapter to units in 
the State for a control period in any year, the provisions of subpart 
DDDDD of part 97 of this chapter authorizing the Administrator to 
complete the allocation and recordation of TR SO2 Group 2 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.

Subpart VV--Virginia

0
58. Section 52.2440 is added to read as follows:

Sec.  52.2440  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

    (a)(1) The owner and operator of each source and each unit located 
in the State of Virginia and for which requirements are set forth under 
the TR NOX Annual Trading Program in subpart AAAAA of part 
97 of this chapter must comply with such requirements. The obligation 
to comply with such requirements will be eliminated by the promulgation 
of an approval by the Administrator of a revision to Virginia's State 
Implementation Plan (SIP) as correcting the SIP's deficiency that is 
the basis for the TR Federal Implementation Plan under Sec.  52.38(a), 
except to the extent the Administrator's approval is partial or 
conditional.
    (2) Notwithstanding the provisions of paragraph (a)(1) of this 
section, if, at the time of the approval of Virginia's SIP revision 
described in paragraph (a)(1) of this section, the Administrator has 
already started recording any allocations of TR NOX Annual 
allowances under subpart AAAAA of part 97 of this chapter to units in 
the State for a control period in any year, the provisions of subpart 
AAAAA of part 97 of this chapter authorizing the Administrator to 
complete the allocation and recordation of TR NOX Annual 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.
    (b)(1) The owner and operator of each source and each unit located 
in the State of Virginia and for which requirements are set forth under 
the TR NOX Ozone Season Trading Program in subpart BBBBB of 
part 97 of this chapter must comply with such requirements. The 
obligation to comply with such requirements will be eliminated by the 
promulgation of an approval by the Administrator of a revision to 
Virginia's State Implementation Plan (SIP) as correcting the SIP's 
deficiency that is the basis for the TR Federal Implementation Plan 
under Sec.  52.38(b), except to the extent the Administrator's approval 
is partial or conditional.
    (2) Notwithstanding the provisions of paragraph (b)(1) of this 
section, if, at the time of the approval of Virginia's SIP revision 
described in paragraph (b)(1) of this section, the Administrator has 
already started recording any allocations of TR NOX Ozone 
Season allowances under subpart BBBBB of part 97 of this chapter to 
units in the State for a control period in any year, the provisions of 
subpart BBBBB of part 97 of this chapter authorizing the Administrator 
to complete the allocation and recordation of TR NOX Ozone 
Season allowances to units in the State for each such control period 
shall continue to apply, unless provided otherwise by such approval of 
the State's SIP revision.

0
59. Section 52.2241 is added to read as follows:

Sec.  52.2241  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of sulfur dioxide?

    (a) The owner and operator of each source and each unit located in 
the State of Virginia and for which requirements are set forth under 
the TR SO2 Group 1 Trading Program in subpart CCCCC of part 
97 of this chapter must comply with such requirements. The obligation 
to comply with such requirements will be eliminated by the promulgation 
of an approval by the Administrator of a revision to Virginia's State 
Implementation Plan (SIP) as correcting the SIP's deficiency that is 
the basis for the TR Federal Implementation Plan under Sec.  52.39, 
except to the extent the Administrator's approval is partial or 
conditional.
    (b) Notwithstanding the provisions of paragraph (a) of this 
section, if, at the time of the approval of Virginia's SIP revision 
described in paragraph (a) of this section, the Administrator has 
already started recording any allocations of TR SO2 Group 1 
allowances under subpart CCCCC of part 97 of this chapter to units in 
the State for a control period in any year, the provisions of subpart 
CCCCC of part 97 of this chapter authorizing the Administrator to 
complete the allocation and recordation of TR SO2 Group 1 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.

[[Page 48377]]

Subpart XX--West Virginia

0
60. Section 52.2540 is added to read as follows:

Sec.  52.2540  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

    (a)(1) The owner and operator of each source and each unit located 
in the State of West Virginia and for which requirements are set forth 
under the TR NOX Annual Trading Program in subpart AAAAA of 
part 97 of this chapter must comply with such requirements. The 
obligation to comply with such requirements will be eliminated by the 
promulgation of an approval by the Administrator of a revision to West 
Virginia's State Implementation Plan (SIP) as correcting the SIP's 
deficiency that is the basis for the TR Federal Implementation Plan 
under Sec.  52.38(a), except to the extent the Administrator's approval 
is partial or conditional.
    (2) Notwithstanding the provisions of paragraph (a)(1) of this 
section, if, at the time of the approval of West Virginia's SIP 
revision described in paragraph (a)(1) of this section, the 
Administrator has already started recording any allocations of TR 
NOX Annual allowances under subpart AAAAA of part 97 of this 
chapter to units in the State for a control period in any year, the 
provisions of subpart AAAAA of part 97 of this chapter authorizing the 
Administrator to complete the allocation and recordation of TR 
NOX Annual allowances to units in the State for each such 
control period shall continue to apply, unless provided otherwise by 
such approval of the State's SIP revision.
    (b)(1) The owner and operator of each source and each unit located 
in the State of West Virginia and for which requirements are set forth 
under the TR NOX Ozone Season Trading Program in subpart 
BBBBB of part 97 of this chapter must comply with such requirements. 
The obligation to comply with such requirements will be eliminated by 
the promulgation of an approval by the Administrator of a revision to 
West Virginia's State Implementation Plan (SIP) as correcting the SIP's 
deficiency that is the basis for the TR Federal Implementation Plan 
under Sec.  52.38(b), except to the extent the Administrator's approval 
is partial or conditional.
    (2) Notwithstanding the provisions of paragraph (b)(1) of this 
section, if, at the time of the approval of West Virginia's SIP 
revision described in paragraph (b)(1) of this section, the 
Administrator has already started recording any allocations of TR 
NOX Ozone Season allowances under subpart BBBBB of part 97 
of this chapter to units in the State for a control period in any year, 
the provisions of subpart BBBBB of part 97 of this chapter authorizing 
the Administrator to complete the allocation and recordation of TR 
NOX Ozone Season allowances to units in the State for each 
such control period shall continue to apply, unless provided otherwise 
by such approval of the State's SIP revision.

0
61. Section 52.2541 is added to read as follows:

Sec.  52.2541  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of sulfur dioxide?

    (a) The owner and operator of each source and each unit located in 
the State of West Virginia and for which requirements are set forth 
under the TR SO2 Group 1 Trading Program in subpart CCCCC of 
part 97 of this chapter must comply with such requirements. The 
obligation to comply with such requirements will be eliminated by the 
promulgation of an approval by the Administrator of a revision to West 
Virginia's State Implementation Plan (SIP) as correcting the SIP's 
deficiency that is the basis for the TR Federal Implementation Plan 
under Sec.  52.39, except to the extent the Administrator's approval is 
partial or conditional.
    (b) Notwithstanding the provisions of paragraph (a) of this 
section, if, at the time of the approval of West Virginia's SIP 
revision described in paragraph (a) of this section, the Administrator 
has already started recording any allocations of TR SO2 
Group 1 allowances under subpart CCCCC of part 97 of this chapter to 
units in the State for a control period in any year, the provisions of 
subpart CCCCC of part 97 of this chapter authorizing the Administrator 
to complete the allocation and recordation of TR SO2 Group 1 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.

Subpart YY--Wisconsin

0
62. Section 52.2587 is amended by adding new paragraphs (c) and (d) to 
read as follows:

Sec.  52.2587  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of nitrogen oxides?

* * * * *
    (c) Notwithstanding any provisions of paragraphs (a) and (b) of 
this section and subparts AA through II and AAAA through IIII of part 
97 of this chapter to the contrary:
    (1) With regard to any control period that begins after December 
31, 2011,
    (i) The provisions in paragraphs (a) and (b) of this section 
relating to NOX annual or ozone season emissions shall not 
be applicable; and
    (ii) The Administrator will not carry out any of the functions set 
forth for the Administrator in subparts AA through II and AAAA through 
IIII of part 97 of this chapter; and
    (2) The Administrator will not deduct for excess emissions any CAIR 
NOX allowances or CAIR NOX Ozone Season 
allowances allocated for 2012 or any year thereafter;
    (3) By November 7, 2011, the Administrator will remove from the 
CAIR NOX Allowance Tracking System accounts all CAIR 
NOX allowances allocated for a control period in 2012 and 
any subsequent year, and, thereafter, no holding or surrender of CAIR 
NOX allowances will be required with regard to emissions or 
excess emissions for such control periods; and
    (4) By November 7, 2011, the Administrator will remove from the 
CAIR NOX Ozone Season Allowance Tracking System accounts all 
CAIR NOX Ozone Season allowances allocated for a control 
period in 2012 and any subsequent year, and, thereafter, no holding or 
surrender of CAIR NOX Ozone Season allowances will be 
required with regard to emissions or excess emissions for such control 
periods.
    (d)(1) The owner and operator of each source and each unit located 
in the State of Wisconsin and Indian country within the borders of the 
State and for which requirements are set forth under the TR 
NOX Annual Trading Program in subpart AAAAA of part 97 of 
this chapter must comply with such requirements. The obligation to 
comply with such requirements with regard to sources and units in the 
State will be eliminated by the promulgation of an approval by the 
Administrator of a revision to Wisconsin's State Implementation Plan 
(SIP) as correcting in part the SIP's deficiency that is the basis for 
the TR Federal Implementation Plan under Sec.  52.38(a), except to the 
extent the Administrator's approval is partial or conditional. The 
obligation to comply with such requirements with regard to sources and 
units located in Indian country within the borders of the State will 
not be eliminated by the promulgation of an approval by the 
Administrator of a revision to Wisconsin's SIP.
    (2) Notwithstanding the provisions of paragraph (d)(1) of this 
section, if, at the

[[Page 48378]]

time of the approval of Wisconsin's SIP revision described in paragraph 
(d)(1) of this section, the Administrator has already started recording 
any allocations of TR NOX Annual allowances under subpart 
AAAAA of part 97 of this chapter to units in the State for a control 
period in any year, the provisions of subpart AAAAA of part 97 of this 
chapter authorizing the Administrator to complete the allocation and 
recordation of TR NOX Annual allowances to units in the 
State for each such control period shall continue to apply, unless 
provided otherwise by such approval of the State's SIP revision.

0
63. Section 52.2588 is amended by designating the existing text as 
paragraph (a) and adding new paragraphs (b) and (c) to read as follows:

Sec.  52.2588  Interstate pollutant transport provisions; What are the 
FIP requirements for decreases in emissions of sulfur dioxide?

* * * * *
    (b) Notwithstanding any provisions of paragraph (a) of this section 
and subparts AAA through III of part 97 of this chapter and any State's 
SIP to the contrary:
    (1) With regard to any control period that begins after December 
31, 2011,
    (i) The provisions of paragraph (a) of this section relating to 
SO2 emissions shall not be applicable; and
    (ii) The Administrator will not carry out any of the functions set 
forth for the Administrator in subparts AAA through III of part 97 of 
this chapter; and
    (2) The Administrator will not deduct for excess emissions any CAIR 
SO2 allowances allocated for 2012 or any year thereafter.
    (c)(1) The owner and operator of each source and each unit located 
in the State of Wisconsin and Indian country within the borders of the 
State and for which requirements are set forth under the TR 
SO2 Group 1 Trading Program in subpart CCCCC of part 97 of 
this chapter must comply with such requirements. The obligation to 
comply with such requirements with regard to sources and units in the 
State will be eliminated by the promulgation of an approval by the 
Administrator of a revision to Wisconsin's State Implementation Plan 
(SIP) as correcting in part the SIP's deficiency that is the basis for 
the TR Federal Implementation Plan under Sec.  52.39, except to the 
extent the Administrator's approval is partial or conditional. The 
obligation to comply with such requirements with regard to sources and 
units located in Indian country within the borders of the State will 
not be eliminated by the promulgation of an approval by the 
Administrator of a revision to Wisconsin's SIP.
    (2) Notwithstanding the provisions of paragraph (c)(1) of this 
section, if, at the time of the approval of Wisconsin's SIP revision 
described in paragraph (c)(1) of this section, the Administrator has 
already started recording any allocations of TR SO2 Group 1 
allowances under subpart CCCCC of part 97 of this chapter to units in 
the State for a control period in any year, the provisions of subpart 
CCCCC of part 97 of this chapter authorizing the Administrator to 
complete the allocation and recordation of TR SO2 Group 1 
allowances to units in the State for each such control period shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP revision.

PART 72--[AMENDED]

0
64. The authority citation for part 72 is revised to read as follows:

    Authority:  42 U.S.C. 7401, 7403, 7410, 7411, 7426, 7601, et 
seq.

Sec.  72.2  [Amended]

0
65. Section 72.2 is amended by removing the definition of ``Interested 
person''.

PART 78--[AMENDED]

0
66. The authority citation for part 78 continues to read as follows:

    Authority:  42 U.S.C. 7401, 7403, 7410, 7411, 7426, 7601, et 
seq.

0
67. Section 78.1 is amended by adding paragraphs (b)(13) through 
(b)(16) to read as follows:

Sec.  78.1  Purpose and scope.

* * * * *
    (b) * * *
    (13) Under subpart AAAAA of part 97 of this chapter,
    (i) The decision on allocation of TR NOX Annual 
allowances under Sec.  97.411(a)(2) and (b) of this chapter.
    (ii) The decision on the transfer of TR NOX Annual 
allowances under Sec.  97.423 of this chapter.
    (iii) The decision on the deduction of TR NOX Annual 
allowances under Sec. Sec.  97.424 and 97.425 of this chapter.
    (iv) The correction of an error in an Allowance Management System 
account under Sec.  97.427 of this chapter.
    (v) The adjustment of information in a submission and the decision 
on the deduction and transfer of TR NOX Annual allowances 
based on the information as adjusted under Sec.  97.428 of this 
chapter.
    (vi) The finalization of control period emissions data, including 
retroactive adjustment based on audit.
    (vii) The approval or disapproval of a petition under Sec.  97.435 
of this chapter.
    (14) Under subpart BBBBB of part 97 of this chapter,
    (i) The decision on allocation of TR NOX Ozone Season 
allowances under Sec.  97.511(a)(2) and (b) of this chapter.
    (ii) The decision on the transfer of TR NOX Ozone Season 
allowances under Sec.  97.523 of this chapter.
    (iii) The decision on the deduction of TR NOX Ozone 
Season allowances under Sec. Sec.  97.524 and 97.525 of this chapter.
    (iv) The correction of an error in an Allowance Management System 
account under Sec.  97.527 of this chapter.
    (v) The adjustment of information in a submission and the decision 
on the deduction and transfer of TR NOX Ozone Season 
allowances based on the information as adjusted under Sec.  97.528 of 
this chapter.
    (vi) The finalization of control period emissions data, including 
retroactive adjustment based on audit.
    (vii) The approval or disapproval of a petition under Sec.  97.535 
of this chapter.
    (15) Under subpart CCCCC of part 97 of this chapter,
    (i) The decision on allocation of TR SO2 Group 1 
allowances under Sec.  97.611(a)(2) and (b) of this chapter.
    (ii) The decision on the transfer of TR SO2 Group 1 
allowances under Sec.  97.623 of this chapter.
    (iii) The decision on the deduction of TR SO2 Group 1 
allowances under Sec. Sec.  97.624 and 97.625 of this chapter.
    (iv) The correction of an error in an Allowance Management System 
account under Sec.  97.627 of this chapter.
    (v) The adjustment of information in a submission and the decision 
on the deduction and transfer of TR SO2 Group 1 allowances 
based on the information as adjusted under Sec.  97.628 of this 
chapter.
    (vi) The finalization of control period emissions data, including 
retroactive adjustment based on audit.
    (vii) The approval or disapproval of a petition under Sec.  97.635 
of this chapter.
    (16) Under subpart DDDDD of part 97 of this chapter,
    (i) The decision on allocation of TR SO2 Group 2 
allowances under Sec.  97.711(a)(2) and (b) of this chapter.
    (ii) The decision on the transfer of TR SO2 Group 1 
allowances under Sec.  97.723 of this chapter.
    (iii) The decision on the deduction of TR SO2 Group 1 
allowances under Sec. Sec.  97.724 and 97.725 of this chapter.
    (iv) The correction of an error in an Allowance Management System 
account under Sec.  97.727 of this chapter.
    (v) The adjustment of information in a submission and the decision 
on the

[[Page 48379]]

deduction and transfer of TR SO2 Group 1 allowances based on 
the information as adjusted under Sec.  97.728 of this chapter.
    (vi) The finalization of control period emissions data, including 
retroactive adjustment based on audit.
    (vii) The approval or disapproval of a petition under Sec.  97.735 
of this chapter.
* * * * *

0
68. Section 78.2 is revised to read as follows:

Sec.  78.2  General.

    (a) Definitions. (1) The terms used in this subpart with regard to 
a decision of the Administrator that is appealed under this section 
shall have the meaning as set forth in the regulations under which the 
Administrator made such decision and as set forth in paragraph (a)(2) 
of this section.
    (2) Interested person means, with regard to a decision of the 
Administrator:
    (i) Any person who submitted comments, or testified at a public 
hearing, pursuant to an opportunity for comment provided by the 
Administrator as part of the process of making such decision;
    (ii) Who submitted objections pursuant to an opportunity for 
objections provided by the Administrator as part of the process of 
making such decision; or
    (iii) Who submitted, to the Administrator and in a format 
prescribed by the Administrator, his or her name, service address, 
telephone number, and facsimile number and identified such decision in 
order to be placed on a list of persons interested in such decision;
    (iv) Provided that the Administrator may update the list of 
interested persons from time to time by requesting additional written 
indication of continued interest from the persons listed and may delete 
from the list the name of any person failing to respond as requested.
    (b) Availability of information. The availability to the public of 
information provided to, or otherwise obtained by, the Administrator 
under this subpart shall be governed by part 2 of this chapter.
    (c) Computation of time. (1) In computing any period of time 
prescribed or allowed under this part, except as otherwise provided, 
the day of the event from which the period begins to run shall not be 
included, and Saturdays, Sundays, and federal holidays shall be 
included. When the period ends on a Saturday, Sunday, or federal 
holiday, the stated period shall be extended to include the next 
business day.
    (2) Where a document is served by first class mail or commercial 
delivery service, but not by overnight or same-day delivery, 5 days 
shall be added to the time prescribed or allowed under this part for 
the filing of a responsive document or for otherwise responding.

0
69. Section 78.3 is amended by:
0
a. In paragraphs (a)(1)(iii), (a)(3)(ii), (a)(4)(ii), (a)(5)(ii), 
(a)(6)(ii), (a)(7)(ii), (a)(8)(ii), and (a)(9)(ii), adding, after the 
word ``person'', the words ``with regard to the decision''.
0
b. Adding paragraph (a)(10);
0
c. In paragraph (b)(3)(i), removing the words ``paragraph (a)(1) and 
(2)'' and adding, in their place, the words ``paragraph (a)(1), (2), 
and (10)''; and
0
d. Adding paragraph (d)(11) to read as follows:

Sec.  78.3  Petition for administrative review and request or 
evidentiary hearing.

    (a) * * *
    (10) The following persons may petition for administrative review 
of a decision of the Administrator that is made under subparts AAAAA, 
BBBBB, CCCCC, and DDDDD of part 97 of this chapter:
    (i) The designated representative for a unit or source, or the 
authorized account representative for any Allowance Management System 
account, covered by the decision; or
    (ii) Any interested person with regard to the decision.
* * * * *
    (d) * * *
    (11) Any provision or requirement of subparts AAAAA, BBBBB, CCCCC, 
or DDDDD of part 97 of this chapter, including the standard 
requirements under Sec.  97.406, Sec.  97.506, Sec.  97.606, or Sec.  
97.706 of this chapter and any emission monitoring or reporting 
requirements.
* * * * *

0
70. Section 78.4 is amended by:
0
a. Revising paragraph (a) by:
0
i. Removing the first, second, third, fourth, fifth, and last 
sentences;
0
ii. In the sixth and seventh sentences, removing the words ``interest 
in'' and adding, in their place, the words ``ownership interest with 
respect to'';
0
iii. Redesignating the paragraph as paragraph (a)(1)(iii); and
0
b. Adding paragraphs (a)(1) introductory text, (a)(1)(i), and 
(a)(1)(ii); and
0
c. Revising paragraph (a)(2) to read as follows:

Sec.  78.4  Filings.

    (a)(1) All original filings made under this part shall be signed by 
the person making the filing or by an attorney or authorized 
representative, in accordance with the following requirements:
    (i) Any filings on behalf of owners and operators of a affected 
unit or affected source, TR NOX Annual unit or TR 
NOX Annual source, TR NOX Ozone Season unit or TR 
NOX Ozone Season source, TR SO2 Group 1 unit or 
TR SO2 Group 1 source, TR SO2 Group 2 unit or TR 
SO2 Group 2 source, or a unit for which a TR opt-in 
application is submitted and not withdrawn shall be signed by the 
designated representative. Any filing on behalf of persons with an 
ownership interest with respect to allowances, TR NOX Annual 
allowances, TR NOX Ozone Season allowances, TR 
SO2 Group 1 allowances, or TR SO2 Group 2 
allowances in a general account shall be signed by the authorized 
account representative.
    (ii) Any filings on behalf of owners and operators of a 
NOX Budget unit or NOX Budget source shall be 
signed by the NOX authorized account representative. Any 
filing on behalf of persons with an ownership interest with respect to 
NOX allowances in a general account shall be signed by the 
NOX authorized account representative.
* * * * *
    (2) The name, address, e-mail address (if any), telephone number, 
and facsimile number (if any) of the person making the filing shall be 
provided with the filing.
* * * * *

Sec.  78.5  [Amended]

0
71. Section 78.5 is amended by, in paragraph (a):
0
a. Removing the words ``public comment prior to'' and adding, in their 
place, the words ``submission of public comments or objections prior 
to'';
0
b. Removing the words ``public comment period'' whenever they appear 
and adding, in their place, the words ``period for submission of public 
comments or objections''.

Sec.  78.12  [Amended]

0
72. Section 78.12 is amended by, in paragraph (a), removing the words 
``public comment'' and adding, in their place, the words ``submission 
of public comments or objections''.

PART 97--[AMENDED]

0
73. The authority citation for part 97 continues to read as follows:
    Authority: 42 U.S.C. 7401, 7403, 7410, 7426, 7601, and 7651, et 
seq.

0
74. Part 97 is amended by adding subpart AAAAA to read as follows:

[[Page 48380]]

Subpart AAAAA--TR NOX Annual Trading Program
97.401 Purpose.
97.402 Definitions.
97.403 Measurements, abbreviations, and acronyms.
97.404 Applicability.
97.405 Retired unit exemption.
97.406 Standard requirements.
97.407 Computation of time.
97.408 Administrative appeal procedures.
97.409 [Reserved]
97.410 State NOX Annual trading budgets, new unit set-
asides, Indian country new unit set-asides and variability limits.
97.411 Timing requirements for TR NOX Annual allowance 
allocations.
97.412 TR NOX Annual allowance allocations to new units.
97.413 Authorization of designated representative and alternate 
designated representative.
97.414 Responsibilities of designated representative and alternate 
designated representative.
97.415 Changing designated representative and alternate designated 
representative; changes in owners and operators.
97.416 Certificate of representation.
97.417 Objections concerning designated representative and alternate 
designated representative.
97.418 Delegation by designated representative and alternate 
designated representative.
97.419 [Reserved]
97.420 Establishment of compliance accounts and general accounts.
97.421 Recordation of TR NOX Annual allowance 
allocations.
97.422 Submission of TR NOX Annual allowance transfers.
97.423 Recordation of TR NOX Annual allowance transfers.
97.424 Compliance with TR NOX Annual emissions 
limitation.
97.425 Compliance with TR NOX Annual assurance 
provisions.
97.426 Banking.
97.427 Account error.
97.428 Administrator's action on submissions.
97.429 [RESERVED]
97.430 General monitoring, recordkeeping, and reporting 
requirements.
97.431 Initial monitoring system certification and recertification 
procedures.
97.432 Monitoring system out-of-control periods.
97.433 Notifications concerning monitoring.
97.434 Recordkeeping and reporting.
97.435 Petitions for alternatives to monitoring, recordkeeping, or 
reporting requirements.

Subpart AAAAA--TR NOX Annual Trading Program

Sec.  97.401  Purpose.

    This subpart sets forth the general, designated representative, 
allowance, and monitoring provisions for the Transport Rule (TR) 
NOX Annual Trading Program, under section 110 of the Clean 
Air Act and Sec.  52.38 of this chapter, as a means of mitigating 
interstate transport of fine particulates and nitrogen oxides.

Sec.  97.402  Definitions.

    The terms used in this subpart shall have the meanings set forth in 
this section as follows:
    Acid Rain Program means a multi-state SO2 and 
NOX air pollution control and emission reduction program 
established by the Administrator under title IV of the Clean Air Act 
and parts 72 through 78 of this chapter.
    Administrator means the Administrator of the United States 
Environmental Protection Agency or the Director of the Clean Air 
Markets Division (or its successor determined by the Administrator) of 
the United States Environmental Protection Agency, the Administrator's 
duly authorized representative under this subpart.
    Allocate or allocation means, with regard to TR NOX 
Annual allowances, the determination by the Administrator, State, or 
permitting authority, in accordance with this subpart and any SIP 
revision submitted by the State and approved by the Administrator under 
Sec.  52.38(a)(3), (4), or (5) of this chapter, of the amount of such 
TR NOX Annual allowances to be initially credited, at no 
cost to the recipient, to:
    (1) A TR NOX Annual unit;
    (2) A new unit set-aside;
    (3) An Indian country new unit set-aside; or
    (4) An entity not listed in paragraphs (1) through (3) of this 
definition;
    (5) Provided that, if the Administrator, State, or permitting 
authority initially credits, to a TR NOX Annual unit 
qualifying for an initial credit, a credit in the amount of zero TR 
NOX Annual allowances, the TR NOX Annual unit 
will be treated as being allocated an amount (i.e., zero) of TR 
NOX Annual allowances.
    Allowable NOX emission rate means, for a unit, the most 
stringent State or federal NOX emission rate limit (in lb/
MWhr or, if in lb/mmBtu, converted to lb/MWhr by multiplying it by the 
unit's heat rate in mmBtu/MWhr) that is applicable to the unit and 
covers the longest averaging period not exceeding one year.
    Allowance Management System means the system by which the 
Administrator records allocations, deductions, and transfers of TR 
NOX Annual allowances under the TR NOX Annual 
Trading Program. Such allowances are allocated, recorded, held, 
deducted, or transferred only as whole allowances.
    Allowance Management System account means an account in the 
Allowance Management System established by the Administrator for 
purposes of recording the allocation, holding, transfer, or deduction 
of TR NOX Annual allowances.
    Allowance transfer deadline means, for a control period in a given 
year, midnight of March 1 (if it is a business day), or midnight of the 
first business day thereafter (if March 1 is not a business day), 
immediately after such control period and is the deadline by which a TR 
NOX Annual allowance transfer must be submitted for 
recordation in a TR NOX Annual source's compliance account 
in order to be available for use in complying with the source's TR 
NOX Annual emissions limitation for such control period in 
accordance with Sec. Sec.  97.406 and 97.424.
    Alternate designated representative means, for a TR NOX 
Annual source and each TR NOX Annual 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 this 
subpart, to act on behalf of the designated representative in matters 
pertaining to the TR NOX Annual Trading Program. If the TR 
NOX Annual source is also subject to the Acid Rain Program, 
TR NOX Ozone Season Trading Program, TR SO2 Group 
1 Trading Program, or TR SO2 Group 2 Trading Program, then 
this natural person shall be the same natural person as the alternate 
designated representative, as defined in the respective program.
    Assurance account means an Allowance Management System account, 
established by the Administrator under Sec.  97.425(b)(3) for certain 
owners and operators of a group of one or more TR NOX Annual 
sources and units in a given State (and Indian country within the 
borders of such State), in which are held TR NOX Annual 
allowances available for use for a control period in a given year in 
complying with the TR NOX Annual assurance provisions in 
accordance with Sec. Sec.  97.406 and 97.425.
    Authorized account representative means, for a general account, the 
natural person who is authorized, in accordance with this subpart, to 
transfer and otherwise dispose of TR NOX Annual allowances 
held in the general account and, for a TR NOX Annual 
source's compliance account, the designated representative of the 
source.
    Automated data acquisition and handling system or DAHS means the 
component of the continuous emission monitoring system, or other 
emissions monitoring system approved for use

[[Page 48381]]

under this subpart, 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 this subpart.
    Biomass means--
    (1) Any organic material grown for the purpose of being converted 
to energy;
    (2) Any organic byproduct of agriculture that can be converted into 
energy; or
    (3) Any material that can be converted into energy and is 
nonmerchantable for other purposes, that is segregated from other 
material that is nonmerchantable for other purposes, and that is;
    (i) A forest-related organic resource, including mill residues, 
precommercial thinnings, slash, brush, or byproduct from conversion of 
trees to merchantable material; or
    (ii) A wood material, including pallets, crates, dunnage, 
manufacturing and construction materials (other than pressure-treated, 
chemically-treated, or painted wood products), and landscape or right-
of-way tree trimmings.
    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 unit means a unit in which the energy input to the 
unit is first used to produce useful thermal energy, where at least 
some of the reject heat from the useful thermal energy application or 
process is then used for electricity production.
    Business day means a day that does not fall on a weekend or a 
federal holiday.
    Certifying official means a natural person who is:
    (1) For a corporation, a president, secretary, treasurer, or vice-
president of the corporation in charge of a principal business function 
or any other person who performs similar policy- or decision-making 
functions for the corporation;
    (2) For a partnership or sole proprietorship, a general partner or 
the proprietor respectively; or
    (3) For a local government entity or State, federal, or other 
public agency, a principal executive officer or ranking elected 
official.
    Clean Air Act means the Clean Air Act, 42 U.S.C. 7401, et seq.
    Coal means ``coal'' as defined in Sec.  72.2 of this chapter.
    Coal-derived fuel means any fuel (whether in a solid, liquid, or 
gaseous state) produced by the mechanical, thermal, or chemical 
processing of coal.
    Cogeneration system means an integrated group, at a source, of 
equipment (including a boiler, or combustion turbine, and a steam 
turbine generator) designed to produce useful thermal energy for 
industrial, commercial, heating, or cooling purposes and electricity 
through the sequential use of energy.
    Cogeneration unit means a stationary, fossil-fuel-fired boiler or 
stationary, fossil-fuel-fired combustion turbine that is a topping-
cycle unit or a bottoming-cycle unit:
    (1) Operating as part of a cogeneration system; and
    (2) Producing on an annual average basis--
    (i) For a topping-cycle 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 than 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 unit, useful power not less than 45 
percent of total energy input;
    (3) Provided that the requirements in paragraph (2) of this 
definition shall not apply to a calendar year referenced in paragraph 
(2) of this definition during which the unit did not operate at all;
    (4) Provided that the total energy input under paragraphs (2)(i)(B) 
and (2)(ii) of this definition shall equal the unit's total energy 
input from all fuel, except biomass if the unit is a boiler; and
    (5) Provided that, if, throughout its operation during the 12-month 
period or a calendar year referenced in paragraph (2) of this 
definition, a unit is operated as part of a cogeneration system and the 
cogeneration system meets on a system-wide basis the requirement in 
paragraph (2)(i)(B) or (2)(ii) of this definition, the unit shall be 
deemed to meet such requirement during that 12-month period or calendar 
year.
    Combustion turbine means an enclosed device comprising:
    (1) If the device is simple cycle, 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 device is combined cycle, the equipment described in 
paragraph (1) of this definition and any associated duct burner, heat 
recovery steam generator, and steam turbine.
    Commence commercial operation means, with regard to a unit:
    (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.  97.405.
    (i) For a unit that is a TR NOX Annual unit under Sec.  
97.404 on the later of January 1, 2005 or the date the unit commences 
commercial operation as defined in the introductory text of paragraph 
(1) of this definition and that subsequently undergoes a physical 
change or is moved to a new location or source, such date shall remain 
the date of commencement of commercial operation of the unit, which 
shall continue to be treated as the same unit.
    (ii) For a unit that is a TR NOX Annual unit under Sec.  
97.404 on the later of January 1, 2005 or the date the unit commences 
commercial operation as defined in the introductory text of paragraph 
(1) of this definition and that is subsequently replaced by a unit at 
the same or a different source, such date shall remain the replaced 
unit's date of commencement of commercial operation, and the 
replacement unit shall be treated as a separate unit with a separate 
date for commencement of commercial operation as defined in paragraph 
(1) or (2) of this definition as appropriate.
    (2) Notwithstanding paragraph (1) of this definition and except as 
provided in Sec.  97.405, for a unit that is not a TR NOX 
Annual unit under Sec.  97.404 on the later of January 1, 2005 or the 
date the unit commences commercial operation as defined in introductory 
text of paragraph (1) of this definition, the unit's date for 
commencement of commercial operation shall be the date on which the 
unit becomes a TR NOX Annual unit under Sec.  97.404.
    (i) For a unit with a date for commencement of commercial operation 
as defined in the introductory text of paragraph (2) of this definition 
and that subsequently undergoes a physical change or is moved to a 
different location or source, such date shall remain the date of 
commencement of commercial operation of the unit, which shall continue 
to be treated as the same unit.
    (ii) For a unit with a date for commencement of commercial 
operation as defined in the introductory text of paragraph (2) of this 
definition and that is subsequently replaced by a unit at the same or a 
different source, such date shall remain the replaced unit's date of 
commencement of commercial operation, and the replacement unit shall be 
treated as a separate unit with a separate date for

[[Page 48382]]

commencement of commercial operation as defined in paragraph (1) or (2) 
of this definition as appropriate.
    Common designated representative means, with regard to a control 
period in a given year, a designated representative where, as of April 
1 immediately after the allowance transfer deadline for such control 
period, the same natural person is authorized under Sec. Sec.  
97.413(a) and 97.415(a) as the designated representative for a group of 
one or more TR NOX Annual sources and units located in a 
State (and Indian country within the borders of such State).
    Common designated representative's assurance level means, with 
regard to a specific common designated representative and a State (and 
Indian country within the borders of such State) and control period in 
a given year for which the State assurance level is exceeded as 
described in Sec.  97.406(c)(2)(iii), the common designated 
representative's share of the State NOX Annual trading 
budget with the variability limit for the State for such control 
period.
    Common designated representative's share means, with regard to a 
specific common designated representative for a control period in a 
given year:
    (1) With regard to a total amount of NOX emissions from 
all TR NOX Annual units in a State (and Indian country 
within the borders of such State) during such control period, the total 
tonnage of NOX emissions during such control period from a 
group of one or more TR NOX Annual units located in such 
State (and such Indian country) and having the common designated 
representative for such control period;
    (2) With regard to a State NOX Annual trading budget 
with the variability limit for such control period, the amount (rounded 
to the nearest allowance) equal to the sum of the total amount of TR 
NOX Annual allowances allocated for such control period to a 
group of one or more TR NOX Annual units located in the 
State (and Indian country within the borders of such State) and having 
the common designated representative for such control period and of the 
total amount of TR NOX Annual allowances purchased by an 
owner or operator of such TR NOX Annual units in an auction 
for such control period and submitted by the State or the permitting 
authority to the Administrator for recordation in the compliance 
accounts for such TR NOX Annual units in accordance with the 
TR NOX Annual allowance auction provisions in a SIP revision 
approved by the Administrator under Sec.  52.38(a)(4) or (5) of this 
chapter, multiplied by the sum of the State NOX Annual 
trading budget under Sec.  97.410(a) and the State's variability limit 
under Sec.  97.410(b) for such control period and divided by such State 
NOX Annual trading budget;
    (3) Provided that, in the case of a unit that operates during, but 
has no amount of TR NOX Annual allowances allocated under 
Sec. Sec.  97.411 and 97.412 for, such control period, the unit shall 
be treated, solely for purposes of this definition, as being allocated 
an amount (rounded to the nearest allowance) of TR NOX 
Annual allowances for such control period equal to the unit's allowable 
NOX emission rate applicable to such control period, 
multiplied by a capacity factor of 0.85 (if the unit is a boiler 
combusting any amount of coal or coal-derived fuel during such control 
period), 0.24 (if the unit is a simple combustion turbine during such 
control period), 0.67 (if the unit is a combined cycle turbine during 
such control period), 0.74 (if the unit is an integrated coal 
gasification combined cycle unit during such control period), or 0.36 
(for any other unit), multiplied by the unit's maximum hourly load as 
reported in accordance with this subpart and by 8,760 hours/control 
period, and divided by 2,000 lb/ton.
    Common stack means a single flue through which emissions from 2 or 
more units are exhausted.
    Compliance account means an Allowance Management System account, 
established by the Administrator for a TR NOX Annual source 
under this subpart, in which any TR NOX Annual allowance 
allocations to the TR NOX Annual units at the source are 
recorded and in which are held any TR NOX Annual allowances 
available for use for a control period in a given year in complying 
with the source's TR NOX Annual emissions limitation in 
accordance with Sec. Sec.  97.406 and 97.424.
    Continuous emission monitoring system or CEMS means the equipment 
required under this subpart to sample, analyze, measure, and provide, 
by means of readings recorded at least once every 15 minutes and using 
an automated data acquisition and handling system (DAHS), a permanent 
record of NOX emissions, stack gas volumetric flow rate, 
stack gas moisture content, and O2 or CO2 
concentration (as applicable), in a manner consistent with part 75 of 
this chapter and Sec. Sec.  97.430 through 97.435. The following 
systems are the principal types of continuous emission monitoring 
systems:
    (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 NOX 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 NOX 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 CO2 monitoring system, consisting of a 
CO2 pollutant concentration monitor (or an O2 
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 O2 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 starting January 1 of a calendar 
year, except as provided in Sec.  97.406(c)(3), and ending on December 
31 of the same year, inclusive.
    Designated representative means, for a TR NOX Annual 
source and each TR NOX Annual 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 this 
subpart, to represent and legally bind each owner and operator in 
matters pertaining to the TR NOX Annual Trading Program. If 
the TR NOX Annual source is also subject to the Acid Rain 
Program, TR NOX Ozone Season Trading Program, TR 
SO2 Group 1 Trading Program, or TR SO2 Group 2 
Trading Program, then this natural person shall be the same natural 
person as the designated representative, as defined in the respective 
program.
    Emissions means air pollutants exhausted from a unit or source into 
the atmosphere, as measured, recorded, and

[[Page 48383]]

reported to the Administrator by the designated representative, and as 
modified by the Administrator:
    (1) In accordance with this subpart; and
    (2) With regard to a period before the unit or source is required 
to measure, record, and report such air pollutants in accordance with 
this subpart, in accordance with part 75 of this chapter.
    Excess emissions means any ton of emissions from the TR 
NOX Annual units at a TR NOX Annual source during 
a control period in a given year that exceeds the TR NOX 
Annual emissions limitation for the source for such control period.
    Fossil fuel means--
    (1) Natural gas, petroleum, coal, or any form of solid, liquid, or 
gaseous fuel derived from such material; or
    (2) For purposes of applying the limitation on ``average annual 
fuel consumption of fossil fuel'' in Sec. Sec.  97.404(b)(2)(i)(B) and 
(ii), natural gas, petroleum, coal, or any form of solid, liquid, or 
gaseous fuel derived from such material for the purpose of creating 
useful heat.
    Fossil-fuel-fired means, with regard to a unit, combusting any 
amount of fossil fuel in 2005 or any calendar year thereafter.
    General account means an Allowance Management System account, 
established under this subpart, that is not a compliance account or an 
assurance account.
    Generator means a device that produces electricity.
    Gross electrical output means, for a 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, for a unit for a specified period of time, the 
product (in mmBtu/time) of the gross calorific value of the fuel (in 
mmBtu/lb) fed into the unit multiplied by the fuel feed rate (in lb of 
fuel/time), as measured, recorded, and reported to the Administrator by 
the designated representative and as modified by the Administrator in 
accordance with this subpart and excluding the heat derived from 
preheated combustion air, recirculated flue gases, or exhaust.
    Heat input rate means, for a unit, the amount of heat input (in 
mmBtu) divided by unit operating time (in hr) or, for a unit and 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.
    Heat rate means, for a unit, the unit's maximum design heat input 
(in Btu/hr), divided by the product of 1,000,000 Btu/mmBtu and the 
unit's maximum hourly load.
    Indian country means ``Indian country'' as defined in 18 U.S.C. 
1151.
    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, for a unit, the maximum amount of 
fuel per hour (in Btu/hr) that the unit is capable of combusting on a 
steady state basis as of the initial installation of the unit as 
specified by the manufacturer of the unit.
    Monitoring system means any monitoring system that meets the 
requirements of this subpart, including a continuous emission 
monitoring system, an alternative monitoring system, or an excepted 
monitoring system under part 75 of this chapter.
    Nameplate capacity means, starting from the initial installation of 
a generator, the maximum electrical generating output (in MWe, rounded 
to the nearest tenth) 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 of such installation 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 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 (in MWe, rounded to the nearest tenth) as of 
such completion as specified by the person conducting the physical 
change.
    Natural gas means ``natural gas'' as defined in Sec.  72.2 of this 
chapter.
    Newly affected TR NOX Annual unit means a unit that was 
not a TR NOX Annual unit when it began operating but that 
thereafter becomes a TR NOX Annual unit.
    Operate or operation means, with regard to a unit, to combust fuel.
    Operator means, for a TR NOX Annual source or a TR 
NOX Annual unit at a source respectively, any person who 
operates, controls, or supervises a TR NOX Annual unit at 
the source or the TR NOX Annual unit and shall include, but 
not be limited to, any holding company, utility system, or plant 
manager of such source or unit.
    Owner means, for a TR NOX Annual source or a TR 
NOX Annual unit at a source respectively, any of the 
following persons:
    (1) Any holder of any portion of the legal or equitable title in a 
TR NOX Annual unit at the source or the TR NOX 
Annual unit;
    (2) Any holder of a leasehold interest in a TR NOX 
Annual unit at the source or the TR NOX Annual unit, 
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 TR NOX Annual unit; and 3) Any purchaser of power from 
a TR NOX Annual unit at the source or the TR NOX 
Annual unit under a life-of-the-unit, firm power contractual 
arrangement.
    Permanently retired means, with regard to a unit, a unit that is 
unavailable for service and that the unit's owners and operators do not 
expect to return to service in the future.
    Permitting authority means ``permitting authority'' as defined in 
Sec. Sec.  70.2 and 71.2 of this chapter.
    Potential electrical output capacity means, for a unit, 33 percent 
of the 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 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 log, or by a notation made on the document, 
information, or correspondence, by the Administrator in the regular 
course of business.
    Recordation, record, or recorded means, with regard to TR 
NOX Annual allowances, the moving of TR NOX

[[Page 48384]]

Annual allowances by the Administrator into, out of, or between 
Allowance Management System accounts, for purposes of allocation, 
auction, 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.
    Replacement, replace, or replaced means, with regard to a unit, the 
demolishing of a unit, or the permanent retirement and permanent 
disabling of a unit, and the construction of another unit (the 
replacement unit) to be used instead of the demolished or retired unit 
(the replaced unit).
    Sequential use of energy means:
    (1) The use of reject heat from electricity production in a useful 
thermal energy application or process; or
    (2) The use of reject heat from useful thermal energy application 
or process in electricity production.
    Serial number means, for a TR NOX Annual allowance, the 
unique identification number assigned to each TR NOX Annual 
allowance by the Administrator.
    Solid waste incineration unit means a stationary, fossil-fuel-fired 
boiler or stationary, fossil-fuel-fired combustion turbine that is a 
``solid waste incineration unit'' as defined in section 129(g)(1) of 
the Clean Air Act.
    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. This definition does not change or 
otherwise affect the definition of ``major source'', ``stationary 
source'', or ``source'' as set forth and implemented in a title V 
operating permit program or any other program under the Clean Air Act.
    State means one of the States that is subject to the TR 
NOX Annual Trading Program pursuant to Sec.  52.38(a) 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;
    (4) Provided that compliance with any ``submission'' or ``service'' 
deadline shall be determined by the date of dispatch, transmission, or 
mailing and not the date of receipt.
    Topping-cycle unit means a unit in which the energy input to the 
unit is first used to produce useful power, including electricity, 
where at least some of the reject heat from the electricity production 
is then used to provide useful thermal energy.
    Total energy input means, for a unit, total energy of all forms 
supplied to the unit, excluding energy produced by the unit. Each form 
of energy supplied shall be measured by the lower heating value of that 
form of energy calculated as follows:

LHV = HHV - 10.55(W + 9H)

Where:

LHV = lower heating value of the form of energy in Btu/lb,
HHV = higher heating value of the form of energy in Btu/lb,
W = weight % of moisture in the form of energy, and
H = weight % of hydrogen in the form of energy.

    Total energy output means, for a unit, the sum of useful power and 
useful thermal energy produced by the unit.
    TR NOX Annual allowance means a limited authorization issued and 
allocated or auctioned by the Administrator under this subpart, or by a 
State or permitting authority under a SIP revision approved by the 
Administrator under Sec.  52.38(a)(3), (4), or (5) of this chapter, to 
emit one ton of NOX during a control period of the specified 
calendar year for which the authorization is allocated or auctioned or 
of any calendar year thereafter under the TR NOX Annual 
Trading Program.
    TR NOX Annual allowance deduction or deduct TR NOX Annual 
allowances means the permanent withdrawal of TR NOX Annual 
allowances by the Administrator from a compliance account (e.g., in 
order to account for compliance with the TR NOX Annual 
emissions limitation) or from an assurance account (e.g., in order to 
account for compliance with the assurance provisions under Sec. Sec.  
97.406 and 97.425).
    TR NOX Annual allowances held or hold TR NO4 Annual allowances 
means the TR NOX Annual allowances treated as included in an 
Allowance Management System account as of a specified point in time 
because at that time they:
    (1) Have been recorded by the Administrator in the account or 
transferred into the account by a correctly submitted, but not yet 
recorded, TR NOX Annual allowance transfer in accordance 
with this subpart; and
    (2) Have not been transferred out of the account by a correctly 
submitted, but not yet recorded, TR NOX Annual allowance 
transfer in accordance with this subpart.
    TR NOX Annual emissions limitation means, for a TR NOX 
Annual source, the tonnage of NOX emissions authorized in a 
control period in a given year by the TR NOX Annual 
allowances available for deduction for the source under Sec.  97.424(a) 
for such control period.
    TR NOX Annual source means a source that includes one or more TR 
NOX Annual units.
    TR NOX Annual Trading Program means a multi-state NOX 
air pollution control and emission reduction program established in 
accordance with this subpart and Sec.  52.38(a) of this chapter 
(including such a program that is revised in a SIP revision approved by 
the Administrator under Sec.  52.38(a)(3) or (4) of this chapter or 
that is established in a SIP revision approved by the Administrator 
under Sec.  52.38(a)(5) of this chapter), as a means of mitigating 
interstate transport of fine particulates and NOX.
    TR NOX Annual unit means a unit that is subject to the TR 
NOX Annual Trading Program.
    TR NOX Ozone Season Trading Program means a multi-state 
NOX air pollution control and emission reduction program 
established in accordance with subpart BBBBB of this part and Sec.  
52.38(b) of this chapter (including such a program that is revised in a 
SIP revision approved by the Administrator under Sec.  52.38(b)(3) or 
(4) of this chapter or that is established in a SIP revision approved 
by the Administrator under Sec.  52.38(b)(5) of this chapter), as a 
means of mitigating interstate transport of ozone and NOX.
    TR SO2 Group 1 Trading Program means a multi-state SO2 
air pollution control and emission reduction program established in 
accordance with subpart CCCCC of this part and Sec.  52.39(a), (b), (d) 
through (f), (j), and (k) of this chapter (including such a program 
that is revised in a SIP revision approved by the Administrator under 
Sec.  52.39(d) or (e) of this chapter or that is established in a SIP 
revision approved by the Administrator under Sec.  52.39(f) of this 
chapter), as a means of mitigating interstate transport of fine 
particulates and SO2.
    TR SO2 Group 2 Trading Program means a multi-state SO2 air 
pollution control and emission reduction program established in 
accordance with subpart DDDDD of this part and 52.39(a), (c), and (g) 
through (k) of this chapter (including such a program that is revised 
in a SIP revision approved by the Administrator under Sec.  52.39(g) or 
(h) of this chapter or that is established in a SIP revision approved 
by the Administrator under Sec.  52.39(i) of this chapter), as a means 
of mitigating interstate transport of fine particulates and 
SO2.

[[Page 48385]]

    Unit means a stationary, fossil-fuel-fired boiler, stationary, 
fossil-fuel-fired combustion turbine, or other stationary, fossil-fuel-
fired combustion device. A unit that undergoes a physical change or is 
moved to a different location or source shall continue to be treated as 
the same unit. A unit (the replaced unit) that is replaced by another 
unit (the replacement unit) at the same or a different source shall 
continue to be treated as the same unit, and the replacement unit shall 
be treated as a separate unit.
    Unit operating day means, with regard to a unit, a calendar day in 
which the unit combusts any fuel.
    Unit operating hour or hour of unit operation means, with regard to 
a unit, an hour in which the unit combusts any fuel.
    Useful power means, with regard to a unit, electricity or 
mechanical energy that the unit makes 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 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., in 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.  97.403  Measurements, abbreviations, and acronyms.

    Measurements, abbreviations, and acronyms used in this subpart are 
defined as follows:

Btu--British thermal unit
CO2--carbon dioxide
H2O--water
hr--hour
kW--kilowatt electrical
kWh--kilowatt hour
lb--pound
mmBtu--million Btu
MWe--megawatt electrical
MWh--megawatt hour
NOX--nitrogen oxides
O2--oxygen
ppm--parts per million
scfh--standard cubic feet per hour
SO2--sulfur dioxide
yr--year

Sec.  97.404  Applicability.

    (a) Except as provided in paragraph (b) of this section:
    (1) The following units in a State (and Indian country within the 
borders of such State) shall be TR NOX Annual units, and any 
source that includes one or more such units shall be a TR 
NOX Annual source, subject to the requirements of this 
subpart: any stationary, fossil-fuel-fired boiler or stationary, 
fossil-fuel-fired combustion turbine serving at any time, on or after 
January 1, 2005, a generator with nameplate capacity of more than 25 
MWe producing electricity for sale.
    (2) If a stationary boiler or stationary combustion turbine that, 
under paragraph (a)(1) of this section, is not a TR NOX 
Annual unit begins to combust fossil fuel or to serve a generator with 
nameplate capacity of more than 25 MWe producing electricity for sale, 
the unit shall become a TR NOX Annual unit as provided in 
paragraph (a)(1) of this section on the first date on which it both 
combusts fossil fuel and serves such generator.
    (b) Any unit in a State (and Indian country within the borders of 
such State) that otherwise is a TR NOX Annual unit under 
paragraph (a) of this section and that meets the requirements set forth 
in paragraph (b)(1)(i) or (2)(i) of this section shall not be a TR 
NOX Annual unit:
    (1)(i) Any unit:
    (A) Qualifying as a cogeneration unit throughout the later of 2005 
or the 12-month period starting on the date the unit first produces 
electricity and continuing to qualify as a cogeneration unit throughout 
each calendar year ending after the later of 2005 or such 12-month 
period; and
    (B) Not supplying in 2005 or any calendar year thereafter 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.
    (ii) If, after qualifying under paragraph (b)(1)(i) of this section 
as not being a TR NOX Annual unit, a unit subsequently no 
longer meets all the requirements of paragraph (b)(1)(i) of this 
section, the unit shall become a TR NOX Annual unit starting 
on the earlier of January 1 after the first calendar year during which 
the unit first no longer qualifies as a cogeneration unit or January 1 
after the first calendar year during which the unit no longer meets the 
requirements of paragraph (b)(1)(i)(B) of this section. The unit shall 
thereafter continue to be a TR NOX Annual unit.
    (2)(i) Any unit:
    (A) Qualifying as a solid waste incineration unit throughout the 
later of 2005 or the 12-month period starting on the date the unit 
first produces electricity and continuing to qualify as a solid waste 
incineration unit throughout each calendar year ending after the later 
of 2005 or such 12-month period; and
    (B) With an average annual fuel consumption of fossil fuel for the 
first 3 consecutive calendar years of operation starting no earlier 
than 2005 of less than 20 percent (on a Btu basis) and an average 
annual fuel consumption of fossil fuel for any 3 consecutive calendar 
years thereafter of less than 20 percent (on a Btu basis).
    (ii) If, after qualifying under paragraph (b)(2)(i) of this section 
as not being a TR NOX Annual unit, a unit subsequently no 
longer meets all the requirements of paragraph (b)(1)(i) of this 
section, the unit shall become a TR NOX Annual unit starting 
on the earlier of January 1 after the first calendar year during which 
the unit first no longer qualifies as a solid waste incineration unit 
or January 1 after the first 3 consecutive calendar years after 2005 
for which the unit has an average annual fuel consumption of fossil 
fuel of 20 percent or more. The unit shall thereafter continue to be a 
TR NOX Annual unit.
    (c) A certifying official of an owner or operator of any unit or 
other equipment may submit a petition (including any supporting 
documents) to the Administrator at any time for a determination 
concerning the applicability, under paragraphs (a) and (b) of this 
section or a SIP revision approved under Sec.  52.38(a)(4) or (5) of 
this chapter, of the TR NOX Annual Trading Program to the 
unit or other equipment.
    (1) Petition content. The petition shall be in writing and include 
the identification of the unit or other equipment and the relevant 
facts about the unit or other equipment. The petition and any other 
documents provided to the Administrator in connection with the petition 
shall include the following certification statement, signed by the 
certifying official: ``I am authorized to make this submission on 
behalf of the owners and operators of the unit or other equipment 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

[[Page 48386]]

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) Response. The Administrator will issue a written response to 
the petition and may request supplemental information determined by the 
Administrator to be relevant to such petition. The Administrator's 
determination concerning the applicability, under paragraphs (a) and 
(b) of this section, of the TR NOX Annual Trading Program to 
the unit or other equipment shall be binding on any State or permitting 
authority unless the Administrator determines that the petition or 
other documents or information provided in connection with the petition 
contained significant, relevant errors or omissions.

Sec.  97.405  Retired unit exemption.

    (a)(1) Any TR NOX Annual unit that is permanently 
retired shall be exempt from Sec.  97.406(b) and (c)(1), Sec.  97.424, 
and Sec. Sec.  97.430 through 97.435.
    (2) The exemption under paragraph (a)(1) of this section shall 
become effective the day on which the TR NOX Annual unit is 
permanently retired. Within 30 days of the unit's permanent retirement, 
the designated representative shall submit a statement to the 
Administrator. The statement shall state, in a format prescribed by the 
Administrator, that the unit was permanently retired on a specified 
date and will comply with the requirements of paragraph (b) of this 
section.
    (b) Special provisions. (1) A unit exempt under paragraph (a) of 
this section shall not emit any NOX, 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 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 
designated representative of a unit exempt under paragraph (a) of this 
section shall comply with the requirements of the TR 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.
    (4) A unit exempt under paragraph (a) of this section shall lose 
its exemption on the first date on which the unit resumes operation. 
Such unit shall be treated, for purposes of applying allocation, 
monitoring, reporting, and recordkeeping requirements under this 
subpart, as a unit that commences commercial operation on the first 
date on which the unit resumes operation.

Sec.  97.406  Standard requirements.

    (a) Designated representative requirements. The owners and 
operators shall comply with the requirement to have a designated 
representative, and may have an alternate designated representative, in 
accordance with Sec. Sec.  97.413 through 97.418.
    (b) Emissions monitoring, reporting, and recordkeeping 
requirements.
    (1) The owners and operators, and the designated representative, of 
each TR NOX Annual source and each TR NOX Annual 
unit at the source shall comply with the monitoring, reporting, and 
recordkeeping requirements of Sec. Sec.  97.430 through 97.435.
    (2) The emissions data determined in accordance with Sec. Sec.  
97.430 through 97.435 shall be used to calculate allocations of TR 
NOX Annual allowances under Sec. Sec.  97.411(a)(2) and (b) 
and 97.412 and to determine compliance with the TR NOX 
Annual emissions limitation and assurance provisions under paragraph 
(c) of this section, provided that, for each monitoring location from 
which mass emissions are reported, the mass emissions amount used in 
calculating such allocations and determining such compliance shall be 
the mass emissions amount for the monitoring location determined in 
accordance with Sec. Sec.  97.430 through 97.435 and rounded to the 
nearest ton, with any fraction of a ton less than 0.50 being deemed to 
be zero.
    (c) NOX emissions requirements. (1) TR NOX Annual 
emissions limitation. (i) As of the allowance transfer deadline for a 
control period in a given year, the owners and operators of each TR 
NOX Annual source and each TR NOX Annual unit at 
the source shall hold, in the source's compliance account, TR 
NOX Annual allowances available for deduction for such 
control period under Sec.  97.424(a) in an amount not less than the 
tons of total NOX emissions for such control period from all 
TR NOX Annual units at the source.
    (ii) If total NOX emissions during a control period in a 
given year from the TR NOX Annual units at a TR 
NOX Annual source are in excess of the TR NOX 
Annual emissions limitation set forth in paragraph (c)(1)(i) of this 
section, then:
    (A) The owners and operators of the source and each TR 
NOX Annual unit at the source shall hold the TR 
NOX Annual allowances required for deduction under Sec.  
97.424(d); and
    (B) The owners and operators of the source and each TR 
NOX Annual unit at the source shall pay any fine, penalty, 
or assessment or comply with any other remedy imposed, for the same 
violations, under the Clean Air Act, and each ton of such excess 
emissions and each day of such control period shall constitute a 
separate violation of this subpart and the Clean Air Act.
    (2) TR NOX Annual assurance provisions. (i) If total 
NOX emissions during a control period in a given year from 
all TR NOX Annual units at TR NOX Annual sources 
in a State (and Indian country within the borders of such State) exceed 
the State assurance level, then the owners and operators of such 
sources and units in each group of one or more sources and units having 
a common designated representative for such control period, where the 
common designated representative's share of such NOX 
emissions during such control period exceeds the common designated 
representative's assurance level for the State and such control period, 
shall hold (in the assurance account established for the owners and 
operators of such group) TR NOX Annual allowances available 
for deduction for such control period under Sec.  97.425(a) in an 
amount equal to two times the product (rounded to the nearest whole 
number), as determined by the Administrator in accordance with Sec.  
97.425(b), of multiplying--
    (A) The quotient of the amount by which the common designated 
representative's share of such NOX emissions exceeds the 
common designated representative's assurance level divided by the sum 
of the amounts, determined for all common designated representatives 
for such sources and units in the State (and Indian country within the 
borders of such State) for such control period, by which each common 
designated representative's share of such NOX emissions 
exceeds the respective common designated representative's assurance 
level; and
    (B) The amount by which total NOX emissions from all TR 
NOX Annual units at TR NOX Annual sources in the 
State (and Indian country within the borders of such State) for such 
control period exceed the State assurance level.

[[Page 48387]]

    (ii) The owners and operators shall hold the TR NOX 
Annual allowances required under paragraph (c)(2)(i) of this section, 
as of midnight of November 1 (if it is a business day), or midnight of 
the first business day thereafter (if November 1 is not a business 
day), immediately after such control period.
    (iii) Total NOX emissions from all TR NOX 
Annual units at TR NOX Annual sources in a State (and Indian 
country within the borders of such State) during a control period in a 
given year exceed the State assurance level if such total 
NOX emissions exceed the sum, for such control period, of 
the State NOX Annual trading budget under Sec.  97.410(a) 
and the State's variability limit under Sec.  97.410(b).
    (iv) It shall not be a violation of this subpart or of the Clean 
Air Act if total NOX emissions from all TR NOX 
Annual units at TR NOX Annual sources in a State (and Indian 
country within the borders of such State) during a control period 
exceed the State assurance level or if a common designated 
representative's share of total NOX emissions from the TR 
NOX Annual units at TR NOX Annual sources in a 
State (and Indian country within the borders of such State) during a 
control period exceeds the common designated representative's assurance 
level.
    (v) To the extent the owners and operators fail to hold TR 
NOX Annual allowances for a control period in a given year 
in accordance with paragraphs (c)(2)(i) through (iii) of this section,
    (A) The owners and operators shall pay any fine, penalty, or 
assessment or comply with any other remedy imposed under the Clean Air 
Act; and
    (B) Each TR NOX Annual allowance that the owners and 
operators fail to hold for such control period in accordance with 
paragraphs (c)(2)(i) through (iii) of this section and each day of such 
control period shall constitute a separate violation of this subpart 
and the Clean Air Act.
    (3) Compliance periods. A TR NOX Annual unit shall be 
subject to the requirements under paragraphs (c)(1) and (c)(2) of this 
section for the control period starting on the later of January 1, 2012 
or the deadline for meeting the unit's monitor certification 
requirements under Sec.  97.430(b) and for each control period 
thereafter.
    (4) Vintage of allowances held for compliance. (i) A TR 
NOX Annual allowance held for compliance with the 
requirements under paragraph (c)(1)(i) of this section for a control 
period in a given year must be a TR NOX Annual allowance 
that was allocated for such control period or a control period in a 
prior year.
    (ii) A TR NOX Annual allowance held for compliance with 
the requirements under paragraphs (c)(1)(ii)(A) and (2)(i) through 
(iii) of this section for a control period in a given year must be a TR 
NOX Annual allowance that was allocated for a control period 
in a prior year or the control period in the given year or in the 
immediately following year.
    (5) Allowance Management System requirements. Each TR 
NOX Annual allowance shall be held in, deducted from, or 
transferred into, out of, or between Allowance Management System 
accounts in accordance with this subpart.
    (6) Limited authorization. A TR NOX Annual allowance is 
a limited authorization to emit one ton of NOX during the 
control period in one year. Such authorization is limited in its use 
and duration as follows:
    (i) Such authorization shall only be used in accordance with the TR 
NOX Annual Trading Program; and
    (ii) Notwithstanding any other provision of this subpart, the 
Administrator has the authority to terminate or limit the use and 
duration of such authorization to the extent the Administrator 
determines is necessary or appropriate to implement any provision of 
the Clean Air Act.
    (7) Property right. A TR NOX Annual allowance does not 
constitute a property right.
    (d) Title V permit requirements. (1) No title V permit revision 
shall be required for any allocation, holding, deduction, or transfer 
of TR NOX Annual allowances in accordance with this subpart.
    (2) A description of whether a unit is required to monitor and 
report NOX emissions using a continuous emission monitoring 
system (under subpart H of part 75 of this chapter), an excepted 
monitoring system (under appendices D and E to part 75 of this 
chapter), a low mass emissions excepted monitoring methodology (under 
Sec.  75.19 of this chapter), or an alternative monitoring system 
(under subpart E of part 75 of this chapter) in accordance with 
Sec. Sec.  97.430 through 97.435 may be added to, or changed in, a 
title V permit using minor permit modification procedures in accordance 
with Sec. Sec.  70.7(e)(2) and 71.7(e)(1) of this chapter, provided 
that the requirements applicable to the described monitoring and 
reporting (as added or changed, respectively) are already incorporated 
in such permit. This paragraph explicitly provides that the addition 
of, or change to, a unit's description as described in the prior 
sentence is eligible for minor permit modification procedures in 
accordance with Sec. Sec.  70.7(e)(2)(i)(B) and 71.7(e)(1)(i)(B) of 
this chapter.
    (e) Additional recordkeeping and reporting requirements. (1) Unless 
otherwise provided, the owners and operators of each TR NOX 
Annual source and each TR NOX Annual unit at the source 
shall keep on site at the source each of the following documents (in 
hardcopy or electronic format) 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 Administrator.
    (i) The certificate of representation under Sec.  97.416 for the 
designated representative for the source and each TR NOX 
Annual 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 certificate of representation and 
documents are superseded because of the submission of a new certificate 
of representation under Sec.  97.416 changing the designated 
representative.
    (ii) All emissions monitoring information, in accordance with this 
subpart.
    (iii) Copies of all reports, compliance certifications, and other 
submissions and all records made or required under, or to demonstrate 
compliance with the requirements of, the TR NOX Annual 
Trading Program.
    (2) The designated representative of a TR NOX Annual 
source and each TR NOX Annual unit at the source shall make 
all submissions required under the TR NOX Annual Trading 
Program, except as provided in Sec.  97.418. This requirement does not 
change, create an exemption from, or or otherwise affect the 
responsible official submission requirements under a title V operating 
permit program in parts 70 and 71 of this chapter.
    (f) Liability. (1) Any provision of the TR NOX Annual 
Trading Program that applies to a TR NOX Annual source or 
the designated representative of a TR NOX Annual source 
shall also apply to the owners and operators of such source and of the 
TR NOX Annual units at the source.
    (2) Any provision of the TR NOX Annual Trading Program 
that applies to a TR NOX Annual unit or the designated 
representative of a TR NOX Annual unit shall also apply to 
the owners and operators of such unit.
    (g) Effect on other authorities. No provision of the TR 
NOX Annual Trading Program or exemption under

[[Page 48388]]

Sec.  97.405 shall be construed as exempting or excluding the owners 
and operators, and the designated representative, of a TR 
NOX Annual source or TR NOX Annual unit from 
compliance with any other provision of the applicable, approved State 
implementation plan, a federally enforceable permit, or the Clean Air 
Act.

Sec.  97.407  Computation of time.

    (a) Unless otherwise stated, any time period scheduled, under the 
TR 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 
TR 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 TR NOX Annual Trading Program, is not a business 
day, the time period shall be extended to the next business day.

Sec.  97.408  Administrative appeal procedures.

    The administrative appeal procedures for decisions of the 
Administrator under the TR NOX Annual Trading Program are 
set forth in part 78 of this chapter.

Sec.  97.409  [Reserved]

Sec.  97.410  State NOX Annual trading budgets, new unit 
set-asides, Indian country new unit set-aside, and variability limits.

    (a) The State NOX Annual trading budgets, new unit set-
asides, and Indian country new unit set-asides for allocations of TR 
NOX Annual allowances for the control periods in 2012 and 
thereafter are as follows:

 
----------------------------------------------------------------------------------------------------------------
                                                                                                  Indian country
                                                                    NOX Annual     New unit set-   new unit set-
                              State                               trading budget   aside (tons)    aside (tons)
                                                                    (tons)* for    for 2012 and    for 2012 and
                                                                   2012 and 2013       2013            2013
----------------------------------------------------------------------------------------------------------------
Alabama.........................................................          72,691           1,454  ..............
Georgia.........................................................          62,010           1,240  ..............
Illinois........................................................          47,872           3,830  ..............
Indiana.........................................................         109,726           3,292  ..............
Iowa............................................................          38,335             729              38
Kansas..........................................................          30,714             583              31
Kentucky........................................................          85,086           3,403  ..............
Maryland........................................................          16,633             333  ..............
Michigan........................................................          60,193           1,144              60
Minnesota.......................................................          29,572             561              30
Missouri........................................................          52,374           1,571  ..............
Nebraska........................................................          26,440           1,825              26
New Jersey......................................................           7,266             145  ..............
New York........................................................          17,543             508              18
North Carolina..................................................          50,587           2,984              51
Ohio............................................................          92,703           1,854  ..............
Pennsylvania....................................................         119,986           2,400  ..............
South Carolina..................................................          32,498             617              33
Tennessee.......................................................          35,703             714  ..............
Texas...........................................................         133,595           3,874             134
Virginia........................................................          33,242           1,662  ..............
West Virginia...................................................          59,472           2,974  ..............
Wisconsin.......................................................          31,628           1,866              32
----------------------------------------------------------------------------------------------------------------

----------------------------------------------------------------------------------------------------------------
                                                                    NOX Annual                    Indian country
                                                                  trading budget   New unit set-   new unit set-
                              State                                 (tons)* for    aside (tons)    aside (tons)
                                                                     2014 and      for 2014 and    for 2014 and
                                                                    thereafter      thereafter      thereafter
----------------------------------------------------------------------------------------------------------------
Alabama.........................................................          71,962           1,439  ..............
Georgia.........................................................          40,540             811  ..............
Illinois........................................................          47,872           3,830  ..............
Indiana.........................................................         108,424           3,253  ..............
Iowa............................................................          37,498             712              38
Kansas..........................................................          25,560             485              26
Kentucky........................................................          77,238           3,090  ..............
Maryland........................................................          16,574             331  ..............
Michigan........................................................          57,812           1,098              58
Minnesota.......................................................          29,572             561              30
Missouri........................................................          48,717           1,462  ..............
Nebraska........................................................          26,440           1,825              26
New Jersey......................................................           7,266             145  ..............
New York........................................................          17,543             508              18
North Carolina..................................................          41,553           2,451              42
Ohio............................................................          87,493           1,750  ..............
Pennsylvania....................................................         119,194           2,384  ..............
South Carolina..................................................          32,498             617              33
Tennessee.......................................................          19,337             387  ..............

[[Page 48389]]

 
Texas...........................................................         133,595           3,874             134
Virginia........................................................          33,242           1,662  ..............
West Virginia...................................................          54,582           2,729  ..............
Wisconsin.......................................................          30,398           1,794              30
----------------------------------------------------------------------------------------------------------------
* Each trading budget includes the new unit set-aside and, where applicable, the Indian country new unit set-
  aside and does not include the variability limit.

    (b) The States' variability limits for the State NOX 
Annual trading budgets for the control periods in 2012 and thereafter 
are as follows:

------------------------------------------------------------------------
                                                            Variability
                                            Variability     limits for
                  State                     limits for       2014 and
                                           2012 and 2013    thereafter
------------------------------------------------------------------------
Alabama.................................          13,084          12,953
Georgia.................................          11,162           7,297
Illinois................................           8,617           8,617
Indiana.................................          19,751          19,516
Iowa....................................           6,900           6,750
Kansas..................................           5,529           4,601
Kentucky................................          15,315          13,903
Maryland................................           2,994           2,983
Michigan................................          10,835          10,406
Minnesota...............................           5,323           5,323
Missouri................................           9,427           8,769
Nebraska................................           4,759           4,759
New Jersey..............................           1,308           1,308
New York................................           3,158           3,158
North Carolina..........................           9,106           7,480
Ohio....................................          16,687          15,749
Pennsylvania............................          21,597          21,455
South Carolina..........................           5,850           5,850
Tennessee...............................           6,427           3,481
Texas...................................          24,047          24,047
Virginia................................           5,984           5,984
West Virginia...........................          10,705           9,825
Wisconsin...............................           5,693           5,472
------------------------------------------------------------------------

Sec.  97.411  Timing requirements for TR NOX Annual allowance 
allocations.

    (a) Existing units. (1) TR NOX Annual allowances are 
allocated, for the control periods in 2012 and each year thereafter, as 
provided in a notice of data availability issued by the Administrator. 
Providing an allocation to a unit in such notice does not constitute a 
determination that the unit is a TR NOX Annual unit, and not 
providing an allocation to a unit in such notice does not constitute a 
determination that the unit is not a TR NOX Annual unit.
    (2) Notwithstanding paragraph (a)(1) of this section, if a unit 
provided an allocation in the notice of data availability issued under 
paragraph (a)(1) of this section does not operate, starting after 2011, 
during the control period in two consecutive years, such unit will not 
be allocated the TR NOX Annual allowances provided in such 
notice for the unit for the control periods in the fifth year after the 
first such year and in each year after that fifth year. All TR 
NOX Annual allowances that would otherwise have been 
allocated to such unit will be allocated to the new unit set-aside for 
the State where such unit is located and for the respective years 
involved. If such unit resumes operation, the Administrator will 
allocate TR NOX Annual allowances to the unit in accordance 
with paragraph (b) of this section.
    (b) New units. (1) New unit set-asides. (i) By June 1, 2012 and 
June 1 of each year thereafter, the Administrator will calculate the TR 
NOX Annual allowance allocation to each TR NOX 
Annual unit in a State, in accordance with Sec.  97.412(a)(2) through 
(7) and (12), for the control period in the year of the applicable 
calculation deadline under this paragraph and will promulgate a notice 
of data availability of the results of the calculations.
    (ii) For each notice of data availability required in paragraph 
(b)(1)(i) of this section, the Administrator will provide an 
opportunity for submission of objections to the calculations referenced 
in such notice.
    (A) Objections shall be submitted by the deadline specified in each 
notice of data availability required in paragraph (b)(1)(i) of this 
section and shall be limited to addressing whether the calculations 
(including the identification of the TR NOX Annual units) 
are in accordance with Sec.  97.412(a)(2) through (7) and (12) and 
Sec. Sec.  97.406(b)(2) and 97.430 through 97.435.
    (B) The Administrator will adjust the calculations to the extent 
necessary to ensure that they are in accordance with the provisions 
referenced in paragraph (b)(1)(ii)(A) of this section. By August 1 
immediately after the promulgation of each notice of data availability 
required in paragraph (b)(1)(i) of this section, the

[[Page 48390]]

Administrator will promulgate a notice of data availability of any 
adjustments that the Administrator determines to be necessary with 
regard to allocations under Sec.  97.412(a)(2) through (7) and (12) and 
the reasons for accepting or rejecting any objections submitted in 
accordance with paragraph (b)(1)(ii)(A) of this section.
    (iii) If the new unit set-aside for such control period contains 
any TR NOX Annual allowances that have not been allocated in 
the applicable notice of data availability required in paragraph 
(b)(1)(ii) of this section, the Administrator will promulgate, by 
December 15 immediately after such notice, a notice of data 
availability that identifies any TR NOX Annual units that 
commenced commercial operation during the period starting January 1 of 
the year before the year of such control period and ending November 30 
of year of such control period.
    (iv) For each notice of data availability required in paragraph 
(b)(1)(iii) of this section, the Administrator will provide an 
opportunity for submission of objections to the identification of TR 
NOX annual units in such notice.
    (A) Objections shall be submitted by the deadline specified in each 
notice of data availability required in paragraph (b)(1)(iii) of this 
section and shall be limited to addressing whether the identification 
of TR NOX annual units in such notice is in accordance with 
paragraph (b)(1)(iii) of this section.
    (B) The Administrator will adjust the identification of TR 
NOX Annual units in the each notice of data availability 
required in paragraph (b)(1)(iii) of this section to the extent 
necessary to ensure that it is in accordance with paragraph (b)(1)(iii) 
of this section and will calculate the TR NOX Annual 
allowance allocation to each TR NOX Annual unit in 
accordance with Sec.  97.412(a)(9), (10), and (12) and Sec. Sec.  
97.406(b)(2) and 97.430 through 97.435. By February 15 immediately 
after the promulgation of each notice of data availability required in 
paragraph (b)(1)(iii) of this section, the Administrator will 
promulgate a notice of data availability of any adjustments of the 
identification of TR NOX Annual units that the Administrator 
determines to be necessary, the reasons for accepting or rejecting any 
objections submitted in accordance with paragraph (b)(1)(iv)(A) of this 
section, and the results of such calculations.
    (v) To the extent any TR NOX Annual allowances are added 
to the new unit set-aside after promulgation of each notice of data 
availability required in paragraph (b)(1)(iv) of this section, the 
Administrator will promulgate additional notices of data availability, 
as deemed appropriate, of the allocation of such TR NOX 
Annual allowances in accordance with Sec.  97.412(a)(10).
    (2) Indian country new unit set-asides. (i) By June 1, 2012 and 
June 1 of each year thereafter, the Administrator will calculate the TR 
NOX Annual allowance allocation to each TR NOX 
Annual unit in Indian country within the borders of a State, in 
accordance with Sec.  97.412(b)(2) through (7) and (12), for the 
control period in the year of the applicable calculation deadline under 
this paragraph and will promulgate a notice of data availability of the 
results of the calculations.
    (ii) For each notice of data availability required in paragraph 
(b)(2)(i) of this section, the Administrator will provide an 
opportunity for submission of objections to the calculations referenced 
in such notice.
    (A) Objections shall be submitted by the deadline specified in each 
notice of data availability required in paragraph (b)(2)(i) of this 
section and shall be limited to addressing whether the calculations 
(including the identification of the TR NOX Annual units) 
are in accordance with Sec.  97.412(b)(2) through (7) and (12) and 
Sec. Sec.  97.406(b)(2) and 97.430 through 97.435.
    (B) The Administrator will adjust the calculations to the extent 
necessary to ensure that they are in accordance with the provisions 
referenced in paragraph (b)(2)(ii)(A) of this section. By August 1 
immediately after the promulgation of each notice of data availability 
required in paragraph (b)(2)(i) of this section, the Administrator will 
promulgate a notice of data availability of any adjustments that the 
Administrator determines to be necessary with regard to allocations 
under Sec.  97.412(b)(2) through (7) and (12) and the reasons for 
accepting or rejecting any objections submitted in accordance with 
paragraph (b)(2)(ii)(A) of this section.
    (iii) If the Indian country new unit set-aside for such control 
period contains any TR NOX Annual allowances that have not 
been allocated in the applicable notice of data availability required 
in paragraph (b)(2)(ii) of this section, the Administrator will 
promulgate, by December 15 immediately after such notice, a notice of 
data availability that identifies any TR NOX Annual units 
that commenced commercial operation during the period starting January 
1 of the year before the year of such control period and ending 
November 30 of year of such control period.
    (iv) For each notice of data availability required in paragraph 
(b)(2)(iii) of this section, the Administrator will provide an 
opportunity for submission of objections to the identification of TR 
NOX annual units in such notice.
    (A) Objections shall be submitted by the deadline specified in each 
notice of data availability required in paragraph (b)(2)(iii) of this 
section and shall be limited to addressing whether the identification 
of TR NOX annual units in such notice is in accordance with 
paragraph (b)(2)(iii) of this section.
    (B) The Administrator will adjust the identification of TR 
NOX Annual units in the each notice of data availability 
required in paragraph (b)(2)(iii) of this section to the extent 
necessary to ensure that it is in accordance with paragraph (b)(2)(iii) 
of this section and will calculate the TR NOX Annual 
allowance allocation to each TR NOX Annual unit in 
accordance with Sec.  97.412(b)(9), (10), and (12) and Sec. Sec.  
97.406(b)(2) and 97.430 through 97.435. By February 15 immediately 
after the promulgation of each notice of data availability required in 
paragraph (b)(2)(iii) of this section, the Administrator will 
promulgate a notice of data availability of any adjustments of the 
identification of TR NOX Annual units that the Administrator 
determines to be necessary, the reasons for accepting or rejecting any 
objections submitted in accordance with paragraph (b)(2)(iv)(A) of this 
section, and the results of such calculations.
    (v) To the extent any TR NOX Annual allowances are added 
to the Indian country new unit set-aside after promulgation of each 
notice of data availability required in paragraph (b)(2)(iv) of this 
section, the Administrator will promulgate additional notices of data 
availability, as deemed appropriate, of the allocation of such TR 
NOX Annual allowances in accordance with Sec.  
97.412(b)(10).
    (c) Units incorrectly allocated TR NOX Annual 
allowances. (1) For each control period in 2012 and thereafter, if the 
Administrator determines that TR NOX Annual allowances were 
allocated under paragraph (a) of this section, or under a provision of 
a SIP revision approved under Sec.  52.38(a)(3), (4), or (5) of this 
chapter, where such control period and the recipient are covered by the 
provisions of paragraph (c)(1)(i) of this section or were allocated 
under Sec.  97.412(a)(2) through (7), (9), and (12) and (b)(2) through 
(7), (9), and (12), or under a provision of a SIP revision approved 
under Sec.  52.38(a)(4) or (5) of this chapter, where such control 
period and the recipient are covered by the

[[Page 48391]]

provisions of paragraph (c)(1)(ii) of this section, then the 
Administrator will notify the designated representative of the 
recipient and will act in accordance with the procedures set forth in 
paragraphs (c)(2) through (5) of this section:
    (i)(A) The recipient is not actually a TR NOX Annual 
unit under Sec.  97.404 as of January 1, 2012 and is allocated TR 
NOX Annual allowances for such control period or, in the 
case of an allocation under a provision of a SIP revision approved 
under Sec.  52.38(a)(3), (4), or (5) of this chapter, the recipient is 
not actually a TR NOX Annual unit as of January 1, 2012 and 
is allocated TR NOX Annual allowances for such control 
period that the SIP revision provides should be allocated only to 
recipients that are TR NOX Annual units as of January 1, 
2012; or
    (B) The recipient is not located as of January 1 of the control 
period in the State from whose NOX Annual trading budget the 
TR NOX Annual allowances allocated under paragraph (a) of 
this section, or under a provision of a SIP revision approved under 
Sec.  52.38(a)(3), (4), or (5) of this chapter, were allocated for such 
control period.
    (ii) The recipient is not actually a TR NOX Annual unit 
under Sec.  97.404 as of January 1 of such control period and is 
allocated TR NOX Annual allowances for such control period 
or, in the case of an allocation under a provision of a SIP revision 
approved under Sec.  52.38(a)(3), (4), or (5) of this chapter, the 
recipient is not actually a TR NOX Annual unit as of January 
1 of such control period and is allocated TR NOX Annual 
allowances for such control period that the SIP revision provides 
should be allocated only to recipients that are TR NOX 
Annual units as of January 1 of such control period.
    (2) Except as provided in paragraph (c)(3) or (4) of this section, 
the Administrator will not record such TR NOX Annual 
allowances under Sec.  97.421.
    (3) If the Administrator already recorded such TR NOX 
Annual allowances under Sec.  97.421 and if the Administrator makes the 
determination under paragraph (c)(1) of this section before making 
deductions for the source that includes such recipient under Sec.  
97.424(b) for such control period, then the Administrator will deduct 
from the account in which such TR NOX Annual allowances were 
recorded an amount of TR NOX Annual allowances allocated for 
the same or a prior control period equal to the amount of such already 
recorded TR NOX Annual allowances. The authorized account 
representative shall ensure that there are sufficient TR NOX 
Annual allowances in such account for completion of the deduction.
    (4) If the Administrator already recorded such TR NOX 
Annual allowances under Sec.  97.421 and if the Administrator makes the 
determination under paragraph (c)(1) of this section after making 
deductions for the source that includes such recipient under Sec.  
97.424(b) for such control period, then the Administrator will not make 
any deduction to take account of such already recorded TR 
NOX Annual allowances.
    (5)(i) With regard to the TR NOX Annual allowances that 
are not recorded, or that are deducted as an incorrect allocation, in 
accordance with paragraphs (c)(2) and (3) of this section for a 
recipient under paragraph (c)(1)(i) of this section, the Administrator 
will:
    (A) Transfer such TR NOX Annual allowances to the new 
unit set-aside for such control period for the State from whose 
NOX Annual trading budget the TR NOX Annual 
allowances were allocated; or
    (B) If the State has a SIP revision approved under Sec.  
52.38(a)(4) or (5) covering such control period, include such TR 
NOX Annual allowances in the portion of the State 
NOX Annual trading budget that may be allocated for such 
control period in accordance with such SIP revision.
    (ii) With regard to the TR NOX Annual allowances that 
were not allocated from the Indian country new unit set-aside for such 
control period and that are not recorded, or that are deducted as an 
incorrect allocation, in accordance with paragraphs (c)(2) and (3) of 
this section for a recipient under paragraph (c)(1)(ii) of this 
paragraph, the Administrator will:
    (A) Transfer such TR NOX Annual allowances to the new 
unit set-aside for such control period; or
    (B) If the State has a SIP revision approved under Sec.  
52.38(a)(4) or (5) covering such control period, include such TR 
NOX Annual allowances in the portion of the State 
NOX Annual trading budget that may be allocated for such 
control period in accordance with such SIP revision.
    (iii) With regard to the TR NOX Annual allowances that 
were allocated from the Indian country new unit set-aside for such 
control period and that are not recorded, or that are deducted as an 
incorrect allocation, in accordance with paragraphs (c)(2) and (3) of 
this section for a recipient under paragraph (c)(1)(ii) of this 
paragraph, the Administrator will transfer such TR NOX 
Annual allowances to the Indian country new unit set-aside for such 
control period.

Sec.  97.412  TR NOX Annual allowance allocations to new 
units.

    (a) For each control period in 2012 and thereafter and for the TR 
NOX Annual units in each State, the Administrator will 
allocate TR NOX Annual allowances to the TR NOX 
Annual units as follows:
    (1) The TR NOX Annual allowances will be allocated to 
the following TR NOX Annual units, except as provided in 
paragraph (a)(10) of this section:
    (i) TR NOX Annual units that are not allocated an amount 
of TR NOX Annual allowances in the notice of data 
availability issued under Sec.  97.411(a)(1);
    (ii) TR NOX Annual units whose allocation of an amount 
of TR NOX Annual allowances for such control period in the 
notice of data availability issued under Sec.  97.411(a)(1) is covered 
by Sec.  97.411(c)(2) or (3);
    (iii) TR NOX Annual units that are allocated an amount 
of TR NOX Annual allowances for such control period in the 
notice of data availability issued under Sec.  97.411(a)(1), which 
allocation is terminated for such control period pursuant to Sec.  
97.411(a)(2), and that operate during the control period immediately 
preceding such control period; or
    (iv) For purposes of paragraph (a)(9) of this section, TR 
NOX Annual units under Sec.  97.411(c)(1)(ii) whose 
allocation of an amount of TR NOX Annual allowances for such 
control period in the notice of data availability issued under Sec.  
97.411(b)(1)(ii)(B) is covered by Sec.  97.411(c)(2) or (3).
    (2) The Administrator will establish a separate new unit set-aside 
for the State for each such control period. Each such new unit set-
aside will be allocated TR NOX Annual allowances in an 
amount equal to the applicable amount of tons of NOX 
emissions as set forth in Sec.  97.410(a) and will be allocated 
additional TR NOX Annual allowances (if any) in accordance 
with Sec. Sec.  97.411(a)(2) and (c)(5) and paragraph (b)(10) of this 
section.
    (3) The Administrator will determine, for each TR NOX 
Annual unit described in paragraph (a)(1) of this section, an 
allocation of TR NOX Annual allowances for the later of the 
following control periods and for each subsequent control period:
    (i) The control period in 2012;
    (ii) The first control period after the control period in which the 
TR NOX Annual unit commences commercial operation;
    (iii) For a unit described in paragraph (a)(1)(ii) of this section, 
the first control period in which the TR NOX Annual unit 
operates in the State after operating in another jurisdiction and for 
which

[[Page 48392]]

the unit is not already allocated one or more TR NOX Annual 
allowances; and
    (iv) For a unit described in paragraph (a)(1)(iii) of this section, 
the first control period after the control period in which the unit 
resumes operation.
    (4)(i) The allocation to each TR NOX annual unit 
described in paragraph (a)(1)(i) through (iii) of this section and for 
each control period described in paragraph (a)(3) of this section will 
be an amount equal to the unit's total tons of NOX emissions 
during the immediately preceding control period.
    (ii) The Administrator will adjust the allocation amount in 
paragraph (a)(4)(i) in accordance with paragraphs (a)(5) through (7) 
and (12) of this section.
    (5) The Administrator will calculate the sum of the TR 
NOX Annual allowances determined for all such TR 
NOX Annual units under paragraph (a)(4)(i) of this section 
in the State for such control period.
    (6) If the amount of TR NOX Annual allowances in the new 
unit set-aside for the State for such control period is greater than or 
equal to the sum under paragraph (a)(5) of this section, then the 
Administrator will allocate the amount of TR NOX Annual 
allowances determined for each such TR NOX Annual unit under 
paragraph (a)(4)(i) of this section.
    (7) If the amount of TR NOX Annual allowances in the new 
unit set-aside for the State for such control period is less than the 
sum under paragraph (a)(5) of this section, then the Administrator will 
allocate to each such TR NOX Annual unit the amount of the 
TR NOX Annual allowances determined under paragraph 
(a)(4)(i) of this section for the unit, multiplied by the amount of TR 
NOX Annual allowances in the new unit set-aside for such 
control period, divided by the sum under paragraph (a)(5) of this 
section, and rounded to the nearest allowance.
    (8) The Administrator will notify the public, through the 
promulgation of the notices of data availability described in Sec.  
97.411(b)(1)(i) and (ii), of the amount of TR NOX Annual 
allowances allocated under paragraphs (a)(2) through (7) and (12) of 
this section for such control period to each TR NOX Annual 
unit eligible for such allocation.
    (9) If, after completion of the procedures under paragraphs (a)(5) 
through (8) of this section for such control period, any unallocated TR 
NOX Annual allowances remain in the new unit set-aside for 
the State for such control period, the Administrator will allocate such 
TR NOX Annual allowances as follows--
    (i) The Administrator will determine, for each unit described in 
paragraph (a)(1) of this section that commenced commercial operation 
during the period starting January 1 of the year before the year of 
such control period and ending November 30 of year of such control 
period, the positive difference (if any) between the unit's emissions 
during such control period and the amount of TR NOX Annual 
allowances referenced in the notice of data availability required under 
Sec.  97.411(b)(1)(ii) for the unit for such control period;
    (ii) The Administrator will determine the sum of the positive 
differences determined under paragraph (a)(9)(i) of this section;
    (iii) If the amount of unallocated TR NOX Annual 
allowances remaining in the new unit set-aside for the State for such 
control period is greater than or equal to the sum determined under 
paragraph (a)(9)(ii) of this section, then the Administrator will 
allocate the amount of TR NOX Annual allowances determined 
for each such TR NOX Annual unit under paragraph (a)(9)(i) 
of this section; and
    (iv) If the amount of unallocated TR NOX Annual 
allowances remaining in the new unit set-aside for the State for such 
control period is less than the sum under paragraph (a)(9)(ii) of this 
section, then the Administrator will allocate to each such TR 
NOX Annual unit the amount of the TR NOX Annual 
allowances determined under paragraph (a)(9)(i) of this section for the 
unit, multiplied by the amount of unallocated TR NOX Annual 
allowances remaining in the new unit set-aside for such control period, 
divided by the sum under paragraph (a)(9)(ii) of this section, and 
rounded to the nearest allowance.
    (10) If, after completion of the procedures under paragraphs (a)(9) 
and (12) of this section for such control period, any unallocated TR 
NOX Annual allowances remain in the new unit set-aside for 
the State for such control period, the Administrator will allocate to 
each TR NOX Annual unit that is in the State, is allocated 
an amount of TR NOX Annual allowances in the notice of data 
availability issued under Sec.  97.411(a)(1), and continues to be 
allocated TR NOX Annual allowances for such control period 
in accordance with Sec.  97.411(a)(2), an amount of TR NOX 
Annual allowances equal to the following: the total amount of such 
remaining unallocated TR NOX Annual allowances in such new 
unit set-aside, multiplied by the unit's allocation under Sec.  
97.411(a) for such control period, divided by the remainder of the 
amount of tons in the applicable State NOX Annual trading 
budget minus the sum of the amounts of tons in such new unit set-aside 
and the Indian country new unit set-aside for the State for such 
control period, and rounded to the nearest allowance.
    (11) The Administrator will notify the public, through the 
promulgation of the notices of data availability described in Sec.  
97.411(b)(1)(iii), (iv), and (v), of the amount of TR NOX 
Annual allowances allocated under paragraphs (a)(9), (10), and (12) of 
this section for such control period to each TR NOX Annual 
unit eligible for such allocation.
    (12)(i) Notwithstanding the requirements of paragraphs (a)(2) 
through (11) of this section, if the calculations of allocations of a 
new unit set-aside for a control period in a given year under paragraph 
(a)(7) of this section, paragraphs (a)(6) and (9)(iv) of this section, 
or paragraphs (a)(6), (9)(iii), and (10) of this section would 
otherwise result in total allocations of such new unit set-aside 
exceeding the total amount of such new unit set-aside, then the 
Administrator will adjust the results of the calculations under 
paragraph (a)(7), (9)(iv), or (10) of this section, as applicable, as 
follows. The Administrator will list the TR NOX Annual units 
in descending order based on the amount of such units' allocations 
under paragraph (a)(7), (9)(iv), or (10) of this section, as 
applicable, and, in cases of equal allocation amounts, in alphabetical 
order of the relevant source's name and numerical order of the relevant 
unit's identification number, and will reduce each unit's allocation 
under paragraph (a)(7), (9)(iv), or (10) of this section, as 
applicable, by one TR NOX Annual allowance (but not below 
zero) in the order in which the units are listed and will repeat this 
reduction process as necessary, until the total allocations of such new 
unit set-aside equal the total amount of such new unit set-aside.
    (ii) Notwithstanding the requirements of paragraphs (a)(10) and 
(11) of this section, if the calculations of allocations of a new unit 
set-aside for a control period in a given year under paragraphs (a)(6), 
(9)(iii), and (10) of this section would otherwise result in a total 
allocations of such new unit set-aside less than the total amount of 
such new unit set-aside, then the Administrator will adjust the results 
of the calculations under paragraph (a)(10) of this section, as 
follows. The Administrator will list the TR NOX Annual units 
in descending order based on the amount of such units' allocations 
under paragraph (a)(10) of this section and, in cases of equal 
allocation amounts, in alphabetical order of the relevant source's name 
and numerical order of the relevant unit's identification number, and 
will increase each unit's

[[Page 48393]]

allocation under paragraph (a)(10) of this section by one TR 
NOX Annual allowance in the order in which the units are 
listed and will repeat this increase process as necessary, until the 
total allocations of such new unit set-aside equal the total amount of 
such new unit set-aside.
    (b) For each control period in 2012 and thereafter and for the TR 
NOX Annual units located in Indian country within the 
borders of each State, the Administrator will allocate TR 
NOX Annual allowances to the TR NOX Annual units 
as follows:
    (1) The TR NOX Annual allowances will be allocated to 
the following TR NOX Annual units, except as provided in 
paragraph (b)(10) of this section:
    (i) TR NOX Annual units that are not allocated an amount 
of TR NOX Annual allowances in the notice of data 
availability issued under Sec.  97.411(a)(1); or
    (ii) For purposes of paragraph (b)(9) of this section, TR 
NOX Annual units under Sec.  97.411(c)(1)(ii) whose 
allocation of an amount of TR NOX Annual allowances for such 
control period in the notice of data availability issued under Sec.  
97.411(b)(2)(ii)(B) is covered by Sec.  97.411(c)(2) or (3).
    (2) The Administrator will establish a separate Indian country new 
unit set-aside for the State for each such control period. Each such 
Indian country new unit set-aside will be allocated TR NOX 
Annual allowances in an amount equal to the applicable amount of tons 
of NOX emissions as set forth in Sec.  97.410(a) and will be 
allocated additional TR NOX Annual allowances (if any) in 
accordance with Sec.  97.411(c)(5).
    (3) The Administrator will determine, for each TR NOX 
Annual unit described in paragraph (b)(1) of this section, an 
allocation of TR NOX Annual allowances for the later of the 
following control periods and for each subsequent control period:
    (i) The control period in 2012; and
    (ii) The first control period after the control period in which the 
TR NOX Annual unit commences commercial operation.
    (4)(i) The allocation to each TR NOX annual unit 
described in paragraph (b)(1)(i) of this section and for each control 
period described in paragraph (b)(3) of this section will be an amount 
equal to the unit's total tons of NOX emissions during the 
immediately preceding control period.
    (ii) The Administrator will adjust the allocation amount in 
paragraph (b)(4)(i) in accordance with paragraphs (b)(5) through (7) 
and (12) of this section.
    (5) The Administrator will calculate the sum of the TR 
NOX Annual allowances determined for all such TR 
NOX Annual units under paragraph (b)(4)(i) of this section 
in Indian country within the borders of the State for such control 
period.
    (6) If the amount of TR NOX Annual allowances in the 
Indian country new unit set-aside for the State for such control period 
is greater than or equal to the sum under paragraph (b)(5) of this 
section, then the Administrator will allocate the amount of TR 
NOX Annual allowances determined for each such TR 
NOX Annual unit under paragraph (b)(4)(i) of this section.
    (7) If the amount of TR NOX Annual allowances in the 
Indian country new unit set-aside for the State for such control period 
is less than the sum under paragraph (b)(5) of this section, then the 
Administrator will allocate to each such TR NOX Annual unit 
the amount of the TR NOX Annual allowances determined under 
paragraph (b)(4)(i) of this section for the unit, multiplied by the 
amount of TR NOX Annual allowances in the Indian country new 
unit set-aside for such control period, divided by the sum under 
paragraph (b)(5) of this section, and rounded to the nearest allowance.
    (8) The Administrator will notify the public, through the 
promulgation of the notices of data availability described in Sec.  
97.411(b)(2)(i) and (ii), of the amount of TR NOX Annual 
allowances allocated under paragraphs (b)(2) through (7) and (12) of 
this section for such control period to each TR NOX Annual 
unit eligible for such allocation.
    (9) If, after completion of the procedures under paragraphs (b)(5) 
through (8) of this section for such control period, any unallocated TR 
NOX Annual allowances remain in the Indian country new unit 
set-aside for the State for such control period, the Administrator will 
allocate such TR NOX Annual allowances as follows--
    (i) The Administrator will determine, for each unit described in 
paragraph (b)(1) of this section that commenced commercial operation 
during the period starting January 1 of the year before the year of 
such control period and ending November 30 of year of such control 
period, the positive difference (if any) between the unit's emissions 
during such control period and the amount of TR NOX Annual 
allowances referenced in the notice of data availability required under 
Sec.  97.411(b)(2)(ii) for the unit for such control period;
    (ii) The Administrator will determine the sum of the positive 
differences determined under paragraph (b)(9)(i) of this section;
    (iii) If the amount of unallocated TR NOX Annual 
allowances remaining in the Indian country new unit set-aside for the 
State for such control period is greater than or equal to the sum 
determined under paragraph (b)(9)(ii) of this section, then the 
Administrator will allocate the amount of TR NOX Annual 
allowances determined for each such TR NOX Annual unit under 
paragraph (b)(9)(i) of this section; and
    (iv) If the amount of unallocated TR NOX Annual 
allowances remaining in the Indian country new unit set-aside for the 
State for such control period is less than the sum under paragraph 
(b)(9)(ii) of this section, then the Administrator will allocate to 
each such TR NOX Annual unit the amount of the TR 
NOX Annual allowances determined under paragraph (b)(9)(i) 
of this section for the unit, multiplied by the amount of unallocated 
TR NOX Annual allowances remaining in the Indian country new 
unit set-aside for such control period, divided by the sum under 
paragraph (b)(9)(ii) of this section, and rounded to the nearest 
allowance.
    (10) If, after completion of the procedures under paragraphs (b)(9) 
and (12) of this section for such control period, any unallocated TR 
NOX Annual allowances remain in the Indian country new unit 
set-aside for the State for such control period, the Administrator 
will:
    (i) Transfer such unallocated TR NOX Annual allowances 
to the new unit set-aside for the State for such control period; or
    (ii) If the State has a SIP revision approved under Sec.  
52.38(a)(4) or (5) covering such control period, include such 
unallocated TR NOX Annual allowances in the portion of the 
State NOX Annual trading budget that may be allocated for 
such control period in accordance with such SIP revision.
    (11) The Administrator will notify the public, through the 
promulgation of the notices of data availability described in Sec.  
97.411(b)(2)(iii), (iv), and (v), of the amount of TR NOX 
Annual allowances allocated under paragraphs (b)(9), (10), and (12) of 
this section for such control period to each TR NOX Annual 
unit eligible for such allocation.
    (12)(i) Notwithstanding the requirements of paragraphs (b)(2) 
through (11) of this section, if the calculations of allocations of an 
Indian country new unit set-aside for a control period in a given year 
under paragraph (b)(7) of this section, paragraphs (b)(6) and (9)(iv) 
of this section, or paragraphs (b)(6), (9)(iii), and (10) of this 
section would otherwise result in total allocations of such Indian 
country new unit set-aside exceeding the total amount of such Indian 
country new unit set-aside, then the Administrator will adjust the 
results of the calculations

[[Page 48394]]

under paragraph (b)(7), (9)(iv), or (10) of this section, as 
applicable, as follows. The Administrator will list the TR 
NOX Annual units in descending order based on the amount of 
such units' allocations under paragraph (b)(7), (9)(iv), or (10) of 
this section, as applicable, and, in cases of equal allocation amounts, 
in alphabetical order of the relevant source's name and numerical order 
of the relevant unit's identification number, and will reduce each 
unit's allocation under paragraph (b)(7), (9)(iv), or (10) of this 
section, as applicable, by one TR NOX Annual allowance (but 
not below zero) in the order in which the units are listed and will 
repeat this reduction process as necessary, until the total allocations 
of such Indian country new unit set-aside equal the total amount of 
such Indian country new unit set-aside.
    (ii) Notwithstanding the requirements of paragraphs (b)(10) and 
(11) of this section, if the calculations of allocations of an Indian 
country new unit set-aside for a control period in a given year under 
paragraphs (b)(6), (9)(iii), and (10) of this section would otherwise 
result in a total allocations of such Indian country new unit set-aside 
less than the total amount of such Indian country new unit set-aside, 
then the Administrator will adjust the results of the calculations 
under paragraph (b)(10) of this section, as follows. The Administrator 
will list the TR NOX Annual units in descending order based 
on the amount of such units' allocations under paragraph (b)(10) of 
this section and, in cases of equal allocation amounts, in alphabetical 
order of the relevant source's name and numerical order of the relevant 
unit's identification number, and will increase each unit's allocation 
under paragraph (b)(10) of this section by one TR NOX Annual 
allowance in the order in which the units are listed and will repeat 
this increase process as necessary, until the total allocations of such 
Indian country new unit set-aside equal the total amount of such Indian 
country new unit set-aside.

Sec.  97.413  Authorization of designated representative and alternate 
designated representative.

    (a) Except as provided under Sec.  97.415, each TR NOX 
Annual source, including all TR NOX Annual units at the 
source, shall have one and only one designated representative, with 
regard to all matters under the TR NOX Annual Trading 
Program.
    (1) The designated representative shall be selected by an agreement 
binding on the owners and operators of the source and all TR 
NOX Annual units at the source and shall act in accordance 
with the certification statement in Sec.  97.416(a)(4)(iii).
    (2) Upon and after receipt by the Administrator of a complete 
certificate of representation under Sec.  97.416:
    (i) The designated representative shall be authorized and shall 
represent and, by his or her representations, actions, inactions, or 
submissions, legally bind each owner and operator of the source and 
each TR NOX Annual unit at the source in all matters 
pertaining to the TR NOX Annual Trading Program, 
notwithstanding any agreement between the designated representative and 
such owners and operators; and
    (ii) The owners and operators of the source and each TR 
NOX Annual unit at the source shall be bound by any decision 
or order issued to the designated representative by the Administrator 
regarding the source or any such unit.
    (b) Except as provided under Sec.  97.415, each TR NOX 
Annual source may have one and only one alternate designated 
representative, who may act on behalf of the designated representative. 
The agreement by which the alternate designated representative is 
selected shall include a procedure for authorizing the alternate 
designated representative to act in lieu of the designated 
representative.
    (1) The alternate designated representative shall be selected by an 
agreement binding on the owners and operators of the source and all TR 
NOX Annual units at the source and shall act in accordance 
with the certification statement in Sec.  97.416(a)(4)(iii).
    (2) Upon and after receipt by the Administrator of a complete 
certificate of representation under Sec.  97.416,
    (i) The alternate designated representative shall be authorized;
    (ii) Any representation, action, inaction, or submission by the 
alternate designated representative shall be deemed to be a 
representation, action, inaction, or submission by the designated 
representative; and
    (iii) The owners and operators of the source and each TR 
NOX Annual unit at the source shall be bound by any decision 
or order issued to the alternate designated representative by the 
Administrator regarding the source or any such unit.
    (c) Except in this section, Sec.  97.402, and Sec. Sec.  97.414 
through 97.418, whenever the term ``designated representative'' (as 
distinguished from the term ``common designated representative'') is 
used in this subpart, the term shall be construed to include the 
designated representative or any alternate designated representative.

Sec.  97.414  Responsibilities of designated representative and 
alternate designated representative.

    (a) Except as provided under Sec.  97.418 concerning delegation of 
authority to make submissions, each submission under the TR 
NOX Annual Trading Program shall be made, signed, and 
certified by the designated representative or alternate designated 
representative for each TR NOX Annual source and TR 
NOX Annual unit for which the submission is made. Each such 
submission shall include the following certification statement by the 
designated representative or alternate 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.''
    (b) The Administrator will accept or act on a submission made for a 
TR NOX Annual source or a TR NOX Annual unit only 
if the submission has been made, signed, and certified in accordance 
with paragraph (a) of this section and Sec.  97.418.

Sec.  97.415  Changing designated representative and alternate 
designated representative; changes in owners and operators; changes in 
units at the source.

    (a) Changing designated representative. The designated 
representative may be changed at any time upon receipt by the 
Administrator of a superseding complete certificate of representation 
under Sec.  97.416. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
designated representative before the time and date when the 
Administrator receives the superseding certificate of representation 
shall be binding on the new designated representative and the owners 
and operators of the TR NOX Annual source and the TR 
NOX Annual units at the source.
    (b) Changing alternate designated representative. The alternate 
designated representative may be changed at any

[[Page 48395]]

time upon receipt by the Administrator of a superseding complete 
certificate of representation under Sec.  97.416. Notwithstanding any 
such change, all representations, actions, inactions, and submissions 
by the previous alternate designated representative before the time and 
date when the Administrator receives the superseding certificate of 
representation shall be binding on the new alternate designated 
representative, the designated representative, and the owners and 
operators of the TR NOX Annual source and the TR 
NOX Annual units at the source.
    (c) Changes in owners and operators. (1) In the event an owner or 
operator of a TR NOX Annual source or a TR NOX 
Annual unit at the source is not included in the list of owners and 
operators in the certificate of representation under Sec.  97.416, such 
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 designated representative and any alternate 
designated representative of the source or unit, and the decisions and 
orders of the Administrator, as if the owner or operator were included 
in such list.
    (2) Within 30 days after any change in the owners and operators of 
a TR NOX Annual source or a TR NOX Annual unit at 
the source, including the addition or removal of an owner or operator, 
the designated representative or any alternate designated 
representative shall submit a revision to the certificate of 
representation under Sec.  97.416 amending the list of owners and 
operators to reflect the change.
    (d) Changes in units at the source. Within 30 days of any change in 
which units are located at a TR NOX Annual source (including 
the addition or removal of a unit), the designated representative or 
any alternate designated representative shall submit a certificate of 
representation under Sec.  97.416 amending the list of units to reflect 
the change.
    (1) If the change is the addition of a unit that operated (other 
than for purposes of testing by the manufacturer before initial 
installation) before being located at the source, then the certificate 
of representation shall identify, in a format prescribed by the 
Administrator, the entity from whom the unit was purchased or otherwise 
obtained (including name, address, telephone number, and facsimile 
number (if any)), the date on which the unit was purchased or otherwise 
obtained, and the date on which the unit became located at the source.
    (2) If the change is the removal of a unit, then the certificate of 
representation shall identify, in a format prescribed by the 
Administrator, the entity to which the unit was sold or that otherwise 
obtained the unit (including name, address, telephone number, and 
facsimile number (if any)), the date on which the unit was sold or 
otherwise obtained, and the date on which the unit became no longer 
located at the source.

Sec.  97.416  Certificate of representation.

    (a) A complete certificate of representation for a designated 
representative or an alternate designated representative shall include 
the following elements in a format prescribed by the Administrator:
    (1) Identification of the TR NOX Annual source, and each 
TR NOX Annual unit at the source, for which the certificate 
of representation is submitted, including source name, source category 
and NAICS code (or, in the absence of a NAICS code, an equivalent 
code), State, plant code, county, latitude and longitude, unit 
identification number and type, identification number and nameplate 
capacity (in MWe, rounded to the nearest tenth) of each generator 
served by each such unit, actual or projected date of commencement of 
commercial operation, and a statement of whether such source is located 
in Indian Country. If a projected date of commencement of commercial 
operation is provided, the actual date of commencement of commercial 
operation shall be provided when such information becomes available.
    (2) The name, address, e-mail address (if any), telephone number, 
and facsimile transmission number (if any) of the designated 
representative and any alternate designated representative.
    (3) A list of the owners and operators of the TR NOX 
Annual source and of each TR NOX Annual unit at the source.
    (4) The following certification statements by the designated 
representative and any alternate designated representative--
    (i) ``I certify that I was selected as the designated 
representative or alternate designated representative, as applicable, 
by an agreement binding on the owners and operators of the source and 
each TR NOX Annual unit at the source.''
    (ii) ``I certify that I have all the necessary authority to carry 
out my duties and responsibilities under the TR NOX Annual 
Trading Program on behalf of the owners and operators of the source and 
of each TR NOX Annual unit at the source and that each such 
owner and operator shall be fully bound by my representations, actions, 
inactions, or submissions and by any decision or order issued to me by 
the Administrator regarding the source or unit.''
    (iii) ``Where there are multiple holders of a legal or equitable 
title to, or a leasehold interest in, a TR NOX Annual unit, 
or where a utility or industrial customer purchases power from a TR 
NOX Annual 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 `designated representative' or `alternate 
designated representative', as applicable, and of the agreement by 
which I was selected to each owner and operator of the source and of 
each TR NOX Annual unit at the source; and TR NOX 
Annual allowances and proceeds of transactions involving TR 
NOX Annual 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 TR NOX Annual allowances by contract, TR NOX 
Annual allowances and proceeds of transactions involving TR 
NOX Annual allowances will be deemed to be held or 
distributed in accordance with the contract.''
    (5) The signature of the designated representative and any 
alternate designated representative and the dates signed.
    (b) Unless otherwise required by the Administrator, documents of 
agreement referred to in the certificate of representation shall not be 
submitted to the Administrator. The Administrator shall not be under 
any obligation to review or evaluate the sufficiency of such documents, 
if submitted.

Sec.  97.417  Objections concerning designated representative and 
alternate designated representative.

    (a) Once a complete certificate of representation under Sec.  
97.416 has been submitted and received, the Administrator will rely on 
the certificate of representation unless and until a superseding 
complete certificate of representation under Sec.  97.416 is received 
by the Administrator.
    (b) Except as provided in paragraph (a) of this section, no 
objection or other communication submitted to the Administrator 
concerning the authorization, or any representation, action, inaction, 
or submission, of a designated representative or alternate designated 
representative shall affect any representation, action, inaction, or 
submission of the designated representative or alternate designated 
representative or the finality of any

[[Page 48396]]

decision or order by the Administrator under the TR NOX 
Annual Trading Program.
    (c) The Administrator will not adjudicate any private legal dispute 
concerning the authorization or any representation, action, inaction, 
or submission of any designated representative or alternate designated 
representative, including private legal disputes concerning the 
proceeds of TR NOX Annual allowance transfers.

Sec.  97.418  Delegation by designated representative and alternate 
designated representative.

    (a) A designated representative may delegate, to one or more 
natural persons, his or her authority to make an electronic submission 
to the Administrator provided for or required under this subpart.
    (b) An alternate designated representative may delegate, to one or 
more natural persons, his or her authority to make an electronic 
submission to the Administrator provided for or required under this 
subpart.
    (c) In order to delegate authority to a natural person to make an 
electronic submission to the Administrator in accordance with paragraph 
(a) or (b) of this section, the designated representative or alternate 
designated representative, as appropriate, must submit to the 
Administrator a notice of delegation, in a format prescribed by the 
Administrator, that includes the following elements:
    (1) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of such designated 
representative or alternate designated representative;
    (2) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of each such natural person 
(referred to in this section as an ``agent'');
    (3) For each such natural person, a list of the type or types of 
electronic submissions under paragraph (a) or (b) of this section for 
which authority is delegated to him or her; and
    (4) The following certification statements by such designated 
representative or alternate designated representative:
    (i) ``I agree that any electronic submission to the Administrator 
that is made by an agent identified in this notice of delegation and of 
a type listed for such agent in this notice of delegation and that is 
made when I am a designated representative or alternate designated 
representative, as appropriate, and before this notice of delegation is 
superseded by another notice of delegation under 40 CFR 97.418(d) shall 
be deemed to be an electronic submission by me.''
    (ii) ``Until this notice of delegation is superseded by another 
notice of delegation under 40 CFR 97.418(d), I agree to maintain an e-
mail account and to notify the Administrator immediately of any change 
in my e-mail address unless all delegation of authority by me under 40 
CFR 97.418 is terminated.''.
    (d) A notice of delegation submitted under paragraph (c) of this 
section shall be effective, with regard to the designated 
representative or alternate designated representative identified in 
such notice, upon receipt of such notice by the Administrator and until 
receipt by the Administrator of a superseding notice of delegation 
submitted by such designated representative or alternate designated 
representative, as appropriate. The superseding notice of delegation 
may replace any previously identified agent, add a new agent, or 
eliminate entirely any delegation of authority.
    (e) Any electronic submission covered by the certification in 
paragraph (c)(4)(i) of this section and made in accordance with a 
notice of delegation effective under paragraph (d) of this section 
shall be deemed to be an electronic submission by the designated 
representative or alternate designated representative submitting such 
notice of delegation.

Sec.  97.419  [Reserved]

Sec.  97.420  Establishment of compliance accounts, assurance accounts, 
and general accounts.

    (a) Compliance accounts. Upon receipt of a complete certificate of 
representation under Sec.  97.416, the Administrator will establish a 
compliance account for the TR NOX Annual source for which 
the certificate of representation was submitted, unless the source 
already has a compliance account. The designated representative and any 
alternate designated representative of the source shall be the 
authorized account representative and the alternate authorized account 
representative respectively of the compliance account.
    (b) Assurance accounts. The Administrator will establish assurance 
accounts for certain owners and operators and States in accordance with 
Sec.  97.425(b)(3).
    (c) General accounts. (1) Application for general account. (i) Any 
person may apply to open a general account, for the purpose of holding 
and transferring TR NOX Annual allowances, by submitting to 
the Administrator a complete application for a general account. Such 
application shall designate one and only one authorized account 
representative and may designate one and only one alternate authorized 
account representative who may act on behalf of the authorized account 
representative.
    (A) The authorized account representative and alternate authorized 
account representative shall be selected by an agreement binding on the 
persons who have an ownership interest with respect to TR 
NOX Annual allowances held in the general account.
    (B) The agreement by which the alternate authorized account 
representative is selected shall include a procedure for authorizing 
the alternate authorized account representative to act in lieu of the 
authorized account representative.
    (ii) A complete application for a general account 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 authorized 
account representative and any alternate authorized account 
representative;
    (B) An identifying name for the general account;
    (C) A list of all persons subject to a binding agreement for the 
authorized account representative and any alternate authorized account 
representative to represent their ownership interest with respect to 
the TR NOX Annual allowances held in the general account;
    (D) The following certification statement by the authorized account 
representative and any alternate authorized account representative: ``I 
certify that I was selected as the authorized account representative or 
the alternate authorized account representative, as applicable, by an 
agreement that is binding on all persons who have an ownership interest 
with respect to TR NOX Annual allowances held in the general 
account. I certify that I have all the necessary authority to carry out 
my duties and responsibilities under the TR 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 decision or order issued to me by the 
Administrator regarding the general account.''
    (E) The signature of the authorized account representative and any 
alternate authorized account representative and the dates signed.
    (iii) Unless otherwise required by the Administrator, documents of 
agreement referred to in the application for a

[[Page 48397]]

general account shall not be submitted to the Administrator. The 
Administrator shall not be under any obligation to review or evaluate 
the sufficiency of such documents, if submitted.
    (2) Authorization of authorized account representative and 
alternate authorized account representative. (i) Upon receipt by the 
Administrator of a complete application for a general account under 
paragraph (b)(1) of this section, the Administrator will establish a 
general account for the person or persons for whom the application is 
submitted, and upon and after such receipt by the Administrator:
    (A) The authorized account representative of the general account 
shall be authorized and shall represent and, by his or her 
representations, actions, inactions, or submissions, legally bind each 
person who has an ownership interest with respect to TR NOX 
Annual allowances held in the general account in all matters pertaining 
to the TR NOX Annual Trading Program, notwithstanding any 
agreement between the authorized account representative and such 
person.
    (B) Any alternate authorized account representative shall be 
authorized, and any representation, action, inaction, or submission by 
any alternate authorized account representative shall be deemed to be a 
representation, action, inaction, or submission by the authorized 
account representative.
    (C) Each person who has an ownership interest with respect to TR 
NOX Annual allowances held in the general account shall be 
bound by any decision or order issued to the authorized account 
representative or alternate authorized account representative by the 
Administrator regarding the general account.
    (ii) Except as provided in paragraph (c)(5) of this section 
concerning delegation of authority to make submissions, each submission 
concerning the general account shall be made, signed, and certified by 
the authorized account representative or any alternate authorized 
account representative for the persons having an ownership interest 
with respect to TR NOX Annual allowances held in the general 
account. Each such submission shall include the following certification 
statement by the authorized account representative or any alternate 
authorized account representative: ``I am authorized to make this 
submission on behalf of the persons having an ownership interest with 
respect to the TR NOX Annual 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) Except in this section, whenever the term ``authorized 
account representative'' is used in this subpart, the term shall be 
construed to include the authorized account representative or any 
alternate authorized account representative.
    (3) Changing authorized account representative and alternate 
authorized account representative; changes in persons with ownership 
interest. (i) The authorized account representative of 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 (c)(1) of this section. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
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 authorized account representative 
and the persons with an ownership interest with respect to the TR 
NOX Annual allowances in the general account.
    (ii) The alternate authorized account representative of 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 (c)(1) of this section. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
alternate 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 authorized 
account representative, the authorized account representative, and the 
persons with an ownership interest with respect to the TR 
NOX Annual allowances in the general account.
    (iii)(A) In the event a person having an ownership interest with 
respect to TR NOX Annual allowances in the general account 
is not included in the list of such persons in the application for a 
general account, such 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 authorized account representative and 
any alternate authorized account representative of the account, and the 
decisions and orders of the Administrator, as if the person were 
included in such list.
    (B) Within 30 days after any change in the persons having an 
ownership interest with respect to NOX Annual allowances in 
the general account, including the addition or removal of a person, the 
authorized account representative or any alternate 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 TR NOX Annual allowances in the general 
account to include the change.
    (4) Objections concerning authorized account representative and 
alternate authorized account representative. (i) Once a complete 
application for a general account under paragraph (c)(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 (c)(4)(i) of this section, no 
objection or other communication submitted to the Administrator 
concerning the authorization, or any representation, action, inaction, 
or submission of the authorized account representative or any alternate 
authorized account representative of a general account shall affect any 
representation, action, inaction, or submission of the authorized 
account representative or any alternate authorized account 
representative or the finality of any decision or order by the 
Administrator under the TR 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 authorized account representative or any 
alternate authorized account representative of a general account, 
including private legal disputes concerning the proceeds of TR 
NOX Annual allowance transfers.
    (5) Delegation by authorized account representative and alternate 
authorized account representative. (i) An authorized account 
representative of a general account may delegate, to one or more 
natural persons, his or her authority to make an electronic submission 
to the Administrator

[[Page 48398]]

provided for or required under this subpart.
    (ii) An alternate authorized account representative of a general 
account may delegate, to one or more natural persons, his or her 
authority to make an electronic submission to the Administrator 
provided for or required under this subpart.
    (iii) In order to delegate authority to a natural person to make an 
electronic submission to the Administrator in accordance with paragraph 
(c)(5)(i) or (ii) of this section, the authorized account 
representative or alternate authorized account representative, as 
appropriate, must submit to the Administrator a notice of delegation, 
in a format prescribed by the Administrator, that includes the 
following elements:
    (A) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of such authorized account 
representative or alternate authorized account representative;
    (B) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of each such natural person 
(referred to in this section as an ``agent'');
    (C) For each such natural person, a list of the type or types of 
electronic submissions under paragraph (c)(5)(i) or (ii) of this 
section for which authority is delegated to him or her;
    (D) The following certification statement by such authorized 
account representative or alternate authorized account representative: 
``I agree that any electronic submission to the Administrator that is 
made by an agent identified in this notice of delegation and of a type 
listed for such agent in this notice of delegation and that is made 
when I am an authorized account representative or alternate authorized 
representative, as appropriate, and before this notice of delegation is 
superseded by another notice of delegation under 40 CFR 
97.420(c)(5)(iv) shall be deemed to be an electronic submission by 
me.''; and
    (E) The following certification statement by such authorized 
account representative or alternate authorized account representative: 
``Until this notice of delegation is superseded by another notice of 
delegation under 40 CFR 97.420(c)(5)(iv), I agree to maintain an e-mail 
account and to notify the Administrator immediately of any change in my 
e-mail address unless all delegation of authority by me under 40 CFR 
97.420(c)(5) is terminated.''.
    (iv) A notice of delegation submitted under paragraph (c)(5)(iii) 
of this section shall be effective, with regard to the authorized 
account representative or alternate authorized account representative 
identified in such notice, upon receipt of such notice by the 
Administrator and until receipt by the Administrator of a superseding 
notice of delegation submitted by such authorized account 
representative or alternate authorized account representative, as 
appropriate. The superseding notice of delegation may replace any 
previously identified agent, add a new agent, or eliminate entirely any 
delegation of authority.
    (v) Any electronic submission covered by the certification in 
paragraph (c)(5)(iii)(D) of this section and made in accordance with a 
notice of delegation effective under paragraph (c)(5)(iv) of this 
section shall be deemed to be an electronic submission by the 
designated representative or alternate designated representative 
submitting such notice of delegation.
    (6) Closing a general account. (i) The authorized account 
representative or alternate authorized account representative of a 
general account may submit to the Administrator a request to close the 
account. Such request shall include a correctly submitted TR 
NOX Annual allowance transfer under Sec.  97.422 for any TR 
NOX Annual allowances in the account to one or more other 
Allowance Management System accounts.
    (ii) If a general account has no TR NOX Annual allowance 
transfers to or from the account for a 12-month period or longer and 
does not contain any TR NOX Annual allowances, the 
Administrator may notify the authorized account representative for the 
account that the account will be closed after 30 days after the notice 
is sent. The account will be closed after the 30-day period unless, 
before the end of the 30-day period, the Administrator receives a 
correctly submitted TR NOX Annual allowance transfer under 
Sec.  97.422 to the account or a statement submitted by the authorized 
account representative or alternate authorized account representative 
demonstrating to the satisfaction of the Administrator good cause as to 
why the account should not be closed.
    (d) Account identification. The Administrator will assign a unique 
identifying number to each account established under paragraph (a), 
(b), or (c) of this section.
    (e) Responsibilities of authorized account representative and 
alternate authorized account representative. After the establishment of 
a compliance account or general account, the Administrator will accept 
or act on a submission pertaining to the account, including, but not 
limited to, submissions concerning the deduction or transfer of TR 
NOX Annual allowances in the account, only if the submission 
has been made, signed, and certified in accordance with Sec. Sec.  
97.414(a) and 97.418 or paragraphs (c)(2)(ii) and (c)(5) of this 
section.

Sec.  97.421  Recordation of TR NOX Annual allowance allocations and 
auction results.

    (a) By November 7, 2011, the Administrator will record in each TR 
NOX Annual source's compliance account the TR NOX 
Annual allowances allocated to the TR NOX Annual units at 
the source in accordance with Sec.  97.411(a) for the control period in 
2012.
    (b) By November 7, 2011, the Administrator will record in each TR 
NOX Annual source's compliance account the TR NOX 
Annual allowances allocated to the TR NOX Annual units at 
the source in accordance with Sec.  97.411(a) for the control period in 
2013, unless the State in which the source is located notifies the 
Administrator in writing by October 17, 2011 of the State's intent to 
submit to the Administrator a complete SIP revision by April 1, 2012 
meeting the requirements of Sec.  52.38(a)(3)(i) through (iv) of this 
chapter.
    (1) If, by April 1, 2012, the State does not submit to the 
Administrator such complete SIP revision, the Administrator will record 
by April 15, 2012 in each TR NOX Annual source's compliance 
account the TR NOX Annual allowances allocated to the TR 
NOX Annual units at the source in accordance with Sec.  
97.411(a) for the control period in 2013.
    (2) If the State submits to the Administrator by April 1, 2012, and 
the Administrator approves by October 1, 2012, such complete SIP 
revision, the Administrator will record by October 1, 2012 in each TR 
NOX Annual source's compliance account the TR NOX 
Annual allowances allocated to the TR NOX Annual units at 
the source as provided in such approved, complete SIP revision for the 
control period in 2013.
    (3) If the State submits to the Administrator by April 1, 2012, and 
the Administrator does not approve by October 1, 2012, such complete 
SIP revision, the Administrator will record by October 1, 2012 in each 
TR NOX Annual source's compliance account the TR 
NOX Annual allowances allocated to the TR NOX 
Annual units at the source in accordance with Sec.  97.411(a) for the 
control period in 2013.
    (c) By July 1, 2013, the Administrator will record in each TR 
NOX Annual source's compliance account the TR

[[Page 48399]]

NOX Annual allowances allocated to the TR NOX 
Annual units at the source, or in each appropriate Allowance Management 
System account the TR NOX Annual allowances auctioned to TR 
NOX Annual units, in accordance with Sec.  97.411(a), or 
with a SIP revision approved under Sec.  52.38(a)(4) or (5) of this 
chapter, for the control period in 2014 and 2015.
    (d) By July 1, 2014, the Administrator will record in each TR 
NOX Annual source's compliance account the TR NOX 
Annual allowances allocated to the TR NOX Annual units at 
the source, or in each appropriate Allowance Management System account 
the TR NOX Annual allowances auctioned to TR NOX 
Annual units, in accordance with Sec.  97.411(a), or with a SIP 
revision approved under Sec.  52.38(a)(4) or (5) of this chapter, for 
the control period in 2016 and 2017.
    (e) By July 1, 2015, the Administrator will record in each TR 
NOX Annual source's compliance account the TR NOX 
Annual allowances allocated to the TR NOX Annual units at 
the source, or in each appropriate Allowance Management System account 
the TR NOX Annual allowances auctioned to TR NOX 
Annual units, in accordance with Sec.  97.411(a), or with a SIP 
revision approved under Sec.  52.38(a)(4) or (5) of this chapter, for 
the control period in 2018 and 2019.
    (f) By July 1, 2016 and July 1 of each year thereafter, the 
Administrator will record in each TR NOX Annual source's 
compliance account the TR NOX Annual allowances allocated to 
the TR NOX Annual units at the source, or in each 
appropriate Allowance Management System account the TR NOX 
Annual allowances auctioned to TR NOX Annual units, in 
accordance with Sec.  97.411(a), or with a SIP revision approved under 
Sec.  52.38(a)(4) or (5) of this chapter, for the control period in the 
fourth year after the year of the applicable recordation deadline under 
this paragraph.
    (g) By August 1, 2012 and August 1 of each year thereafter, the 
Administrator will record in each TR NOX Annual source's 
compliance account the TR NOX Annual allowances allocated to 
the TR NOX Annual units at the source, or in each 
appropriate Allowance Management System account the TR NOX 
Annual allowances auctioned to TR NOX Annual units, in 
accordance with Sec.  97.412(a)(2) through (8) and (12), or with a SIP 
revision approved under Sec.  52.38(a)(4) or (5) of this chapter, for 
the control period in the year of the applicable recordation deadline 
under this paragraph.
    (h) By August 1, 2012 and August 1 of each year thereafter, the 
Administrator will record in each TR NOX Annual source's 
compliance account the TR NOX Annual allowances allocated to 
the TR NOX Annual units at the source in accordance with 
Sec.  97.412(b)(2) through (8) and (12) for the control period in the 
year of the applicable recordation deadline under this paragraph.
    (i) By February 15, 2013 and February 15 of each year thereafter, 
the Administrator will record in each TR NOX Annual source's 
compliance account the TR NOX Annual allowances allocated to 
the TR NOX Annual units at the source in accordance with 
Sec.  97.412(a)(9) through (12), for the control period in the year 
before the year of the applicable recordation deadline under this 
paragraph.
    (j) By the date on which any allocation or auction results, other 
than an allocation or auction results described in paragraphs (a) 
through (i) of this section, of TR NOX Annual allowances to 
a recipient is made by or are submitted to the Administrator in 
accordance with Sec.  97.411 or Sec.  97.412 or with a SIP revision 
approved under Sec.  52.38(a)(4) or (5) of this chapter, the 
Administrator will record such allocation or auction results in the 
appropriate Allowance Management System account.
    (k) When recording the allocation or auction of TR NOX 
Annual allowances to a TR NOX Annual unit or other entity in 
an Allowance Management System account, the Administrator will assign 
each TR NOX Annual allowance a unique identification number 
that will include digits identifying the year of the control period for 
which the TR NOX Annual allowance is allocated or auctioned.

Sec.  97.422  Submission of TR NOX Annual allowance transfers.

    (a) An authorized account representative seeking recordation of a 
TR NOX Annual allowance transfer shall submit the transfer 
to the Administrator.
    (b) A TR NOX Annual allowance transfer shall be 
correctly submitted if:
    (1) The transfer includes the following elements, in a format 
prescribed by the Administrator:
    (i) The account numbers established by the Administrator for both 
the transferor and transferee accounts;
    (ii) The serial number of each TR NOX Annual allowance 
that is in the transferor account and is to be transferred; and
    (iii) The name and signature of the authorized account 
representative of the transferor account and the date signed; and
    (2) When the Administrator attempts to record the transfer, the 
transferor account includes each TR NOX Annual allowance 
identified by serial number in the transfer.

Sec.  97.423  Recordation of TR NOX Annual allowance transfers.

    (a) Within 5 business days (except as provided in paragraph (b) of 
this section) of receiving a TR NOX Annual allowance 
transfer that is correctly submitted under Sec.  97.422, the 
Administrator will record a TR NOX Annual allowance transfer 
by moving each TR NOX Annual allowance from the transferor 
account to the transferee account as specified in the transfer.
    (b) A TR NOX Annual allowance transfer to or from a 
compliance account that is submitted for recordation after the 
allowance transfer deadline for a control period and that includes any 
TR NOX Annual allowances allocated for any control period 
before such allowance transfer deadline will not be recorded until 
after the Administrator completes the deductions from such compliance 
account under Sec.  97.424 for the control period immediately before 
such allowance transfer deadline.
    (c) Where a TR NOX Annual allowance transfer is not 
correctly submitted under Sec.  97.422, the Administrator will not 
record such transfer.
    (d) Within 5 business days of recordation of a TR NOX 
Annual allowance transfer under paragraphs (a) and (b) of the section, 
the Administrator will notify the authorized account representatives of 
both the transferor and transferee accounts.
    (e) Within 10 business days of receipt of a TR NOX 
Annual allowance transfer that is not correctly submitted under Sec.  
97.422, the Administrator will notify the 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.

Sec.  97.424  Compliance with TR NOX Annual emissions limitation.

    (a) Availability for deduction for compliance. TR NOX 
Annual allowances are available to be deducted for compliance with a 
source's TR NOX Annual emissions limitation for a control 
period in a given year only if the TR NOX Annual allowances:
    (1) Were allocated for such control period or a control period in a 
prior year; and

[[Page 48400]]

    (2) Are held in the source's compliance account as of the allowance 
transfer deadline for such control period.
    (b) Deductions for compliance. After the recordation, in accordance 
with Sec.  97.423, of TR NOX Annual allowance transfers 
submitted by the allowance transfer deadline for a control period in a 
given year, the Administrator will deduct from each source's compliance 
account TR NOX Annual allowances available under paragraph 
(a) of this section in order to determine whether the source meets the 
TR NOX Annual emissions limitation for such control period, 
as follows:
    (1) Until the amount of TR NOX Annual allowances 
deducted equals the number of tons of total NOX emissions 
from all TR NOX Annual units at the source for such control 
period; or
    (2) If there are insufficient TR NOX Annual allowances 
to complete the deductions in paragraph (b)(1) of this section, until 
no more TR NOX Annual allowances available under paragraph 
(a) of this section remain in the compliance account.
    (c)(1) Identification of TR NOX Annual allowances by serial number. 
The authorized account representative for a source's compliance account 
may request that specific TR NOX Annual allowances, 
identified by serial number, in the compliance account be deducted for 
emissions or excess emissions for a control period in a given year in 
accordance with paragraph (b) or (d) of this section. In order to be 
complete, such request shall be submitted to the Administrator by the 
allowance transfer deadline for such control period and include, in a 
format prescribed by the Administrator, the identification of the TR 
NOX Annual source and the appropriate serial numbers.
    (2) First-in, first-out. The Administrator will deduct TR 
NOX Annual allowances under paragraph (b) or (d) of this 
section from the source's compliance account in accordance with a 
complete request under paragraph (c)(1) of this section or, in the 
absence of such request or in the case of identification of an 
insufficient amount of TR NOX Annual allowances in such 
request, on a first-in, first-out accounting basis in the following 
order:
    (i) Any TR NOX Annual allowances that were allocated to 
the units at the source and not transferred out of the compliance 
account, in the order of recordation; and then
    (ii) Any TR NOX Annual allowances that were allocated to 
any unit and transferred to and recorded in the compliance account 
pursuant to this subpart, in the order of recordation.
    (d) Deductions for excess emissions. After making the deductions 
for compliance under paragraph (b) of this section for a control period 
in a year in which the TR NOX Annual source has excess 
emissions, the Administrator will deduct from the source's compliance 
account an amount of TR NOX Annual allowances, allocated for 
a control period in a prior year or the control period in the year of 
the excess emissions or in the immediately following year, equal to two 
times the number of tons of the source's excess emissions.
    (e) Recordation of deductions. The Administrator will record in the 
appropriate compliance account all deductions from such an account 
under paragraphs (b) and (d) of this section.

Sec.  97.425  Compliance with TR NOX Annual assurance provisions.

    (a) Availability for deduction. TR NOX Annual allowances 
are available to be deducted for compliance with the TR NOX 
Annual assurance provisions for a control period in a given year by the 
owners and operators of a group of one or more TR NOX Annual 
sources and units in a State (and Indian country within the borders of 
such State) only if the TR NOX Annual allowances:
    (1) Were allocated for a control period in a prior year or the 
control period in the given year or in the immediately following year; 
and
    (2) Are held in the assurance account, established by the 
Administrator for such owners and operators of such group of TR 
NOX Annual sources and units in such State (and Indian 
country within the borders of such State) under paragraph (b)(3) of 
this section, as of the deadline established in paragraph (b)(4) of 
this section.
    (b) Deductions for compliance. The Administrator will deduct TR 
NOX Annual allowances available under paragraph (a) of this 
section for compliance with the TR NOX Annual assurance 
provisions for a State for a control period in a given year in 
accordance with the following procedures:
    (1) By June 1, 2013 and June 1 of each year thereafter, the 
Administrator will:
    (i) Calculate, for each State (and Indian country within the 
borders of such State), the total NOX emissions from all TR 
NOX Annual units at TR NOX Annual sources in the 
State (and Indian country within the borders of such State) during the 
control period in the year before the year of this calculation deadline 
and the amount, if any, by which such total NOX emissions 
exceed the State assurance level as described in Sec.  
97.406(c)(2)(iii); and
    (ii) Promulgate a notice of data availability of the results of the 
calculations required in paragraph (b)(1)(i) of this section, including 
separate calculations of the NOX emissions from each TR 
NOX Annual source.
    (2) For each notice of data availability required in paragraph 
(b)(1)(ii) of this section and for any State (and Indian country within 
the borders of such State) identified in such notice as having TR 
NOX Annual units with total NOX emissions 
exceeding the State assurance level for a control period in a given 
year, as described in Sec.  97.406(c)(2)(iii):
    (i) By July 1 immediately after the promulgation of such notice, 
the designated representative of each TR NOX Annual source 
in each such State (and Indian country within the borders of such 
State) shall submit a statement, in a format prescribed by the 
Administrator, providing for each TR NOX Annual unit (if 
any) at the source that operates during, but is not allocated an amount 
of TR NOX Annual allowances for, such control period, the 
unit's allowable NOX emission rate for such control period 
and, if such rate is expressed in lb per mmBtu, the unit's heat rate.
    (ii) By August 1 immediately after the promulgation of such notice, 
the Administrator will calculate, for each such State (and Indian 
country within the borders of such State) and such control period and 
each common designated representative for such control period for a 
group of one or more TR NOX Annual sources and units in the 
State (and Indian country within the borders of such State), the common 
designated representative's share of the total NOX emissions 
from all TR NOX Annual units at TR NOX Annual 
sources in the State (and Indian country within the borders of such 
State), the common designated representative's assurance level, and the 
amount (if any) of TR NOX Annual allowances that the owners 
and operators of such group of sources and units must hold in 
accordance with the calculation formula in Sec.  97.406(c)(2)(i) and 
will promulgate a notice of data availability of the results of these 
calculations.
    (iii) The Administrator will provide an opportunity for submission 
of objections to the calculations referenced by the notice of data 
availability required in paragraph (b)(2)(ii) of this section and the 
calculations referenced by the relevant notice of data availability 
required in paragraph (b)(1)(i) of this section.
    (A) Objections shall be submitted by the deadline specified in such 
notice

[[Page 48401]]

and shall be limited to addressing whether the calculations referenced 
in the relevant notice required under paragraph (b)(1)(ii) of this 
section and referenced in the notice required under paragraph 
(b)(2)(ii) of this section are in accordance with Sec.  
97.406(c)(2)(iii), Sec. Sec.  97.406(b) and 97.430 through 97.435, the 
definitions of ``common designated representative'', ``common 
designated representative's assurance level'', and ``common designated 
representative's share'' in Sec.  97.402, and the calculation formula 
in Sec.  97.406(c)(2)(i).
    (B) The Administrator will adjust the calculations to the extent 
necessary to ensure that they are in accordance with the provisions 
referenced in paragraph (b)(2)(iii)(A) of this section. By October 1 
immediately after the promulgation of such notice, the Administrator 
will promulgate a notice of data availability of any adjustments that 
the Administrator determines to be necessary and the reasons for 
accepting or rejecting any objections submitted in accordance with 
paragraph (b)(2)(iii)(A) of this section.
    (3) For any State (and Indian country within the borders of such 
State) referenced in each notice of data availability required in 
paragraph (b)(2)(iii)(B) of this section as having TR NOX 
Annual units with total NOX emissions exceeding the State 
assurance level for a control period in a given year, the Administrator 
will establish one assurance account for each set of owners and 
operators referenced, in the notice of data availability required under 
paragraph (b)(2)(iii)(B) of this section, as all of the owners and 
operators of a group of TR NOX Annual sources and units in 
the State (and Indian country within the borders of such State) having 
a common designated representative for such control period and as being 
required to hold TR NOX Annual allowances.
    (4)(i) As of midnight of November 1 immediately after the 
promulgation of each notice of data availability required in paragraph 
(b)(2)(iii)(B) of this section, the owners and operators described in 
paragraph (b)(3) of this section shall hold in the assurance account 
established for the them and for the appropriate TR NOX 
Annual sources, TR NOX Annual units, and State (and Indian 
country within the borders of such State) under paragraph (b)(3) of 
this section a total amount of TR NOX Annual allowances, 
available for deduction under paragraph (a) of this section, equal to 
the amount such owners and operators are required to hold with regard 
to such sources, units and State (and Indian country within the borders 
of such State) as calculated by the Administrator and referenced in 
such notice.
    (ii) Notwithstanding the allowance-holding deadline specified in 
paragraph (b)(4)(i) of this section, if November 1 is not a business 
day, then such allowance-holding deadline shall be midnight of the 
first business day thereafter.
    (5) After November 1 (or the date described in paragraph (b)(4)(ii) 
of this section) immediately after the promulgation of each notice of 
data availability required in paragraph (b)(2)(iii)(B) of this section 
and after the recordation, in accordance with Sec.  97.423, of TR 
NOX Annual allowance transfers submitted by midnight of such 
date, the Administrator will determine whether the owners and operators 
described in paragraph (b)(3) of this section hold, in the assurance 
account for the appropriate TR NOX Annual sources, TR 
NOX Annual units, and State (and Indian country within the 
borders of such State) established under paragraph (b)(3) of this 
section, the amount of TR NOX Annual allowances available 
under paragraph (a) of this section that the owners and operators are 
required to hold with regard to such sources, units, and State (and 
Indian country within the borders of such State) as calculated by the 
Administrator and referenced in the notice required in paragraph 
(b)(2)(iii)(B) of this section.
    (6) Notwithstanding any other provision of this subpart and any 
revision, made by or submitted to the Administrator after the 
promulgation of the notice of data availability required in paragraph 
(b)(2)(iii)(B) of this section for a control period in a given year, of 
any data used in making the calculations referenced in such notice, the 
amounts of TR NOX Annual allowances that the owners and 
operators are required to hold in accordance with Sec.  97.406(c)(2)(i) 
for such control period shall continue to be such amounts as calculated 
by the Administrator and referenced in such notice required in 
paragraph (b)(2)(iii)(B) of this section, except as follows:
    (i) If any such data are revised by the Administrator as a result 
of a decision in or settlement of litigation concerning such data on 
appeal under part 78 of this chapter of such notice, or on appeal under 
section 307 of the Clean Air Act of a decision rendered under part 78 
of this chapter on appeal of such notice, then the Administrator will 
use the data as so revised to recalculate the amounts of TR 
NOX Annual allowances that owners and operators are required 
to hold in accordance with the calculation formula in Sec.  
97.406(c)(2)(i) for such control period with regard to the TR 
NOX Annual sources, TR NOX Annual units, and 
State (and Indian country within the borders of such State) involved, 
provided that such litigation under part 78 of this chapter, or the 
proceeding under part 78 of this chapter that resulted in the decision 
appealed in such litigation under section 307 of the Clean Air Act, was 
initiated no later than 30 days after promulgation of such notice 
required in paragraph (b)(2)(iii)(B) of this section.
    (ii) If any such data are revised by the owners and operators of a 
TR NOX Annual source and TR NOX Annual unit whose 
designated representative submitted such data under paragraph (b)(2)(i) 
of this section, as a result of a decision in or settlement of 
litigation concerning such submission, then the Administrator will use 
the data as so revised to recalculate the amounts of TR NOX 
Annual allowances that owners and operators are required to hold in 
accordance with the calculation formula in Sec.  97.406(c)(2)(i) for 
such control period with regard to the TR NOX Annual 
sources, TR NOX Annual units, and State (and Indian country 
within the borders of such State) involved, provided that such 
litigation was initiated no later than 30 days after promulgation of 
such notice required in paragraph (b)(2)(iii)(B) of this section.
    (iii) If the revised data are used to recalculate, in accordance 
with paragraphs (b)(6)(i) and (ii) of this section, the amount of TR 
NOX Annual allowances that the owners and operators are 
required to hold for such control period with regard to the TR 
NOX Annual sources, TR NOX Annual units, and 
State (and Indian country within the borders of such State) involved--
    (A) Where the amount of TR NOX Annual allowances that 
the owners and operators are required to hold increases as a result of 
the use of all such revised data, the Administrator will establish a 
new, reasonable deadline on which the owners and operators shall hold 
the additional amount of TR NOX Annual allowances in the 
assurance account established by the Administrator for the appropriate 
TR NOX Annual sources, TR NOX Annual units, and 
State (and Indian country within the borders of such State) under 
paragraph (b)(3) of this section. The owners' and operators' failure to 
hold such additional amount, as required, before the new deadline shall 
not be a violation of the Clean Air Act. The owners' and operators' 
failure to hold such additional amount, as required, as of the new 
deadline shall be a violation of the Clean Air Act. Each

[[Page 48402]]

TR NOX Annual allowance that the owners and operators fail 
to hold as required as of the new deadline, and each day in such 
control period, shall be a separate violation of the Clean Air Act.
    (B) For the owners and operators for which the amount of TR 
NOX Annual allowances required to be held decreases as a 
result of the use of all such revised data, the Administrator will 
record, in all accounts from which TR NOX Annual allowances 
were transferred by such owners and operators for such control period 
to the assurance account established by the Administrator for the 
appropriate at TR NOX Annual sources, TR NOX 
Annual units, and State (and Indian country within the borders of such 
State) under paragraph (b)(3) of this section, a total amount of the TR 
NOX Annual allowances held in such assurance account equal 
to the amount of the decrease. If TR NOX Annual allowances 
were transferred to such assurance account from more than one account, 
the amount of TR NOX Annual allowances recorded in each such 
transferor account will be in proportion to the percentage of the total 
amount of TR NOX Annual allowances transferred to such 
assurance account for such control period from such transferor account.
    (C) Each TR NOX Annual allowance held under paragraph 
(b)(6)(iii)(A) of this section as a result of recalculation of 
requirements under the TR NOX Annual assurance provisions 
for such control period must be a TR NOX Annual allowance 
allocated for a control period in a year before or the year immediately 
following, or in the same year as, the year of such control period.

Sec.  97.426  Banking.

    (a) A TR NOX Annual allowance 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 TR NOX Annual allowance that is held in a 
compliance account or a general account will remain in such account 
unless and until the TR NOX Annual allowance is deducted or 
transferred under Sec.  97.411(c), Sec.  97.423, Sec.  97.424, Sec.  
97.425, 97.427, or 97.428.

Sec.  97.427  Account error.

    The Administrator may, at his or her sole discretion and on his or 
her own motion, correct any error in any Allowance Management System 
account. Within 10 business days of making such correction, the 
Administrator will notify the authorized account representative for the 
account.

Sec.  97.428  Administrator's action on submissions.

    (a) The Administrator may review and conduct independent audits 
concerning any submission under the TR NOX Annual Trading 
Program and make appropriate adjustments of the information in the 
submission.
    (b) The Administrator may deduct TR NOX Annual 
allowances from or transfer TR NOX Annual allowances to a 
compliance account or an assurance account, based on the information in 
a submission, as adjusted under paragraph (a)(1) of this section, and 
record such deductions and transfers.

Sec.  97.429  [Reserved]

Sec.  97.430  General monitoring, recordkeeping, and reporting 
requirements.

    The owners and operators, and to the extent applicable, the 
designated representative, of a TR NOX Annual unit, shall 
comply with the monitoring, recordkeeping, and reporting requirements 
as provided in this subpart and subpart H of part 75 of this chapter. 
For purposes of applying such requirements, the definitions in Sec.  
97.402 and in Sec.  72.2 of this chapter shall apply, 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 ``TR NOX Annual 
unit,'' ``designated representative,'' and ``continuous emission 
monitoring system'' (or ``CEMS'') respectively as defined in Sec.  
97.402, and the term ``newly affected unit'' shall be deemed to mean 
``newly affected TR NOX Annual unit''. The owner or operator 
of a unit that is not a TR NOX Annual 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 TR 
NOX Annual unit.
    (a) Requirements for installation, certification, and data 
accounting. The owner or operator of each TR NOX Annual 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.  97.431 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. Except as provided in paragraph (e) of 
this section, 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 and 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 TR NOX Annual unit 
that commences commercial operation before July 1, 2011, January 1, 
2012;
    (2) For the owner or operator of a TR NOX Annual unit 
that commences commercial operation on or after July 1, 2011, the later 
of the following:
    (i) January 1, 2012; or
    (ii) 180 calendar days after the date on which the unit commences 
commercial operation;
    (3) The owner or operator of a TR NOX Annual 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) or (2) of this section shall meet the 
requirements of Sec. Sec.  75.4(e)(1) through (e)(4) of this chapter, 
except that:
    (i) Such requirements shall apply to the monitoring systems 
required under Sec.  97.430 through Sec.  97.435, rather than the 
monitoring systems required under part 75 of this chapter;
    (ii) NOX emission rate, NOX concentration, 
stack gas moisture content, stack gas volumetric flow rate, and 
O2 or CO2 concentration data shall be determined 
and reported, rather than the data listed in Sec.  75.4(e)(2) of this 
chapter; and
    (iii) Any petition for another procedure under Sec.  75.4(e)(2) of 
this chapter shall be submitted under Sec.  97.435, rather than Sec.  
75.66.
    (c) Reporting data. The owner or operator of a TR NOX 
Annual 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

[[Page 48403]]

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.
    (d) Prohibitions. (1) No owner or operator of a TR NOX 
Annual 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.  97.435.
    (2) No owner or operator of a TR NOX Annual unit shall 
operate the unit so as to discharge, or allow to be discharged, 
NOX to the atmosphere without accounting for all such 
NOX in accordance with the applicable provisions of this 
subpart and part 75 of this chapter.
    (3) No owner or operator of a TR NOX Annual 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 discharged into the 
atmosphere or heat input, 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 TR NOX Annual 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.  97.405 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 Administrator 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 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.  
97.431(d)(3)(i).
    (e) Long-term cold storage. The owner or operator of a TR 
NOX Annual unit is subject to the applicable provisions of 
Sec.  75.4(d) of this chapter concerning units in long-term cold 
storage.

Sec.  97.431  Initial monitoring system certification and 
recertification procedures.

    (a) The owner or operator of a TR NOX Annual unit shall 
be exempt from the initial certification requirements of this section 
for a monitoring system under Sec.  97.430(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 appendices B, D, and 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.  97.430(a)(1) that is 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 or Sec.  75.17 of this chapter, the designated 
representative shall resubmit the petition to the Administrator under 
Sec.  97.435 to determine whether the approval applies under the TR 
NOX Annual Trading Program.
    (d) Except as provided in paragraph (a) of this section, the owner 
or operator of a TR NOX Annual 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.  97.430(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.  
97.430(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.  97.430(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.  97.430(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.  97.430(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. 
For initial certification of a continuous monitoring system under Sec.  
97.430(a)(1), paragraphs (d)(3)(i) through (v) of this section apply. 
For recertifications of such monitoring systems, paragraphs (d)(3)(i) 
through (iv) of this section and 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) apply, provided that in applying 
paragraphs (d)(3)(i) through (iv) of this section, the words 
``certification'' and ``initial certification'' are replaced by the 
word ``recertification'' and the word ``certified'' is replaced by with 
the word ``recertified''.
    (i) Notification of certification. The designated representative 
shall submit to the appropriate EPA Regional Office and the 
Administrator written notice of the dates of certification testing, in 
accordance with Sec.  97.433.

[[Page 48404]]

    (ii) Certification application. The designated representative shall 
submit to the Administrator 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 TR NOX Annual Trading Program 
for a period not to exceed 120 days after receipt by the Administrator 
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 Administrator 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 Administrator.
    (iv) Certification application approval process. The Administrator 
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 Administrator 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 TR 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 Administrator 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 Administrator will issue a written notice of 
incompleteness that sets a reasonable date by which the designated 
representative must submit the additional information required to 
complete the certification application. If the designated 
representative does not comply with the notice of incompleteness by the 
specified date, then the Administrator may issue a notice of 
disapproval under paragraph (d)(3)(iv)(C) of this section.
    (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 Administrator 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 Administrator 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).
    (D) Audit decertification. The Administrator may issue a notice of 
disapproval of the certification status of a monitor in accordance with 
Sec.  97.432(b).
    (v) Procedures for loss of certification. If 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 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 Administrator's notice of disapproval, no later than 
30 unit operating days after the date of issuance of the notice of 
disapproval.
    (e) 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) The designated representative of each unit for which the owner 
or operator intends to use an alternative monitoring system approved by 
the Administrator 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.  97.432  Monitoring system out-of-control periods.

    (a) General provisions. 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.  97.431 or 
the applicable provisions of part 75 of this chapter, both at the time 
of the initial certification or

[[Page 48405]]

recertification application submission and at the time of the audit, 
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 Administrator or any State or 
permitting authority. By issuing the notice of disapproval, 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.  
97.431 for each disapproved monitoring system.

Sec.  97.433  Notifications concerning monitoring.

    The designated representative of a TR NOX Annual unit 
shall submit written notice to the Administrator in accordance with 
Sec.  75.61 of this chapter.

Sec.  97.434  Recordkeeping and reporting.

    (a) General provisions. The designated representative shall comply 
with all recordkeeping and reporting requirements in paragraphs (b) 
through (e) of this section, the applicable recordkeeping and reporting 
requirements under Sec.  75.73 of this chapter, and the requirements of 
Sec.  97.414(a).
    (b) Monitoring plans. The owner or operator of a TR NOX 
Annual unit shall comply with requirements of Sec.  75.73(c) and (e) of 
this chapter.
    (c) Certification applications. The designated representative shall 
submit an application to the Administrator within 45 days after 
completing all initial certification or recertification tests required 
under Sec.  97.431, including the information required under Sec.  
75.63 of this chapter.
    (d) Quarterly reports. The designated representative shall submit 
quarterly reports, as follows:
    (1) The designated representative shall report the NOX 
mass emissions data and heat input data for the TR NOX 
Annual 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, 
2011, the calendar quarter covering January 1, 2012 through March 31, 
2012; or
    (ii) For a unit that commences commercial operation on or after 
July 1, 2011, the calendar quarter corresponding to the earlier of the 
date of provisional certification or the applicable deadline for 
initial certification under Sec.  97.430(b), unless that quarter is the 
third or fourth quarter of 2011, in which case reporting shall commence 
in the quarter covering January 1, 2012 through March 31, 2012.
    (2) The designated representative shall submit each quarterly 
report to the Administrator within 30 days after 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 TR NOX Annual units that are also subject to the 
Acid Rain Program, TR NOX Ozone Season Trading Program, TR 
SO2 Group 1 Trading Program, or TR SO2 Group 2 
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.
    (4) The Administrator may review and conduct independent audits of 
any quarterly report in order to determine whether the quarterly report 
meets the requirements of this subpart and part 75 of this chapter, 
including the requirement to use substitute data.
    (i) The Administrator will notify the designated representative of 
any determination that the quarterly report fails to meet any such 
requirements and specify in such notification any corrections that the 
Administrator believes are necessary to make through resubmission of 
the quarterly report and a reasonable time period within which the 
designated representative must respond. Upon request by the designated 
representative, the Administrator may specify reasonable extensions of 
such time period. Within the time period (including any such 
extensions) specified by the Administrator, the designated 
representative shall resubmit the quarterly report with the corrections 
specified by the Administrator, except to the extent the designated 
representative provides information demonstrating that a specified 
correction is not necessary because the quarterly report already meets 
the requirements of this subpart and part 75 of this chapter that are 
relevant to the specified correction.
    (ii) Any resubmission of a quarterly report shall meet the 
requirements applicable to the submission of a quarterly report under 
this subpart and part 75 of this chapter, except for the deadline set 
forth in paragraph (d)(2) of this section.
    (e) Compliance certification. The 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 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.  97.435  Petitions for alternatives to monitoring, recordkeeping, 
or reporting requirements.

    (a) The designated representative of a TR NOX Annual 
unit may submit a petition under Sec.  75.66 of this chapter to the 
Administrator, requesting approval to apply an alternative to any 
requirement of Sec. Sec.  97.430 through 97.434.
    (b) A petition submitted under paragraph (a) of this section shall 
include sufficient information for the evaluation of the petition, 
including, at a minimum, the following information:
    (i) Identification of each unit and source covered by the petition;
    (ii) A detailed explanation of why the proposed alternative is 
being suggested in lieu of the requirement;
    (iii) A description and diagram of any equipment and procedures 
used in the proposed alternative;
    (iv) A demonstration that the proposed alternative is consistent 
with the purposes of the requirement for which the alternative is 
proposed and with the purposes of this subpart and part 75 of this 
chapter and that any adverse effect of approving the alternative will 
be de minimis; and

[[Page 48406]]

    (v) Any other relevant information that the Administrator may 
require.
    (c) Use of an alternative to any requirement referenced in 
paragraph (a) of this section is in accordance with this subpart only 
to the extent that the petition is approved in writing by the 
Administrator and that such use is in accordance with such approval.

0
75. Part 97 is amended by adding subpart BBBBB to read as follows:
Subpart BBBBB--TR NOX Ozone Season Trading Program
97.501 Purpose.
97.502 Definitions.
97.503 Measurements, abbreviations, and acronyms.
97.504 Applicability.
97.505 Retired unit exemption.
97.506 Standard requirements.
97.507 Computation of time.
97.508 Administrative appeal procedures.
97.509 [Reserved]
97.510 State NOX Ozone Season trading budgets, new unit 
set-asides, Indian country new unit set-asides and variability 
limits.
97.511 Timing requirements for TR NOX Ozone Season 
allowance allocations.
97.512 TR NOX Ozone Season allowance allocations to new 
units.
97.513 Authorization of designated representative and alternate 
designated representative.
97.514 Responsibilities of designated representative and alternate 
designated representative.
97.515 Changing designated representative and alternate designated 
representative; changes in owners and operators.
97.516 Certificate of representation.
97.517 Objections concerning designated representative and alternate 
designated representative.
97.518 Delegation by designated representative and alternate 
designated representative.
97.519 [Reserved]
97.520 Establishment of compliance accounts and general accounts.
97.521 Recordation of TR NOX Ozone Season allowance 
allocations.
97.522 Submission of TR NOX Ozone Season allowance 
transfers.
97.523 Recordation of TR NOX Ozone Season allowance 
transfers.
97.524 Compliance with TR NOX Ozone Season emissions 
limitation.
97.525 Compliance with TR NOX Ozone Season assurance 
provisions.
97.526 Banking.
97.527 Account error.
97.528 Administrator's action on submissions.
97.529 [RESERVED]
97.530 General monitoring, recordkeeping, and reporting 
requirements.
97.531 Initial monitoring system certification and recertification 
procedures.
97.532 Monitoring system out-of-control periods.
97.533 Notifications concerning monitoring.
97.534 Recordkeeping and reporting.
97.535 Petitions for alternatives to monitoring, recordkeeping, or 
reporting requirements.

Subpart BBBBB--TR NOX Ozone Season Trading Program

Sec.  97.501  Purpose.

    This subpart sets forth the general, designated representative, 
allowance, and monitoring provisions for the Transport Rule (TR) 
NOX Ozone Season Trading Program, under section 110 of the 
Clean Air Act and Sec.  52.38 of this chapter, as a means of mitigating 
interstate transport of ozone and nitrogen oxides.

Sec.  97.502  Definitions.

    The terms used in this subpart shall have the meanings set forth in 
this section as follows:
    Acid Rain Program means a multi-state SO2 and 
NOX air pollution control and emission reduction program 
established by the Administrator under title IV of the Clean Air Act 
and parts 72 through 78 of this chapter.
    Administrator means the Administrator of the United States 
Environmental Protection Agency or the Director of the Clean Air 
Markets Division (or its successor determined by the Administrator) of 
the United States Environmental Protection Agency, the Administrator's 
duly authorized representative under this subpart.
    Allocate or allocation means, with regard to TR NOX 
Ozone Season allowances, the determination by the Administrator, State, 
or permitting authority, in accordance with this subpart and any SIP 
revision submitted by the State and approved by the Administrator under 
Sec.  52.38(b)(3), (4), or (5) of this chapter, of the amount of such 
TR NOX Ozone Season allowances to be initially credited, at 
no cost to the recipient, to:
    (1) A TR NOX Ozone Season unit;
    (2) A new unit set-aside;
    (3) An Indian country new unit set-aside; or
    (4) An entity not listed in paragraphs (1) through (3) of this 
definition;
    (5) Provided that, if the Administrator, State, or permitting 
authority initially credits, to a TR NOX Ozone Season unit 
qualifying for an initial credit, a credit in the amount of zero TR 
NOX Ozone Season allowances, the TR NOX Ozone 
Season unit will be treated as being allocated an amount (i.e., zero) 
of TR NOX Ozone Season allowances.
    Allowable NOX emission rate means, for a unit, the most stringent 
State or federal NOX emission rate limit (in lb/MWhr or, if 
in lb/mmBtu, converted to lb/MWhr by multiplying it by the unit's heat 
rate in mmBtu/MWhr) that is applicable to the unit and covers the 
longest averaging period not exceeding one year.
    Allowance Management System means the system by which the 
Administrator records allocations, deductions, and transfers of TR 
NOX Ozone Season allowances under the TR NOX 
Ozone Season Trading Program. Such allowances are allocated, recorded, 
held, deducted, or transferred only as whole allowances.
    Allowance Management System account means an account in the 
Allowance Management System established by the Administrator for 
purposes of recording the allocation, holding, transfer, or deduction 
of TR NOX Ozone Season allowances.
    Allowance transfer deadline means, for a control period in a given 
year, midnight of December 1 (if it is a business day), or midnight of 
the first business day thereafter (if December 1 is not a business 
day), immediately after such control period and is the deadline by 
which a TR NOX Ozone Season allowance transfer must be 
submitted for recordation in a TR NOX Ozone Season source's 
compliance account in order to be available for use in complying with 
the source's TR NOX Ozone Season emissions limitation for 
such control period in accordance with Sec. Sec.  97.506 and 97.524.
    Alternate designated representative means, for a TR NOX 
Ozone Season source and each TR 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 this subpart, to act on behalf of the designated representative in 
matters pertaining to the TR NOX Ozone Season Trading 
Program. If the TR NOX Ozone Season source is also subject 
to the Acid Rain Program, TR NOX Annual Trading Program, TR 
SO2 Group 1 Trading Program, or TR SO2 Group 2 
Trading Program, then this natural person shall be the same natural 
person as the alternate designated representative, as defined in the 
respective program.
    Assurance account means an Allowance Management System account, 
established by the Administrator under Sec.  97.525(b)(3) for certain 
owners and operators of a group of one or more TR NOX Ozone 
Season sources and units in a given State (and Indian country within 
the borders of such State), in which are held TR NOX Ozone 
Season allowances available for use for a control period in a given 
year in complying with the TR NOX Ozone

[[Page 48407]]

Season assurance provisions in accordance with Sec. Sec.  97.506 and 
97.525.
    Authorized account representative means, for a general account, the 
natural person who is authorized, in accordance with this subpart, to 
transfer and otherwise dispose of TR NOX Ozone Season 
allowances held in the general account and, for a TR NOX 
Ozone Season source's compliance account, the designated representative 
of the source.
    Automated data acquisition and handling system or DAHS means the 
component of the continuous emission monitoring system, or other 
emissions monitoring system approved for use under this subpart, 
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 this subpart.
    Biomass means--
    (1) Any organic material grown for the purpose of being converted 
to energy;
    (2) Any organic byproduct of agriculture that can be converted into 
energy; or
    (3) Any material that can be converted into energy and is 
nonmerchantable for other purposes, that is segregated from other 
material that is nonmerchantable for other purposes, and that is;
    (i) A forest-related organic resource, including mill residues, 
precommercial thinnings, slash, brush, or byproduct from conversion of 
trees to merchantable material; or
    (ii) A wood material, including pallets, crates, dunnage, 
manufacturing and construction materials (other than pressure-treated, 
chemically-treated, or painted wood products), and landscape or right-
of-way tree trimmings.
    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 unit means a unit in which the energy input to the 
unit is first used to produce useful thermal energy, where at least 
some of the reject heat from the useful thermal energy application or 
process is then used for electricity production.
    Business day means a day that does not fall on a weekend or a 
federal holiday.
    Certifying official means a natural person who is:
    (1) For a corporation, a president, secretary, treasurer, or vice-
president of the corporation in charge of a principal business function 
or any other person who performs similar policy- or decision-making 
functions for the corporation;
    (2) For a partnership or sole proprietorship, a general partner or 
the proprietor respectively; or
    (3) For a local government entity or State, federal, or other 
public agency, a principal executive officer or ranking elected 
official.
    Clean Air Act means the Clean Air Act, 42 U.S.C. 7401, et seq.
    Coal means ``coal'' as defined in Sec.  72.2 of this chapter.
    Coal-derived fuel means any fuel (whether in a solid, liquid, or 
gaseous state) produced by the mechanical, thermal, or chemical 
processing of coal.
    Cogeneration system means an integrated group, at a source, of 
equipment (including a boiler, or combustion turbine, and a steam 
turbine generator) designed to produce useful thermal energy for 
industrial, commercial, heating, or cooling purposes and electricity 
through the sequential use of energy.
    Cogeneration unit means a stationary, fossil-fuel-fired boiler or 
stationary, fossil-fuel-fired combustion turbine that is a topping-
cycle unit or a bottoming-cycle unit:
    (1) Operating as part of a cogeneration system; and
    (2) Producing on an annual average basis--
    (i) For a topping-cycle 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 than 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 unit, useful power not less than 45 
percent of total energy input;
    (3) Provided that the requirements in paragraph (2) of this 
definition shall not apply to a calendar year referenced in paragraph 
(2) of this definition during which the unit did not operate at all;
    (4) Provided that the total energy input under paragraphs (2)(i)(B) 
and (2)(ii) of this definition shall equal the unit's total energy 
input from all fuel, except biomass if the unit is a boiler; and
    (5) Provided that, if, throughout its operation during the 12-month 
period or a calendar year referenced in paragraph (2) of this 
definition, a unit is operated as part of a cogeneration system and the 
cogeneration system meets on a system-wide basis the requirement in 
paragraph (2)(i)(B) or (2)(ii) of this definition, the unit shall be 
deemed to meet such requirement during that 12-month period or calendar 
year.
    Combustion turbine means an enclosed device comprising:
    (1) If the device is simple cycle, 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 device is combined cycle, the equipment described in 
paragraph (1) of this definition and any associated duct burner, heat 
recovery steam generator, and steam turbine.
    Commence commercial operation means, with regard to a unit:
    (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.  97.505.
    (i) For a unit that is a TR NOX Ozone Season unit under 
Sec.  97.504 on the later of January 1, 2005 or the date the unit 
commences commercial operation as defined in the introductory text of 
paragraph (1) of this definition and that subsequently undergoes a 
physical change or is moved to a new location or source, such date 
shall remain the date of commencement of commercial operation of the 
unit, which shall continue to be treated as the same unit.
    (ii) For a unit that is a TR NOX Ozone Season unit under 
Sec.  97.504 on the later of January 1, 2005 or the date the unit 
commences commercial operation as defined in the introductory text of 
paragraph (1) of this definition and that is subsequently replaced by a 
unit at the same or a different source, such date shall remain the 
replaced unit's date of commencement of commercial operation, and the 
replacement unit shall be treated as a separate unit with a separate 
date for commencement of commercial operation as defined in paragraph 
(1) or (2) of this definition as appropriate.
    (2) Notwithstanding paragraph (1) of this definition and except as 
provided in Sec.  97.505, for a unit that is not a TR NOX 
Ozone Season unit under Sec.  97.504 on the later of January 1, 2005 or 
the date the unit commences commercial operation as defined in 
introductory text of paragraph (1) of this definition, the unit's date 
for commencement of commercial operation shall be the date on which the 
unit becomes a TR NOX Ozone Season unit under Sec.  97.504.
    (i) For a unit with a date for commencement of commercial operation 
as defined in the introductory text of paragraph (2) of this definition

[[Page 48408]]

and that subsequently undergoes a physical change or is moved to a 
different location or source, such date shall remain the date of 
commencement of commercial operation of the unit, which shall continue 
to be treated as the same unit.
    (ii) For a unit with a date for commencement of commercial 
operation as defined in the introductory text of paragraph (2) of this 
definition and that is subsequently replaced by a unit at the same or a 
different source, such date shall remain the replaced unit's date of 
commencement of commercial operation, and the replacement unit shall be 
treated as a separate unit with a separate date for commencement of 
commercial operation as defined in paragraph (1) or (2) of this 
definition as appropriate.
    Common designated representative means, with regard to a control 
period in a given year, a designated representative where, as of April 
1 immediately after the allowance transfer deadline for such control 
period, the same natural person is authorized under Sec. Sec.  
97.513(a) and 97.515(a) as the designated representative for a group of 
one or more TR NOX Ozone Season sources and units located in 
a State (and Indian country within the borders of such State).
    Common designated representative's assurance level means, with 
regard to a specific common designated representative and a State (and 
Indian country within the borders of such State) and control period in 
a given year for which the State assurance level is exceeded as 
described in Sec.  97.506(c)(2)(iii), the common designated 
representative's share of the State NOX Ozone Season trading 
budget with the variability limit for the State for such control 
period.
    Common designated representative's share means, with regard to a 
specific common designated representative for a control period in a 
given year:
    (1) With regard to a total amount of NOX emissions from 
all TR NOX Ozone Season units in a State (and Indian country 
within the borders of such State) during such control period, the total 
tonnage of NOX emissions during such control period from a 
group of one or more TR NOX Ozone Season units located in 
such State (and such Indian country) and having the common designated 
representative for such control period;
    (2) With regard to a State NOX Ozone Season trading 
budget with the variability limit for such control period, the amount 
(rounded to the nearest allowance) equal to the sum of the total amount 
of TR NOX Ozone Season allowances allocated for such control 
period to a group of one or more TR NOX Ozone Season units 
located in the State (and Indian country within the borders of such 
State) and having the common designated representative for such control 
period and of the total amount of TR NOX Ozone Season 
allowances purchased by an owner or operator of such TR NOX 
Ozone Season units in an auction for such control period and submitted 
by the State or the permitting authority to the Administrator for 
recordation in the compliance accounts for such TR NOX Ozone 
Season units in accordance with the TR NOX Ozone Season 
allowance auction provisions in a SIP revision approved by the 
Administrator under Sec.  52.38(b)(4) or (5) of this chapter, 
multiplied by the sum of the State NOX Ozone Season trading 
budget under Sec.  97.510(a) and the State's variability limit under 
Sec.  97.510(b) for such control period and divided by such State 
NOX Ozone Season trading budget;
    (3) Provided that, in the case of a unit that operates during, but 
has no amount of TR NOX Ozone Season allowances allocated 
under Sec. Sec.  97.511 and 97.512 for, such control period, the unit 
shall be treated, solely for purposes of this definition, as being 
allocated an amount (rounded to the nearest allowance) of TR 
NOX Ozone Season allowances for such control period equal to 
the unit's allowable NOX emission rate applicable to such 
control period, multiplied by a capacity factor of 0.92 (if the unit is 
a boiler combusting any amount of coal or coal-derived fuel during such 
control period), 0.32 (if the unit is a simple combustion turbine 
during such control period), 0.71 (if the unit is a combined cycle 
turbine during such control period), 0.73 (if the unit is an integrated 
coal gasification combined cycle unit during such control period), or 
0.44 (for any other unit), multiplied by the unit's maximum hourly load 
as reported in accordance with this subpart and by 3,672 hours/control 
period, and divided by 2,000 lb/ton.
    Common stack means a single flue through which emissions from 2 or 
more units are exhausted.
    Compliance account means an Allowance Management System account, 
established by the Administrator for a TR NOX Ozone Season 
source under this subpart, in which any TR NOX Ozone Season 
allowance allocations to the TR NOX Ozone Season units at 
the source are recorded and in which are held any TR NOX 
Ozone Season allowances available for use for a control period in a 
given year in complying with the source's TR NOX Ozone 
Season emissions limitation in accordance with Sec. Sec.  97.506 and 
97.524.
    Continuous emission monitoring system or CEMS means the equipment 
required under this subpart to sample, analyze, measure, and provide, 
by means of readings recorded at least once every 15 minutes and using 
an automated data acquisition and handling system (DAHS), a permanent 
record of NOX emissions, stack gas volumetric flow rate, 
stack gas moisture content, and O2 or CO2 
concentration (as applicable), in a manner consistent with part 75 of 
this chapter and Sec. Sec.  97.530 through 97.535. The following 
systems are the principal types of continuous emission monitoring 
systems:
    (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 NOX 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 NOX 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 CO2 monitoring system, consisting of a 
CO2 pollutant concentration monitor (or an O2 
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 O2 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 starting May 1 of a calendar year, 
except as provided in Sec.  97.506(c)(3), and

[[Page 48409]]

ending on September 30 of the same year, inclusive.
    Designated representative means, for a TR NOX Ozone 
Season source and each TR 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 this subpart, to represent and legally bind each owner and 
operator in matters pertaining to the TR NOX Ozone Season 
Trading Program. If the TR NOX Ozone Season source is also 
subject to the Acid Rain Program, TR NOX Annual Trading 
Program, TR SO2 Group 1 Trading Program, or TR 
SO2 Group 2 Trading Program, then this natural person shall 
be the same natural person as the designated representative, as defined 
in the respective program.
    Emissions means air pollutants exhausted from a unit or source into 
the atmosphere, as measured, recorded, and reported to the 
Administrator by the designated representative, and as modified by the 
Administrator:
    (1) In accordance with this subpart; and
    (2) With regard to a period before the unit or source is required 
to measure, record, and report such air pollutants in accordance with 
this subpart, in accordance with part 75 of this chapter.
    Excess emissions means any ton of emissions from the TR 
NOX Ozone Season units at a TR NOX Ozone Season 
source during a control period in a given year that exceeds the TR 
NOX Ozone Season emissions limitation for the source for 
such control period.
    Fossil fuel means--
    (1) Natural gas, petroleum, coal, or any form of solid, liquid, or 
gaseous fuel derived from such material; or
    (2) For purposes of applying the limitation on ``average annual 
fuel consumption of fossil fuel'' in Sec. Sec.  97.504(b)(2)(i)(B) and 
(ii), natural gas, petroleum, coal, or any form of solid, liquid, or 
gaseous fuel derived from such material for the purpose of creating 
useful heat.
    Fossil-fuel-fired means, with regard to a unit, combusting any 
amount of fossil fuel in 2005 or any calendar year thereafter.
    General account means an Allowance Management System account, 
established under this subpart, that is not a compliance account or an 
assurance account.
    Generator means a device that produces electricity.
    Gross electrical output means, for a 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, for a unit for a specified period of time, the 
product (in mmBtu/time) of the gross calorific value of the fuel (in 
mmBtu/lb) fed into the unit multiplied by the fuel feed rate (in lb of 
fuel/time), as measured, recorded, and reported to the Administrator by 
the designated representative and as modified by the Administrator in 
accordance with this subpart and excluding the heat derived from 
preheated combustion air, recirculated flue gases, or exhaust.
    Heat input rate means, for a unit, the amount of heat input (in 
mmBtu) divided by unit operating time (in hr) or, for a unit and 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.
    Heat rate means, for a unit, the unit's maximum design heat input 
(in Btu/hr), divided by the product of 1,000,000 Btu/mmBtu and the 
unit's maximum hourly load.
    Indian country means ``Indian country'' as defined in 18 U.S.C. 
1151.
    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, for a unit, the maximum amount of 
fuel per hour (in Btu/hr) that the unit is capable of combusting on a 
steady state basis as of the initial installation of the unit as 
specified by the manufacturer of the unit.
    Monitoring system means any monitoring system that meets the 
requirements of this subpart, including a continuous emission 
monitoring system, an alternative monitoring system, or an excepted 
monitoring system under part 75 of this chapter.
    Nameplate capacity means, starting from the initial installation of 
a generator, the maximum electrical generating output (in MWe, rounded 
to the nearest tenth) 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 of such installation 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 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 (in MWe, rounded to the nearest tenth) as of 
such completion as specified by the person conducting the physical 
change.
    Natural gas means ``natural gas'' as defined in Sec.  72.2 of this 
chapter.
    Newly affected TR NOX Ozone Season unit means a unit that was not a 
TR NOX Ozone Season unit when it began operating but that 
thereafter becomes a TR NOX Ozone Season unit.
    Operate or operation means, with regard to a unit, to combust fuel.
    Operator means, for a TR NOX Ozone Season source or a TR 
NOX Ozone Season unit at a source respectively, any person 
who operates, controls, or supervises a TR NOX Ozone Season 
unit at the source or the TR NOX Ozone Season unit and shall 
include, but not be limited to, any holding company, utility system, or 
plant manager of such source or unit.
    Owner means, for a TR NOX Ozone Season source or a TR 
NOX Ozone Season unit at a source respectively, any of the 
following persons:
    (1) Any holder of any portion of the legal or equitable title in a 
TR NOX Ozone Season unit at the source or the TR 
NOX Ozone Season unit;
    (2) Any holder of a leasehold interest in a TR NOX Ozone 
Season unit at the source or the TR NOX Ozone Season unit, 
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 TR NOX Ozone Season unit; and
    (3) Any purchaser of power from a TR NOX Ozone Season 
unit at the source or the TR NOX Ozone Season unit under a 
life-of-the-unit, firm power contractual arrangement.
    Permanently retired means, with regard to a unit, a unit that is

[[Page 48410]]

unavailable for service and that the unit's owners and operators do not 
expect to return to service in the future.
    Permitting authority means ``permitting authority'' as defined in 
Sec. Sec.  70.2 and 71.2 of this chapter.
    Potential electrical output capacity means, for a unit, 33 percent 
of the 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 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 log, or by a notation made on the document, 
information, or correspondence, by the Administrator in the regular 
course of business.
    Recordation, record, or recorded means, with regard to TR 
NOX Ozone Season allowances, the moving of TR NOX 
Ozone Season allowances by the Administrator into, out of, or between 
Allowance Management System accounts, for purposes of allocation, 
auction, 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.
    Replacement, replace, or replaced means, with regard to a unit, the 
demolishing of a unit, or the permanent retirement and permanent 
disabling of a unit, and the construction of another unit (the 
replacement unit) to be used instead of the demolished or retired unit 
(the replaced unit).
    Sequential use of energy means:
    (1) The use of reject heat from electricity production in a useful 
thermal energy application or process; or
    (2) The use of reject heat from useful thermal energy application 
or process in electricity production.
    Serial number means, for a TR NOX Ozone Season 
allowance, the unique identification number assigned to each TR 
NOX Ozone Season allowance by the Administrator.
    Solid waste incineration unit means a stationary, fossil-fuel-fired 
boiler or stationary, fossil-fuel-fired combustion turbine that is a 
``solid waste incineration unit'' as defined in section 129(g)(1) of 
the Clean Air Act.
    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. This definition does not change or 
otherwise affect the definition of ``major source'', ``stationary 
source'', or ``source'' as set forth and implemented in a title V 
operating permit program or any other program under the Clean Air Act.
    State means one of the States that is subject to the TR 
NOX Ozone Season Trading Program pursuant to Sec.  52.38(b) 
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;
    (4) Provided that compliance with any ``submission'' or ``service'' 
deadline shall be determined by the date of dispatch, transmission, or 
mailing and not the date of receipt.
    Topping-cycle unit means a unit in which the energy input to the 
unit is first used to produce useful power, including electricity, 
where at least some of the reject heat from the electricity production 
is then used to provide useful thermal energy.
    Total energy input means, for a unit, total energy of all forms 
supplied to the unit, excluding energy produced by the unit. Each form 
of energy supplied shall be measured by the lower heating value of that 
form of energy calculated as follows:

LHV = HHV - 10.55 (W + 9H)

Where:

LHV = lower heating value of the form of energy in Btu/lb,
HHV = higher heating value of the form of energy in Btu/lb,
W = weight % of moisture in the form of energy, and
H = weight % of hydrogen in the form of energy.

    Total energy output means, for a unit, the sum of useful power and 
useful thermal energy produced by the unit.
    TR NOX Annual Trading Program means a multi-state NOX 
air pollution control and emission reduction program established in 
accordance with subpart AAAAA of this part and Sec.  52.38(a) of this 
chapter (including such a program that is revised in a SIP revision 
approved by the Administrator under Sec.  52.38(a)(3) or (4) of this 
chapter or that is established in a SIP revision approved by the 
Administrator under Sec.  52.38(a)(5) of this chapter), as a means of 
mitigating interstate transport of fine particulates and 
NOX.
    TR NOX Ozone Season allowance means a limited authorization issued 
and allocated or auctioned by the Administrator under this subpart, or 
by a State or permitting authority under a SIP revision approved by the 
Administrator under Sec.  52.38(b)(3), (4), or (5) of this chapter, to 
emit one ton of NOX during a control period of the specified 
calendar year for which the authorization is allocated or auctioned or 
of any calendar year thereafter under the TR NOX Ozone 
Season Trading Program.
    TR NOX Ozone Season allowance deduction or deduct TR NOX Ozone 
Season allowances means the permanent withdrawal of TR NOX 
Ozone Season allowances by the Administrator from a compliance account 
(e.g., in order to account for compliance with the TR NOX 
Ozone Season emissions limitation) or from an assurance account (e.g., 
in order to account for compliance with the assurance provisions under 
Sec. Sec.  97.506 and 97.525).
    TR NOX Ozone Season allowances held or hold TR NOX Ozone Season 
allowances means the TR NOX Ozone Season allowances treated 
as included in an Allowance Management System account as of a specified 
point in time because at that time they:
    (1) Have been recorded by the Administrator in the account or 
transferred into the account by a correctly submitted, but not yet 
recorded, TR NOX Ozone Season allowance transfer in 
accordance with this subpart; and
    (2) Have not been transferred out of the account by a correctly 
submitted, but not yet recorded, TR NOX Ozone Season 
allowance transfer in accordance with this subpart.
    TR NOX Ozone Season emissions limitation means, for a TR 
NOX Ozone Season source, the tonnage of NOX 
emissions authorized in a control period in a given year by the TR 
NOX Ozone Season allowances available for deduction for the 
source under Sec.  97.524(a) for such control period.
    TR NOX Ozone Season source means a source that includes one or more 
TR NOX Ozone Season units.
    TR NOX Ozone Season Trading Program means a multi-state 
NOX air pollution control and emission reduction program 
established in accordance with this subpart and Sec.  52.38(b) of this 
chapter (including such a program that is revised in a SIP revision 
approved by the Administrator under Sec.  52.38(b)(3) or (4) of this 
chapter or that is established in a SIP revision approved by the 
Administrator under Sec.  52.38(b)(5) of this chapter), as a means of 
mitigating interstate transport of ozone and NOX.
    TR NOX Ozone Season unit means a unit that is subject to the TR 
NOX Ozone Season Trading Program.

[[Page 48411]]

    TR SO2 Group 1 Trading Program means a multi-state SO2 
air pollution control and emission reduction program established in 
accordance with subpart CCCCC of this part and 52.39(a), (b), (d) 
through (f), (j), and (k) of this chapter (including such a program 
that is revised in a SIP revision approved by the Administrator under 
Sec.  52.39(d) or (e) of this chapter or that is established in a SIP 
revision approved by the Administrator under Sec.  52.39(f) of this 
chapter), as a means of mitigating interstate transport of fine 
particulates and SO2.
    TR SO2 Group 2 Trading Program means a multi-state SO2 
air pollution control and emission reduction program established in 
accordance with subpart DDDDD of this part and 52.39(a), (c), and (g) 
through (k) of this chapter (including such a program that is revised 
in a SIP revision approved by the Administrator under Sec.  52.39(g) or 
(h) of this chapter or that is established in a SIP revision approved 
by the Administrator under Sec.  52.39(i) of this chapter), as a means 
of mitigating interstate transport of fine particulates and 
SO2.
    Unit means a stationary, fossil-fuel-fired boiler, stationary, 
fossil-fuel-fired combustion turbine, or other stationary, fossil-fuel-
fired combustion device. A unit that undergoes a physical change or is 
moved to a different location or source shall continue to be treated as 
the same unit. A unit (the replaced unit) that is replaced by another 
unit (the replacement unit) at the same or a different source shall 
continue to be treated as the same unit, and the replacement unit shall 
be treated as a separate unit.
    Unit operating day means, with regard to a unit, a calendar day in 
which the unit combusts any fuel.
    Unit operating hour or hour of unit operation means, with regard to 
a unit, an hour in which the unit combusts any fuel.
    Useful power means, with regard to a unit, electricity or 
mechanical energy that the unit makes 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 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., in 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.  97.503  Measurements, abbreviations, and acronyms.

    Measurements, abbreviations, and acronyms used in this subpart are 
defined as follows:

Btu--British thermal unit
CO2--carbon dioxide
H2O--water
hr--hour
kW--kilowatt electrical
kWh--kilowatt hour
lb--pound
mmBtu--million Btu
MWe--megawatt electrical
MWh--megawatt hour
NOX--nitrogen oxides
O2--oxygen
ppm--parts per million
scfh--standard cubic feet per hour
SO2--sulfur dioxide
yr--year

Sec.  97.504  Applicability.

    (a) Except as provided in paragraph (b) of this section:
    (1) The following units in a State (and Indian country within the 
borders of such State) shall be TR NOX Ozone Season units, 
and any source that includes one or more such units shall be a TR 
NOX Ozone Season source, subject to the requirements of this 
subpart: any stationary, fossil-fuel-fired boiler or stationary, 
fossil-fuel-fired combustion turbine serving at any time, on or after 
January 1, 2005, a generator with nameplate capacity of more than 25 
MWe producing electricity for sale.
    (2) If a stationary boiler or stationary combustion turbine that, 
under paragraph (a)(1) of this section, is not a TR NOX 
Ozone Season unit begins to combust fossil fuel or to serve a generator 
with nameplate capacity of more than 25 MWe producing electricity for 
sale, the unit shall become a TR NOX Ozone Season unit as 
provided in paragraph (a)(1) of this section on the first date on which 
it both combusts fossil fuel and serves such generator.
    (b) Any unit in a State (and Indian country within the borders of 
such State) that otherwise is a TR NOX Ozone Season unit 
under paragraph (a) of this section and that meets the requirements set 
forth in paragraph (b)(1)(i) or (2)(i) of this section shall not be a 
TR NOX Ozone Season unit:
    (1)(i) Any unit:
    (A) Qualifying as a cogeneration unit throughout the later of 2005 
or the 12-month period starting on the date the unit first produces 
electricity and continuing to qualify as a cogeneration unit throughout 
each calendar year ending after the later of 2005 or such 12-month 
period; and
    (B) Not supplying in 2005 or any calendar year thereafter 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.
    (ii) If, after qualifying under paragraph (b)(1)(i) of this section 
as not being a TR NOX Ozone Season unit, a unit subsequently 
no longer meets all the requirements of paragraph (b)(1)(i) of this 
section, the unit shall become a TR NOX Ozone Season unit 
starting on the earlier of January 1 after the first calendar year 
during which the unit first no longer qualifies as a cogeneration unit 
or January 1 after the first calendar year during which the unit no 
longer meets the requirements of paragraph (b)(1)(i)(B) of this 
section. The unit shall thereafter continue to be a TR NOX 
Ozone Season unit.
    (2)(i) Any unit:
    (A) Qualifying as a solid waste incineration unit throughout the 
later of 2005 or the 12-month period starting on the date the unit 
first produces electricity and continuing to qualify as a solid waste 
incineration unit throughout each calendar year ending after the later 
of 2005 or such 12-month period; and
    (B) With an average annual fuel consumption of fossil fuel for the 
first 3 consecutive calendar years of operation starting no earlier 
than 2005 of less than 20 percent (on a Btu basis) and an average 
annual fuel consumption of fossil fuel for any 3 consecutive calendar 
years thereafter of less than 20 percent (on a Btu basis).
    (ii) If, after qualifying under paragraph (b)(2)(i) of this section 
as not being a TR NOX Ozone Season unit, a unit subsequently 
no longer meets all the requirements of paragraph (b)(1)(i) of this 
section, the unit shall become a TR NOX Ozone Season unit 
starting on the earlier of January 1 after the first calendar year 
during which the unit first no longer qualifies as a solid waste 
incineration unit or January 1 after the first 3 consecutive calendar 
years after 2005 for which the unit has an average annual fuel 
consumption of fossil fuel of 20 percent or more. The unit shall 
thereafter continue to be a TR NOX Ozone Season unit.
    (c) A certifying official of an owner or operator of any unit or 
other equipment

[[Page 48412]]

may submit a petition (including any supporting documents) to the 
Administrator at any time for a determination concerning the 
applicability, under paragraphs (a) and (b) of this section or a SIP 
revision approved under Sec.  52.38(b)(4) or (5) of this chapter, of 
the TR NOX Ozone Season Trading Program to the unit or other 
equipment.
    (1) Petition content. The petition shall be in writing and include 
the identification of the unit or other equipment and the relevant 
facts about the unit or other equipment. The petition and any other 
documents provided to the Administrator in connection with the petition 
shall include the following certification statement, signed by the 
certifying official: ``I am authorized to make this submission on 
behalf of the owners and operators of the unit or other equipment 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) Response. The Administrator will issue a written response to 
the petition and may request supplemental information determined by the 
Administrator to be relevant to such petition. The Administrator's 
determination concerning the applicability, under paragraphs (a) and 
(b) of this section, of the TR NOX Ozone Season Trading 
Program to the unit or other equipment shall be binding on any State or 
permitting authority unless the Administrator determines that the 
petition or other documents or information provided in connection with 
the petition contained significant, relevant errors or omissions.

Sec.  97.505  Retired unit exemption.

    (a)(1) Any TR NOX Ozone Season unit that is permanently 
retired shall be exempt from Sec.  97.506(b) and (c)(1), Sec.  97.524, 
and Sec. Sec.  97.530 through 97.535.
    (2) The exemption under paragraph (a)(1) of this section shall 
become effective the day on which the TR NOX Ozone Season 
unit is permanently retired. Within 30 days of the unit's permanent 
retirement, the designated representative shall submit a statement to 
the Administrator. The statement shall state, in a format prescribed by 
the Administrator, that the unit was permanently retired on a specified 
date and will comply with the requirements of paragraph (b) of this 
section.
    (b) Special provisions. (1) A unit exempt under paragraph (a) of 
this section shall not emit any NOX, 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 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 
designated representative of a unit exempt under paragraph (a) of this 
section shall comply with the requirements of the TR 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.
    (4) A unit exempt under paragraph (a) of this section shall lose 
its exemption on the first date on which the unit resumes operation. 
Such unit shall be treated, for purposes of applying allocation, 
monitoring, reporting, and recordkeeping requirements under this 
subpart, as a unit that commences commercial operation on the first 
date on which the unit resumes operation.

Sec.  97.506  Standard requirements.

    (a) Designated representative requirements. The owners and 
operators shall comply with the requirement to have a designated 
representative, and may have an alternate designated representative, in 
accordance with Sec. Sec.  97.513 through 97.518.
    (b) Emissions monitoring, reporting, and recordkeeping 
requirements. (1) The owners and operators, and the designated 
representative, of each TR NOX Ozone Season source and each 
TR NOX Ozone Season unit at the source shall comply with the 
monitoring, reporting, and recordkeeping requirements of Sec. Sec.  
97.530 through 97.535.
    (2) The emissions data determined in accordance with Sec. Sec.  
97.530 through 97.535 shall be used to calculate allocations of TR 
NOX Ozone Season allowances under Sec. Sec.  97.511(a)(2) 
and (b) and 97.512 and to determine compliance with the TR 
NOX Ozone Season emissions limitation and assurance 
provisions under paragraph (c) of this section, provided that, for each 
monitoring location from which mass emissions are reported, the mass 
emissions amount used in calculating such allocations and determining 
such compliance shall be the mass emissions amount for the monitoring 
location determined in accordance with Sec. Sec.  97.530 through 97.535 
and rounded to the nearest ton, with any fraction of a ton less than 
0.50 being deemed to be zero.
    (c) NOX emissions requirements. (1) TR NOX 
Ozone Season emissions limitation. (i) As of the allowance transfer 
deadline for a control period in a given year, the owners and operators 
of each TR NOX Ozone Season source and each TR 
NOX Ozone Season unit at the source shall hold, in the 
source's compliance account, TR NOX Ozone Season allowances 
available for deduction for such control period under Sec.  97.524(a) 
in an amount not less than the tons of total NOX emissions 
for such control period from all TR NOX Ozone Season units 
at the source.
    (ii) If total NOX emissions during a control period in a 
given year from the TR NOX Ozone Season units at a TR 
NOX Ozone Season source are in excess of the TR 
NOX Ozone Season emissions limitation set forth in paragraph 
(c)(1)(i) of this section, then:
    (A) The owners and operators of the source and each TR 
NOX Ozone Season unit at the source shall hold the TR 
NOX Ozone Season allowances required for deduction under 
Sec.  97.524(d); and
    (B) The owners and operators of the source and each TR 
NOX Ozone Season unit at the source shall pay any fine, 
penalty, or assessment or comply with any other remedy imposed, for the 
same violations, under the Clean Air Act, and each ton of such excess 
emissions and each day of such control period shall constitute a 
separate violation of this subpart and the Clean Air Act.
    (2) TR NOX Ozone Season assurance provisions. (i) If 
total NOX emissions during a control period in a given year 
from all TR NOX Ozone Season units at TR NOX 
Ozone Season sources in a State (and Indian country within the borders 
of such State) exceed the State assurance level, then the owners and 
operators of such sources and units in each group of one or more 
sources and units having a common designated representative for such 
control period, where the common designated representative's share of 
such NOX emissions during such control period exceeds the 
common designated

[[Page 48413]]

representative's assurance level for the State and such control period, 
shall hold (in the assurance account established for the owners and 
operators of such group) TR NOX Ozone Season allowances 
available for deduction for such control period under Sec.  97.525(a) 
in an amount equal to two times the product (rounded to the nearest 
whole number), as determined by the Administrator in accordance with 
Sec.  97.525(b), of multiplying--
    (A) The quotient of the amount by which the common designated 
representative's share of such NOX emissions exceeds the 
common designated representative's assurance level divided by the sum 
of the amounts, determined for all common designated representatives 
for such sources and units in the State (and Indian country within the 
borders of such State) for such control period, by which each common 
designated representative's share of such NOX emissions 
exceeds the respective common designated representative's assurance 
level; and
    (B) The amount by which total NOX emissions from all TR 
NOX Ozone Season units at TR NOX Ozone Season 
sources in the State (and Indian country within the borders of such 
State) for such control period exceed the State assurance level.
    (ii) The owners and operators shall hold the TR NOX 
Ozone Season allowances required under paragraph (c)(2)(i) of this 
section, as of midnight of November 1 (if it is a business day), or 
midnight of the first business day thereafter (if November 1 is not a 
business day), immediately after such control period.
    (iii) Total NOX emissions from all TR NOX 
Ozone Season units at TR NOX Ozone Season sources in a State 
(and Indian country within the borders of such State) during a control 
period in a given year exceed the State assurance level if such total 
NOX emissions exceed the sum, for such control period, of 
the State NOX Ozone Season trading budget under Sec.  
97.510(a) and the State's variability limit under Sec.  97.510(b).
    (iv) It shall not be a violation of this subpart or of the Clean 
Air Act if total NOX emissions from all TR NOX 
Ozone Season units at TR NOX Ozone Season sources in a State 
(and Indian country within the borders of such State) during a control 
period exceed the State assurance level or if a common designated 
representative's share of total NOX emissions from the TR 
NOX Ozone Season units at TR NOX Ozone Season 
sources in a State (and Indian country within the borders of such 
State) during a control period exceeds the common designated 
representative's assurance level.
    (v) To the extent the owners and operators fail to hold TR 
NOX Ozone Season allowances for a control period in a given 
year in accordance with paragraphs (c)(2)(i) through (iii) of this 
section,
    (A) The owners and operators shall pay any fine, penalty, or 
assessment or comply with any other remedy imposed under the Clean Air 
Act; and
    (B) Each TR NOX Ozone Season allowance that the owners 
and operators fail to hold for such control period in accordance with 
paragraphs (c)(2)(i) through (iii) of this section and each day of such 
control period shall constitute a separate violation of this subpart 
and the Clean Air Act.
    (3) Compliance periods. A TR NOX Ozone Season unit shall 
be subject to the requirements under paragraphs (c)(1) and (c)(2) of 
this section for the control period starting on the later of May 1, 
2012 or the deadline for meeting the unit's monitor certification 
requirements under Sec.  97.530(b) and for each control period 
thereafter.
    (4) Vintage of allowances held for compliance. (i) A TR 
NOX Ozone Season allowance held for compliance with the 
requirements under paragraph (c)(1)(i) of this section for a control 
period in a given year must be a TR NOX Ozone Season 
allowance that was allocated for such control period or a control 
period in a prior year.
    (ii) A TR NOX Ozone Season allowance held for compliance 
with the requirements under paragraphs (c)(1)(ii)(A) and (2)(i) through 
(iii) of this section for a control period in a given year must be a TR 
NOX Ozone Season allowance that was allocated for a control 
period in a prior year or the control period in the given year or in 
the immediately following year.
    (5) Allowance Management System requirements. Each TR 
NOX Ozone Season allowance shall be held in, deducted from, 
or transferred into, out of, or between Allowance Management System 
accounts in accordance with this subpart.
    (6) Limited authorization. A TR NOX Ozone Season 
allowance is a limited authorization to emit one ton of NOX 
during the control period in one year. Such authorization is limited in 
its use and duration as follows:
    (i) Such authorization shall only be used in accordance with the TR 
NOX Ozone Season Trading Program; and
    (ii) Notwithstanding any other provision of this subpart, the 
Administrator has the authority to terminate or limit the use and 
duration of such authorization to the extent the Administrator 
determines is necessary or appropriate to implement any provision of 
the Clean Air Act.
    (7) Property right. A TR NOX Ozone Season allowance does 
not constitute a property right.
    (d) Title V permit requirements. (1) No title V permit revision 
shall be required for any allocation, holding, deduction, or transfer 
of TR NOX Ozone Season allowances in accordance with this 
subpart.
    (2) A description of whether a unit is required to monitor and 
report NOX emissions using a continuous emission monitoring 
system (under subpart H of part 75 of this chapter), an excepted 
monitoring system (under appendices D and E to part 75 of this 
chapter), a low mass emissions excepted monitoring methodology (under 
Sec.  75.19 of this chapter), or an alternative monitoring system 
(under subpart E of part 75 of this chapter) in accordance with 
Sec. Sec.  97.530 through 97.535 may be added to, or changed in, a 
title V permit using minor permit modification procedures in accordance 
with Sec. Sec.  70.7(e)(2) and 71.7(e)(1) of this chapter, provided 
that the requirements applicable to the described monitoring and 
reporting (as added or changed, respectively) are already incorporated 
in such permit. This paragraph explicitly provides that the addition 
of, or change to, a unit's description as described in the prior 
sentence is eligible for minor permit modification procedures in 
accordance with Sec. Sec.  70.7(e)(2)(i)(B) and 71.7(e)(1)(i)(B) of 
this chapter.
    (e) Additional recordkeeping and reporting requirements. (1) Unless 
otherwise provided, the owners and operators of each TR NOX 
Ozone Season source and each TR NOX Ozone Season unit at the 
source shall keep on site at the source each of the following documents 
(in hardcopy or electronic format) 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 Administrator.
    (i) The certificate of representation under Sec.  97.516 for the 
designated representative for the source and each TR 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 certificate of 
representation and documents are superseded because of the submission 
of a new certificate of representation under Sec.  97.516 changing the 
designated representative.

[[Page 48414]]

    (ii) All emissions monitoring information, in accordance with this 
subpart.
    (iii) Copies of all reports, compliance certifications, and other 
submissions and all records made or required under, or to demonstrate 
compliance with the requirements of, the TR NOX Ozone Season 
Trading Program.
    (2) The designated representative of a TR NOX Ozone 
Season source and each TR NOX Ozone Season unit at the 
source shall make all submissions required under the TR NOX 
Ozone Season Trading Program, except as provided in Sec.  97.518. This 
requirement does not change, create an exemption from, or otherwise 
affect the responsible official submission requirements under a title V 
operating permit program in parts 70 and 71 of this chapter.
    (f) Liability. (1) Any provision of the TR NOX Ozone 
Season Trading Program that applies to a TR NOX Ozone Season 
source or the designated representative of a TR NOX Ozone 
Season source shall also apply to the owners and operators of such 
source and of the TR NOX Ozone Season units at the source.
    (2) Any provision of the TR NOX Ozone Season Trading 
Program that applies to a TR NOX Ozone Season unit or the 
designated representative of a TR NOX Ozone Season unit 
shall also apply to the owners and operators of such unit.
    (g) Effect on other authorities. No provision of the TR 
NOX Ozone Season Trading Program or exemption under Sec.  
97.505 shall be construed as exempting or excluding the owners and 
operators, and the designated representative, of a TR NOX 
Ozone Season source or TR 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.  97.507  Computation of time.

    (a) Unless otherwise stated, any time period scheduled, under the 
TR 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 
TR 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 TR NOX Ozone Season Trading Program, is not a 
business day, the time period shall be extended to the next business 
day.

Sec.  97.508  Administrative appeal procedures.

    The administrative appeal procedures for decisions of the 
Administrator under the TR NOX Ozone Season Trading Program 
are set forth in part 78 of this chapter.

Sec.  97.509  [Reserved]

Sec.  97.510  State NOX Ozone Season trading budgets, new unit set-
asides, Indian country new unit set-aside, and variability limits.

    (a) The State NOX Ozone Season trading budgets, new unit 
set-asides, and Indian country new unit set-asides for allocations of 
TR NOX Ozone Season allowances for the control periods in 
2012 and thereafter are as follows:

----------------------------------------------------------------------------------------------------------------
                                                       NOX Ozone Season                       Indian country new
                                                        trading budget    New unit set-aside    unit set-aside
                        State                          (tons) * for 2012    (tons) for 2012     (tons) for 2012
                                                           and 2013            and 2013            and 2013
----------------------------------------------------------------------------------------------------------------
Alabama.............................................              31,746                 635  ..................
Arkansas............................................              15,037                 301  ..................
Florida.............................................              27,825                 529                  28
Georgia.............................................              27,944                 559  ..................
Illinois............................................              21,208               1,697  ..................
Indiana.............................................              46,876               1,406  ..................
Kentucky............................................              36,167               1,447  ..................
Louisiana...........................................              13,432                 390                  13
Maryland............................................               7,179                 144  ..................
Mississippi.........................................              10,160                 193                  10
New Jersey..........................................               3,382                  68  ..................
New York............................................               8,331                 242                   8
North Carolina......................................              22,168               1,308                  22
Ohio................................................              40,063                 801  ..................
Pennsylvania........................................              52,201               1,044  ..................
South Carolina......................................              13,909                 264                  14
Tennessee...........................................              14,908                 298  ..................
Texas...............................................              63,043               1,828                  63
Virginia............................................              14,452                 723  ..................
West Virginia.......................................              25,283               1,264  ..................
----------------------------------------------------------------------------------------------------------------

----------------------------------------------------------------------------------------------------------------
                                                       NOX Ozone Season                       Indian country new
                                                        trading budget    New unit set-aside    unit set-aside
                        State                          (tons) * for 2014    (tons) for 2014     (tons) for 2014
                                                        and thereafter      and thereafter      and thereafter
----------------------------------------------------------------------------------------------------------------
Alabama.............................................              31,499                 630  ..................
Arkansas............................................              15,037                 301  ..................
Florida.............................................              27,825                 529                  28
Georgia.............................................              18,279                 366  ..................
Illinois............................................              21,208               1,697  ..................
Indiana.............................................              46,175               1,385  ..................
Kentucky............................................              32,674               1,307  ..................
Louisiana...........................................              13,432                 390                  13
Maryland............................................               7,179                 144  ..................
Mississippi.........................................              10,160                 193                  10
New Jersey..........................................               3,382                  68  ..................

[[Page 48415]]

 
New York............................................               8,331                 242                   8
North Carolina......................................              18,455               1,089                  18
Ohio................................................              37,792                 756  ..................
Pennsylvania........................................              51,912               1,038  ..................
South Carolina......................................              13,909                 264                  14
Tennessee...........................................               8,016                 160  ..................
Texas...............................................              63,043               1,828                  63
Virginia............................................              14,452                 723  ..................
West Virginia.......................................              23,291               1,165  ..................
----------------------------------------------------------------------------------------------------------------
* Each trading budget includes the new unit set-aside and, where applicable, the Indian country new unit set-
  aside and does not include the variability limit.

    (b) The States' variability limits for the State NOX 
Ozone Season trading budgets for the control periods in 2012 and 
thereafter are as follows:

------------------------------------------------------------------------
                                                      Variability limits
              State               Variability limits     for 2014 and
                                   for 2012 and 2013      thereafter
------------------------------------------------------------------------
Alabama.........................               6,667               6,615
Arkansas........................               3,158               3,158
Florida.........................               5,843               5,843
Georgia.........................               5,868               3,839
Illinois........................               4,454               4,454
Indiana.........................               9,844               9,697
Kentucky........................               7,595               6,862
Louisiana.......................               2,821               2,821
Maryland........................               1,508               1,508
Mississippi.....................               2,134               2,134
New Jersey......................                 710                 710
New York........................               1,750               1,750
North Carolina..................               4,655               3,876
Ohio............................               8,413               7,936
Pennsylvania....................              10,962              10,902
South Carolina..................               2,921               2,921
Tennessee.......................               3,131               1,683
Texas...........................              13,239              13,239
Virginia........................               3,035               3,035
West Virginia...................               5,309               4,891
------------------------------------------------------------------------

Sec.  97.511  Timing requirements for TR NOX Ozone Season allowance 
allocations.

    (a) Existing units. (1) TR NOX Ozone Season allowances 
are allocated, for the control periods in 2012 and each year 
thereafter, as provided in a notice of data availability issued by the 
Administrator. Providing an allocation to a unit in such notice does 
not constitute a determination that the unit is a TR NOX 
Ozone Season unit, and not providing an allocation to a unit in such 
notice does not constitute a determination that the unit is not a TR 
NOX Ozone Season unit.
    (2) Notwithstanding paragraph (a)(1) of this section, if a unit 
provided an allocation in the notice of data availability issued under 
paragraph (a)(1) of this section does not operate, starting after 2011, 
during the control period in two consecutive years, such unit will not 
be allocated the TR NOX Ozone Season allowances provided in 
such notice for the unit for the control periods in the fifth year 
after the first such year and in each year after that fifth year. All 
TR NOX Ozone Season allowances that would otherwise have 
been allocated to such unit will be allocated to the new unit set-aside 
for the State where such unit is located and for the respective years 
involved. If such unit resumes operation, the Administrator will 
allocate TR NOX Ozone Season allowances to the unit in 
accordance with paragraph (b) of this section.
    (b) New units.--(1) New unit set-asides. (i) By June 1, 2012 and 
June 1 of each year thereafter, the Administrator will calculate the TR 
NOX Ozone Season allowance allocation to each TR 
NOX Ozone Season unit in a State, in accordance with Sec.  
97.512(a)(2) through (7) and (12), for the control period in the year 
of the applicable calculation deadline under this paragraph and will 
promulgate a notice of data availability of the results of the 
calculations.
    (ii) For each notice of data availability required in paragraph 
(b)(1)(i) of this section, the Administrator will provide an 
opportunity for submission of objections to the calculations referenced 
in such notice.
    (A) Objections shall be submitted by the deadline specified in each 
notice of data availability required in paragraph (b)(1)(i) of this 
section and shall be limited to addressing whether the calculations 
(including the identification of the TR NOX Ozone Season 
units) are in accordance with Sec.  97.512(a)(2) through (7) and (12) 
and Sec. Sec.  97.506(b)(2) and 97.530 through 97.535.
    (B) The Administrator will adjust the calculations to the extent 
necessary to ensure that they are in accordance with the provisions 
referenced in paragraph (b)(1)(ii)(A) of this section. By August 1 
immediately after the promulgation of each notice of data availability 
required in paragraph (b)(1)(i) of this section, the Administrator will 
promulgate a notice

[[Page 48416]]

of data availability of any adjustments that the Administrator 
determines to be necessary with regard to allocations under Sec.  
97.512(a)(2) through (7) and (12) and the reasons for accepting or 
rejecting any objections submitted in accordance with paragraph 
(b)(1)(ii)(A) of this section.
    (iii) If the new unit set-aside for such control period contains 
any TR NOX Ozone Season allowances that have not been 
allocated in the applicable notice of data availability required in 
paragraph (b)(1)(ii) of this section, the Administrator will 
promulgate, by September 15 immediately after such notice, a notice of 
data availability that identifies any TR NOX Ozone Season 
units that commenced commercial operation during the period starting 
May 1 of the year before the year of such control period and ending 
August 31 of year of such control period.
    (iv) For each notice of data availability required in paragraph 
(b)(1)(iii) of this section, the Administrator will provide an 
opportunity for submission of objections to the identification of TR 
NOX Ozone Season units in such notice.
    (A) Objections shall be submitted by the deadline specified in each 
notice of data availability required in paragraph (b)(1)(iii) of this 
section and shall be limited to addressing whether the identification 
of TR NOX Ozone Season units in such notice is in accordance 
with paragraph (b)(1)(iii) of this section.
    (B) The Administrator will adjust the identification of TR 
NOX Ozone Season units in the each notice of data 
availability required in paragraph (b)(1)(iii) of this section to the 
extent necessary to ensure that it is in accordance with paragraph 
(b)(1)(iii) of this section and will calculate the TR NOX 
Ozone Season allowance allocation to each TR NOX Ozone 
Season unit in accordance with Sec.  97.512(a)(9), (10), and (12) and 
Sec. Sec.  97.506(b)(2) and 97.530 through 97.535. By November 15 
immediately after the promulgation of each notice of data availability 
required in paragraph (b)(1)(iii) of this section, the Administrator 
will promulgate a notice of data availability of any adjustments of the 
identification of TR NOX Ozone Season units that the 
Administrator determines to be necessary, the reasons for accepting or 
rejecting any objections submitted in accordance with paragraph 
(b)(1)(iv)(A) of this section, and the results of such calculations.
    (v) To the extent any TR NOX Ozone Season allowances are 
added to the new unit set-aside after promulgation of each notice of 
data availability required in paragraph (b)(1)(iv) of this section, the 
Administrator will promulgate additional notices of data availability, 
as deemed appropriate, of the allocation of such TR NOX 
Ozone Season allowances in accordance with Sec.  97.512(a)(10).
    (2) Indian country new unit set-asides. (i) By June 1, 2012 and 
June 1 of each year thereafter, the Administrator will calculate the TR 
NOX Ozone Season allowance allocation to each TR 
NOX Ozone Season unit in Indian country within the borders 
of a State, in accordance with Sec.  97.512(b)(2) through (7) and (12), 
for the control period in the year of the applicable calculation 
deadline under this paragraph and will promulgate a notice of data 
availability of the results of the calculations.
    (ii) For each notice of data availability required in paragraph 
(b)(2)(i) of this section, the Administrator will provide an 
opportunity for submission of objections to the calculations referenced 
in such notice.
    (A) Objections shall be submitted by the deadline specified in each 
notice of data availability required in paragraph (b)(2)(i) of this 
section and shall be limited to addressing whether the calculations 
(including the identification of the TR NOX Ozone Season 
units) are in accordance with Sec.  97.512(b)(2) through (7) and (12) 
and Sec. Sec.  97.506(b)(2) and 97.530 through 97.535.
    (B) The Administrator will adjust the calculations to the extent 
necessary to ensure that they are in accordance with the provisions 
referenced in paragraph (b)(2)(ii)(A) of this section. By August 1 
immediately after the promulgation of each notice of data availability 
required in paragraph (b)(2)(i) of this section, the Administrator will 
promulgate a notice of data availability of any adjustments that the 
Administrator determines to be necessary with regard to allocations 
under Sec.  97.512(b)(2) through (7) and (12) and the reasons for 
accepting or rejecting any objections submitted in accordance with 
paragraph (b)(2)(ii)(A) of this section.
    (iii) If the Indian country new unit set-aside for such control 
period contains any TR NOX Ozone Season allowances that have 
not been allocated in the applicable notice of data availability 
required in paragraph (b)(2)(ii) of this section, the Administrator 
will promulgate, by September 15 immediately after such notice, a 
notice of data availability that identifies any TR NOX Ozone 
Season units that commenced commercial operation during the period 
starting May 1 of the year before the year of such control period and 
ending August 31 of year of such control period.
    (iv) For each notice of data availability required in paragraph 
(b)(2)(iii) of this section, the Administrator will provide an 
opportunity for submission of objections to the identification of TR 
NOX Ozone Season units in such notice.
    (A) Objections shall be submitted by the deadline specified in each 
notice of data availability required in paragraph (b)(2)(iii) of this 
section and shall be limited to addressing whether the identification 
of TR NOX Ozone Season units in such notice is in accordance 
with paragraph (b)(2)(iii) of this section.
    (B) The Administrator will adjust the identification of TR 
NOX Ozone Season units in the each notice of data 
availability required in paragraph (b)(2)(iii) of this section to the 
extent necessary to ensure that it is in accordance with paragraph 
(b)(2)(iii) of this section and will calculate the TR NOX 
Ozone Season allowance allocation to each TR NOX Ozone 
Season unit in accordance with Sec.  97.512(b)(9), (10), and (12) and 
Sec. Sec.  97.506(b)(2) and 97.530 through 97.535. By November 15 
immediately after the promulgation of each notice of data availability 
required in paragraph (b)(2)(iii) of this section, the Administrator 
will promulgate a notice of data availability of any adjustments of the 
identification of TR NOX Ozone Season units that the 
Administrator determines to be necessary, the reasons for accepting or 
rejecting any objections submitted in accordance with paragraph 
(b)(2)(iv)(A) of this section, and the results of such calculations. 
(v) To the extent any TR NOX Ozone Season allowances are 
added to the Indian country new unit set-aside after promulgation of 
each notice of data availability required in paragraph (b)(2)(iv) of 
this section, the Administrator will promulgate additional notices of 
data availability, as deemed appropriate, of the allocation of such TR 
NOX Ozone Season allowances in accordance with Sec.  
97.512(b)(10).
    (c) Units incorrectly allocated TR NOX Ozone Season allowances. (1) 
For each control period in 2012 and thereafter, if the Administrator 
determines that TR NOX Ozone Season allowances were 
allocated under paragraph (a) of this section, or under a provision of 
a SIP revision approved under Sec.  52.38(b)(3), (4), or (5) of this 
chapter, where such control period and the recipient are covered by the 
provisions of paragraph (c)(1)(i) of this section or were allocated 
under Sec.  97.512(a)(2) through (7), (9), and (12) and (b)(2) through 
(7), (9), and (12), or under a provision of a SIP revision approved 
under Sec.  52.38(b)(4) or (5) of this chapter, where such control 
period and the recipient are covered by the

[[Page 48417]]

provisions of paragraph (c)(1)(ii) of this section, then the 
Administrator will notify the designated representative of the 
recipient and will act in accordance with the procedures set forth in 
paragraphs (c)(2) through (5) of this section:
    (i)(A) The recipient is not actually a TR NOX Ozone 
Season unit under Sec.  97.504 as of May 1, 2012 and is allocated TR 
NOX Ozone Season allowances for such control period or, in 
the case of an allocation under a provision of a SIP revision approved 
under Sec.  52.38(b)(3), (4), or (5) of this chapter, the recipient is 
not actually a TR NOX Ozone Season unit as of May 1, 2012 
and is allocated TR NOX Ozone Season allowances for such 
control period that the SIP revision provides should be allocated only 
to recipients that are TR NOX Ozone Season units as of May 
1, 2012; or
    (B) The recipient is not located as of May 1 of the control period 
in the State from whose NOX Ozone Season trading budget the 
TR NOX Ozone Season allowances allocated under paragraph (a) 
of this section, or under a provision of a SIP revision approved under 
Sec.  52.38(b)(3), (4), or (5) of this chapter, were allocated for such 
control period.
    (ii) The recipient is not actually a TR NOX Ozone Season 
unit under Sec.  97.504 as of May 1 of such control period and is 
allocated TR NOX Ozone Season allowances for such control 
period or, in the case of an allocation under a provision of a SIP 
revision approved under Sec.  52.38(b)(3), (4), or (5) of this chapter, 
the recipient is not actually a TR NOX Ozone Season unit as 
of January 1 of such control period and is allocated TR NOX 
Ozone Season allowances for such control period that the SIP revision 
provides should be allocated only to recipients that are TR 
NOX Ozone Season units as of May 1 of such control period.
    (2) Except as provided in paragraph (c)(3) or (4) of this section, 
the Administrator will not record such TR NOX Ozone Season 
allowances under Sec.  97.521.
    (3) If the Administrator already recorded such TR NOX 
Ozone Season allowances under Sec.  97.521 and if the Administrator 
makes the determination under paragraph (c)(1) of this section before 
making deductions for the source that includes such recipient under 
Sec.  97.524(b) for such control period, then the Administrator will 
deduct from the account in which such TR NOX Ozone Season 
allowances were recorded an amount of TR NOX Ozone Season 
allowances allocated for the same or a prior control period equal to 
the amount of such already recorded TR NOX Ozone Season 
allowances. The authorized account representative shall ensure that 
there are sufficient TR NOX Ozone Season allowances in such 
account for completion of the deduction.
    (4) If the Administrator already recorded such TR NOX 
Ozone Season allowances under Sec.  97.521 and if the Administrator 
makes the determination under paragraph (c)(1) of this section after 
making deductions for the source that includes such recipient under 
Sec.  97.524(b) for such control period, then the Administrator will 
not make any deduction to take account of such already recorded TR 
NOX Ozone Season allowances.
    (5)(i) With regard to the TR NOX Ozone Season allowances 
that are not recorded, or that are deducted as an incorrect allocation, 
in accordance with paragraphs (c)(2) and (3) of this section for a 
recipient under paragraph (c)(1)(i) of this section, the Administrator 
will:
    (A) Transfer such TR NOX Ozone Season allowances to the 
new unit set-aside for such control period for the State from whose 
NOX Ozone Season trading budget the TR NOX Ozone 
Season allowances were allocated; or
    (B) If the State has a SIP revision approved under Sec.  
52.38(b)(4) or (5) covering such control period, include such TR 
NOX Annual allowances in the portion of the State 
NOX Ozone Season trading budget that may be allocated for 
such control period in accordance with such SIP revision.
    (ii) With regard to the TR NOX Ozone Season allowances 
that were not allocated from the Indian country new unit set-aside for 
such control period and that are not recorded, or that are deducted as 
an incorrect allocation, in accordance with paragraphs (c)(2) and (3) 
of this section for a recipient under paragraph (c)(1)(ii) of this 
paragraph, the Administrator will:
    (A) Transfer such TR NOX Ozone Season allowances to the 
new unit set-aside for such control period; or
    (B) If the State has a SIP revision approved under Sec.  
52.38(b)(4) or (5) covering such control period, include such TR 
NOX Ozone Season allowances in the portion of the State 
NOX Ozone Season trading budget that may be allocated for 
such control period in accordance with such SIP revision.
    (iii) With regard to the TR NOX Ozone Season allowances 
that were allocated from the Indian country new unit set-aside for such 
control period and that are not recorded, or that are deducted as an 
incorrect allocation, in accordance with paragraphs (c)(2) and (3) of 
this section for a recipient under paragraph (c)(1)(ii) of this 
paragraph, the Administrator will transfer such TR NOX Ozone 
Season allowances to the Indian country new unit set-aside for such 
control period.

Sec.  97.512  TR NOX Ozone Season allowance allocations to new units.

    (a) For each control period in 2012 and thereafter and for the TR 
NOX Ozone Season units in each State, the Administrator will 
allocate TR NOX Ozone Season allowances to the TR 
NOX Ozone Season units as follows:
    (1) The TR NOX Ozone Season allowances will be allocated 
to the following TR NOX Ozone Season units, except as 
provided in paragraph (a)(10) of this section:
    (i) TR NOX Ozone Season units that are not allocated an 
amount of TR NOX Ozone Season allowances in the notice of 
data availability issued under Sec.  97.511(a)(1);
    (ii) TR NOX Ozone Season units whose allocation of an 
amount of TR NOX Ozone Season allowances for such control 
period in the notice of data availability issued under Sec.  
97.511(a)(1) is covered by Sec.  97.511(c)(2) or (3);
    (iii) TR NOX Ozone Season units that are allocated an 
amount of TR NOX Ozone Season allowances for such control 
period in the notice of data availability issued under Sec.  
97.511(a)(1), which allocation is terminated for such control period 
pursuant to Sec.  97.511(a)(2), and that operate during the control 
period immediately preceding such control period; or
    (iv) For purposes of paragraph (a)(9) of this section, TR 
NOX Ozone Season units under Sec.  97.511(c)(1)(ii) whose 
allocation of an amount of TR NOX Ozone Season allowances 
for such control period in the notice of data availability issued under 
Sec.  97.511(b)(1)(ii)(B) is covered by Sec.  97.511(c)(2) or (3).
    (2) The Administrator will establish a separate new unit set-aside 
for the State for each such control period. Each such new unit set-
aside will be allocated TR NOX Ozone Season allowances in an 
amount equal to the applicable amount of tons of NOX 
emissions as set forth in Sec.  97.510(a) and will be allocated 
additional TR NOX Ozone Season allowances (if any) in 
accordance with Sec. Sec.  97.511(a)(2) and (c)(5) and paragraph 
(b)(10) of this section.
    (3) The Administrator will determine, for each TR NOX 
Ozone Season unit described in paragraph (a)(1) of this section, an 
allocation of TR NOX Ozone Season allowances for the later 
of the following control periods and for each subsequent control 
period:
    (i) The control period in 2012;
    (ii) The first control period after the control period in which the 
TR NOX

[[Page 48418]]

Ozone Season unit commences commercial operation;
    (iii) For a unit described in paragraph (a)(1)(ii) of this section, 
the first control period in which the TR NOX Ozone Season 
unit operates in the State after operating in another jurisdiction and 
for which the unit is not already allocated one or more TR 
NOX Ozone Season allowances; and
    (iv) For a unit described in paragraph (a)(1)(iii) of this section, 
the first control period after the control period in which the unit 
resumes operation.
    (4)(i) The allocation to each TR NOX Ozone Season unit 
described in paragraph (a)(1)(i) through (iii) of this section and for 
each control period described in paragraph (a)(3) of this section will 
be an amount equal to the unit's total tons of NOX emissions 
during the immediately preceding control period.
    (ii) The Administrator will adjust the allocation amount in 
paragraph (a)(4)(i) in accordance with paragraphs (a)(5) through (7) 
and (12) of this section.
    (5) The Administrator will calculate the sum of the TR 
NOX Ozone Season allowances determined for all such TR 
NOX Ozone Season units under paragraph (a)(4)(i) of this 
section in the State for such control period.
    (6) If the amount of TR NOX Ozone Season allowances in 
the new unit set-aside for the State for such control period is greater 
than or equal to the sum under paragraph (a)(5) of this section, then 
the Administrator will allocate the amount of TR NOX Ozone 
Season allowances determined for each such TR NOX Ozone 
Season unit under paragraph (a)(4)(i) of this section.
    (7) If the amount of TR NOX Ozone Season allowances in 
the new unit set-aside for the State for such control period is less 
than the sum under paragraph (a)(5) of this section, then the 
Administrator will allocate to each such TR NOX Ozone Season 
unit the amount of the TR NOX Ozone Season allowances 
determined under paragraph (a)(4)(i) of this section for the unit, 
multiplied by the amount of TR NOX Ozone Season allowances 
in the new unit set-aside for such control period, divided by the sum 
under paragraph (a)(5) of this section, and rounded to the nearest 
allowance.
    (8) The Administrator will notify the public, through the 
promulgation of the notices of data availability described in Sec.  
97.511(b)(1)(i) and (ii), of the amount of TR NOX Ozone 
Season allowances allocated under paragraphs (a)(2) through (7) and 
(12) of this section for such control period to each TR NOX 
Ozone Season unit eligible for such allocation.
    (9) If, after completion of the procedures under paragraphs (a)(5) 
through (8) of this section for such control period, any unallocated TR 
NOX Ozone Season allowances remain in the new unit set-aside 
for the State for such control period, the Administrator will allocate 
such TR NOX Ozone Season allowances as follows--
    (i) The Administrator will determine, for each unit described in 
paragraph (a)(1) of this section that commenced commercial operation 
during the period starting May 1 of the year before the year of such 
control period and ending August 31 of year of such control period, the 
positive difference (if any) between the unit's emissions during such 
control period and the amount of TR NOX Ozone Season 
allowances referenced in the notice of data availability required under 
Sec.  97.511(b)(1)(ii) for the unit for such control period;
    (ii) The Administrator will determine the sum of the positive 
differences determined under paragraph (a)(9)(i) of this section;
    (iii) If the amount of unallocated TR NOX Ozone Season 
allowances remaining in the new unit set-aside for the State for such 
control period is greater than or equal to the sum determined under 
paragraph (a)(9)(ii) of this section, then the Administrator will 
allocate the amount of TR NOX Ozone Season allowances 
determined for each such TR NOX Ozone Season unit under 
paragraph (a)(9)(i) of this section; and
    (iv) If the amount of unallocated TR NOX Ozone Season 
allowances remaining in the new unit set-aside for the State for such 
control period is less than the sum under paragraph (a)(9)(ii) of this 
section, then the Administrator will allocate to each such TR 
NOX Ozone Season unit the amount of the TR NOX 
Ozone Season allowances determined under paragraph (a)(9)(i) of this 
section for the unit, multiplied by the amount of unallocated TR 
NOX Ozone Season allowances remaining in the new unit set-
aside for such control period, divided by the sum under paragraph 
(a)(9)(ii) of this section, and rounded to the nearest allowance.
    (10) If, after completion of the procedures under paragraphs (a)(9) 
and (12) of this section for such control period, any unallocated TR 
NOX Ozone Season allowances remain in the new unit set-aside 
for the State for such control period, the Administrator will allocate 
to each TR NOX Ozone Season unit that is in the State, is 
allocated an amount of TR NOX Ozone Season allowances in the 
notice of data availability issued under Sec.  97.511(a)(1), and 
continues to be allocated TR NOX Ozone Season allowances for 
such control period in accordance with Sec.  97.511(a)(2), an amount of 
TR NOX Ozone Season allowances equal to the following: the 
total amount of such remaining unallocated TR NOX Ozone 
Season allowances in such new unit set-aside, multiplied by the unit's 
allocation under Sec.  97.511(a) for such control period, divided by 
the remainder of the amount of tons in the applicable State 
NOX Ozone Season trading budget minus the sum of the amounts 
of tons in such new unit set-aside and the Indian country new unit set-
aside for the State for such control period, and rounded to the nearest 
allowance.
    (11) The Administrator will notify the public, through the 
promulgation of the notices of data availability described in Sec.  
97.511(b)(1)(iii), (iv), and (v), of the amount of TR NOX 
Ozone Season allowances allocated under paragraphs (a)(9), (10), and 
(12) of this section for such control period to each TR NOX 
Ozone Season unit eligible for such allocation.
    (12)(i) Notwithstanding the requirements of paragraphs (a)(2) 
through (11) of this section, if the calculations of allocations of a 
new unit set-aside for a control period in a given year under paragraph 
(a)(7) of this section, paragraphs (a)(6) and (9)(iv) of this section, 
or paragraphs (a)(6), (9)(iii), and (10) of this section would 
otherwise result in total allocations of such new unit set-aside 
exceeding the total amount of such new unit set-aside, then the 
Administrator will adjust the results of the calculations under 
paragraph (a)(7), (9)(iv), or (10) of this section, as applicable, as 
follows. The Administrator will list the TR NOX Ozone Season 
units in descending order based on the amount of such units' 
allocations under paragraph (a)(7), (9)(iv), or (10) of this section, 
as applicable, and, in cases of equal allocation amounts, in 
alphabetical order of the relevant source's name and numerical order of 
the relevant unit's identification number, and will reduce each unit's 
allocation under paragraph (a)(7), (9)(iv), or (10) of this section, as 
applicable, by one TR NOX Ozone Season allowance (but not 
below zero) in the order in which the units are listed and will repeat 
this reduction process as necessary, until the total allocations of 
such new unit set-aside equal the total amount of such new unit set-
aside.
    (ii) Notwithstanding the requirements of paragraphs (a)(10) and 
(11) of this section, if the calculations of allocations of a new unit 
set-aside for a control period in a given year under paragraphs (a)(6), 
(9)(iii), and (10) of this section would otherwise result in a total

[[Page 48419]]

allocations of such new unit set-aside less than the total amount of 
such new unit set-aside, then the Administrator will adjust the results 
of the calculations under paragraph (a)(10) of this section, as 
follows. The Administrator will list the TR NOX Ozone Season 
units in descending order based on the amount of such units' 
allocations under paragraph (a)(10) of this section and, in cases of 
equal allocation amounts, in alphabetical order of the relevant 
source's name and numerical order of the relevant unit's identification 
number, and will increase each unit's allocation under paragraph 
(a)(10) of this section by one TR NOX Ozone Season allowance 
in the order in which the units are listed and will repeat this 
increase process as necessary, until the total allocations of such new 
unit set-aside equal the total amount of such new unit set-aside.
    (b) For each control period in 2012 and thereafter and for the TR 
NOX Ozone Season units located in Indian country within the 
borders of each State, the Administrator will allocate TR 
NOX Ozone Season allowances to the TR NOX Ozone 
Season units as follows:
    (1) The TR NOX Ozone Season allowances will be allocated 
to the following TR NOX Ozone Season units, except as 
provided in paragraph (b)(10) of this section:
    (i) TR NOX Ozone Season units that are not allocated an 
amount of TR NOX Ozone Season allowances in the notice of 
data availability issued under Sec.  97.511(a)(1); or
    (ii) For purposes of paragraph (b)(9) of this section, TR 
NOX Ozone Season units under Sec.  97.511(c)(1)(ii) whose 
allocation of an amount of TR NOX Ozone Season allowances 
for such control period in the notice of data availability issued under 
Sec.  97.511(b)(2)(ii)(B) is covered by Sec.  97.511(c)(2) or (3).
    (2) The Administrator will establish a separate Indian country new 
unit set-aside for the State for each such control period. Each such 
Indian country new unit set-aside will be allocated TR NOX 
Ozone Season allowances in an amount equal to the applicable amount of 
tons of NOX emissions as set forth in Sec.  97.510(a) and 
will be allocated additional TR NOX Ozone Season allowances 
(if any) in accordance with Sec.  97.511(c)(5).
    (3) The Administrator will determine, for each TR NOX 
Ozone Season unit described in paragraph (b)(1) of this section, an 
allocation of TR NOX Ozone Season allowances for the later 
of the following control periods and for each subsequent control 
period:
    (i) The control period in 2012; and
    (ii) The first control period after the control period in which the 
TR NOX Ozone Season unit commences commercial operation.
    (4)(i) The allocation to each TR NOX Ozone Season unit 
described in paragraph (b)(1)(i) of this section and for each control 
period described in paragraph (b)(3) of this section will be an amount 
equal to the unit's total tons of NOX emissions during the 
immediately preceding control period.
    (ii) The Administrator will adjust the allocation amount in 
paragraph (b)(4)(i) in accordance with paragraphs (b)(5) through (7) 
and (12) of this section.
    (5) The Administrator will calculate the sum of the TR 
NOX Ozone Season allowances determined for all such TR 
NOX Ozone Season units under paragraph (b)(4)(i) of this 
section in Indian country within the borders of the State for such 
control period.
    (6) If the amount of TR NOX Ozone Season allowances in 
the Indian country new unit set-aside for the State for such control 
period is greater than or equal to the sum under paragraph (b)(5) of 
this section, then the Administrator will allocate the amount of TR 
NOX Ozone Season allowances determined for each such TR 
NOX Ozone Season unit under paragraph (b)(4)(i) of this 
section.
    (7) If the amount of TR NOX Ozone Season allowances in 
the Indian country new unit set-aside for the State for such control 
period is less than the sum under paragraph (b)(5) of this section, 
then the Administrator will allocate to each such TR NOX 
Ozone Season unit the amount of the TR NOX Ozone Season 
allowances determined under paragraph (b)(4)(i) of this section for the 
unit, multiplied by the amount of TR NOX Ozone Season 
allowances in the Indian country new unit set-aside for such control 
period, divided by the sum under paragraph (b)(5) of this section, and 
rounded to the nearest allowance.
    (8) The Administrator will notify the public, through the 
promulgation of the notices of data availability described in Sec.  
97.511(b)(2)(i) and (ii), of the amount of TR NOX Ozone 
Season allowances allocated under paragraphs (b)(2) through (7) and 
(12) of this section for such control period to each TR NOX 
Ozone Season unit eligible for such allocation.
    (9) If, after completion of the procedures under paragraphs (b)(5) 
through (8) of this section for such control period, any unallocated TR 
NOX Ozone Season allowances remain in the Indian country new 
unit set-aside for the State for such control period, the Administrator 
will allocate such TR NOX Ozone Season allowances as 
follows--
    (i) The Administrator will determine, for each unit described in 
paragraph (b)(1) of this section that commenced commercial operation 
during the period starting May 1 of the year before the year of such 
control period and ending August 31 of year of such control period, the 
positive difference (if any) between the unit's emissions during such 
control period and the amount of TR NOX Ozone Season 
allowances referenced in the notice of data availability required under 
Sec.  97.511(b)(2)(ii) for the unit for such control period;
    (ii) The Administrator will determine the sum of the positive 
differences determined under paragraph (b)(9)(i) of this section;
    (iii) If the amount of unallocated TR NOX Ozone Season 
allowances remaining in the Indian country new unit set-aside for the 
State for such control period is greater than or equal to the sum 
determined under paragraph (b)(9)(ii) of this section, then the 
Administrator will allocate the amount of TR NOX Ozone 
Season allowances determined for each such TR NOX Ozone 
Season unit under paragraph (b)(9)(i) of this section; and
    (iv) If the amount of unallocated TR NOX Ozone Season 
allowances remaining in the Indian country new unit set-aside for the 
State for such control period is less than the sum under paragraph 
(b)(9)(ii) of this section, then the Administrator will allocate to 
each such TR NOX Ozone Season unit the amount of the TR 
NOX Ozone Season allowances determined under paragraph 
(b)(9)(i) of this section for the unit, multiplied by the amount of 
unallocated TR NOX Ozone Season allowances remaining in the 
Indian country new unit set-aside for such control period, divided by 
the sum under paragraph (b)(9)(ii) of this section, and rounded to the 
nearest allowance.
    (10) If, after completion of the procedures under paragraphs (b)(9) 
and (12) of this section for such control period, any unallocated TR 
NOX Ozone Season allowances remain in the Indian country new 
unit set-aside for the State for such control period, the Administrator 
will:
    (i) Transfer such unallocated TR NOX Ozone Season 
allowances to the new unit set-aside for the State for such control 
period; or
    (ii) If the State has a SIP revision approved under Sec.  
52.38(b)(4) or (5) covering such control period, include such 
unallocated TR NOX Ozone Season allowances in the portion of 
the State NOX Ozone Season trading budget that may be 
allocated for such control period in accordance with such SIP revision.

[[Page 48420]]

    (11) The Administrator will notify the public, through the 
promulgation of the notices of data availability described in Sec.  
97.511(b)(2)(iii), (iv), and (v), of the amount of TR NOX 
Ozone Season allowances allocated under paragraphs (b)(9), (10), and 
(12) of this section for such control period to each TR NOX 
Ozone Season unit eligible for such allocation.
    (12)(i) Notwithstanding the requirements of paragraphs (b)(2) 
through (11) of this section, if the calculations of allocations of an 
Indian country new unit set-aside for a control period in a given year 
under paragraph (b)(7) of this section, paragraphs (b)(6) and (9)(iv) 
of this section, or paragraphs (b)(6), (9)(iii), and (10) of this 
section would otherwise result in total allocations of such Indian 
country new unit set-aside exceeding the total amount of such Indian 
country new unit set-aside, then the Administrator will adjust the 
results of the calculations under paragraph (b)(7), (9)(iv), or (10) of 
this section, as applicable, as follows. The Administrator will list 
the TR NOX Ozone Season units in descending order based on 
the amount of such units' allocations under paragraph (b)(7), (9)(iv), 
or (10) of this section, as applicable, and, in cases of equal 
allocation amounts, in alphabetical order of the relevant source's name 
and numerical order of the relevant unit's identification number, and 
will reduce each unit's allocation under paragraph (b)(7), (9)(iv), or 
(10) of this section, as applicable, by one TR NOX Ozone 
Season allowance (but not below zero) in the order in which the units 
are listed and will repeat this reduction process as necessary, until 
the total allocations of such Indian country new unit set-aside equal 
the total amount of such Indian country new unit set-aside.
    (ii) Notwithstanding the requirements of paragraphs (b)(10) and 
(11) of this section, if the calculations of allocations of an Indian 
country new unit set-aside for a control period in a given year under 
paragraphs (b)(6), (9)(iii), and (10) of this section would otherwise 
result in a total allocations of such Indian country new unit set-aside 
less than the total amount of such Indian country new unit set-aside, 
then the Administrator will adjust the results of the calculations 
under paragraph (b)(10) of this section, as follows. The Administrator 
will list the TR NOX Ozone Season units in descending order 
based on the amount of such units' allocations under paragraph (b)(10) 
of this section and, in cases of equal allocation amounts, in 
alphabetical order of the relevant source's name and numerical order of 
the relevant unit's identification number, and will increase each 
unit's allocation under paragraph (b)(10) of this section by one TR 
NOX Ozone Season allowance in the order in which the units 
are listed and will repeat this increase process as necessary, until 
the total allocations of such Indian country new unit set-aside equal 
the total amount of such Indian country new unit set-aside.

Sec.  97.513  Authorization of designated representative and alternate 
designated representative.

    (a) Except as provided under Sec.  97.515, each TR NOX 
Ozone Season source, including all TR NOX Ozone Season units 
at the source, shall have one and only one designated representative, 
with regard to all matters under the TR NOX Ozone Season 
Trading Program.
    (1) The designated representative shall be selected by an agreement 
binding on the owners and operators of the source and all TR 
NOX Ozone Season units at the source and shall act in 
accordance with the certification statement in Sec.  97.516(a)(4)(iii).
    (2) Upon and after receipt by the Administrator of a complete 
certificate of representation under Sec.  97.516:
    (i) The designated representative shall be authorized and shall 
represent and, by his or her representations, actions, inactions, or 
submissions, legally bind each owner and operator of the source and 
each TR NOX Ozone Season unit at the source in all matters 
pertaining to the TR NOX Ozone Season Trading Program, 
notwithstanding any agreement between the designated representative and 
such owners and operators; and
    (ii) The owners and operators of the source and each TR 
NOX Ozone Season unit at the source shall be bound by any 
decision or order issued to the designated representative by the 
Administrator regarding the source or any such unit.
    (b) Except as provided under Sec.  97.515, each TR NOX 
Ozone Season source may have one and only one alternate designated 
representative, who may act on behalf of the designated representative. 
The agreement by which the alternate designated representative is 
selected shall include a procedure for authorizing the alternate 
designated representative to act in lieu of the designated 
representative.
    (1) The alternate designated representative shall be selected by an 
agreement binding on the owners and operators of the source and all TR 
NOX Ozone Season units at the source and shall act in 
accordance with the certification statement in Sec.  97.516(a)(4)(iii).
    (2) Upon and after receipt by the Administrator of a complete 
certificate of representation under Sec.  97.516,
    (i) The alternate designated representative shall be authorized;
    (ii) Any representation, action, inaction, or submission by the 
alternate designated representative shall be deemed to be a 
representation, action, inaction, or submission by the designated 
representative; and
    (iii) The owners and operators of the source and each TR 
NOX Ozone Season unit at the source shall be bound by any 
decision or order issued to the alternate designated representative by 
the Administrator regarding the source or any such unit.
    (c) Except in this section, Sec.  97.502, and Sec. Sec.  97.514 
through 97.518, whenever the term ``designated representative'' (as 
distinguished from the term ``common designated representative'') is 
used in this subpart, the term shall be construed to include the 
designated representative or any alternate designated representative.

Sec.  97.514  Responsibilities of designated representative and 
alternate designated representative.

    (a) Except as provided under Sec.  97.518 concerning delegation of 
authority to make submissions, each submission under the TR 
NOX Ozone Season Trading Program shall be made, signed, and 
certified by the designated representative or alternate designated 
representative for each TR NOX Ozone Season source and TR 
NOX Ozone Season unit for which the submission is made. Each 
such submission shall include the following certification statement by 
the designated representative or alternate 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.''
    (b) The Administrator will accept or act on a submission made for a 
TR NOX Ozone Season source or a TR NOX Ozone 
Season unit only if the

[[Page 48421]]

submission has been made, signed, and certified in accordance with 
paragraph (a) of this section and Sec.  97.518.

Sec.  97.515  Changing designated representative and alternate 
designated representative; changes in owners and operators; changes in 
units at the source.

    (a) Changing designated representative. The designated 
representative may be changed at any time upon receipt by the 
Administrator of a superseding complete certificate of representation 
under Sec.  97.516. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
designated representative before the time and date when the 
Administrator receives the superseding certificate of representation 
shall be binding on the new designated representative and the owners 
and operators of the TR NOX Ozone Season source and the TR 
NOX Ozone Season units at the source.
    (b) Changing alternate designated representative. The alternate 
designated representative may be changed at any time upon receipt by 
the Administrator of a superseding complete certificate of 
representation under Sec.  97.516. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
alternate designated representative before the time and date when the 
Administrator receives the superseding certificate of representation 
shall be binding on the new alternate designated representative, the 
designated representative, and the owners and operators of the TR 
NOX Ozone Season source and the TR NOX Ozone 
Season units at the source.
    (c) Changes in owners and operators. (1) In the event an owner or 
operator of a TR NOX Ozone Season source or a TR 
NOX Ozone Season unit at the source is not included in the 
list of owners and operators in the certificate of representation under 
Sec.  97.516, such 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 designated representative 
and any alternate designated representative of the source or unit, and 
the decisions and orders of the Administrator, as if the owner or 
operator were included in such list.
    (2) Within 30 days after any change in the owners and operators of 
a TR NOX Ozone Season source or a TR NOX Ozone 
Season unit at the source, including the addition or removal of an 
owner or operator, the designated representative or any alternate 
designated representative shall submit a revision to the certificate of 
representation under Sec.  97.516 amending the list of owners and 
operators to reflect the change.
    (d) Changes in units at the source. Within 30 days of any change in 
which units are located at a TR NOX Ozone Season source 
(including the addition or removal of a unit), the designated 
representative or any alternate designated representative shall submit 
a certificate of representation under Sec.  97.516 amending the list of 
units to reflect the change.
    (1) If the change is the addition of a unit that operated (other 
than for purposes of testing by the manufacturer before initial 
installation) before being located at the source, then the certificate 
of representation shall identify, in a format prescribed by the 
Administrator, the entity from whom the unit was purchased or otherwise 
obtained (including name, address, telephone number, and facsimile 
number (if any)), the date on which the unit was purchased or otherwise 
obtained, and the date on which the unit became located at the source.
    (2) If the change is the removal of a unit, then the certificate of 
representation shall identify, in a format prescribed by the 
Administrator, the entity to which the unit was sold or that otherwise 
obtained the unit (including name, address, telephone number, and 
facsimile number (if any)), the date on which the unit was sold or 
otherwise obtained, and the date on which the unit became no longer 
located at the source.

Sec.  97.516  Certificate of representation.

    (a) A complete certificate of representation for a designated 
representative or an alternate designated representative shall include 
the following elements in a format prescribed by the Administrator:
    (1) Identification of the TR NOX Ozone Season source, 
and each TR NOX Ozone Season unit at the source, for which 
the certificate of representation is submitted, including source name, 
source category and NAICS code (or, in the absence of a NAICS code, an 
equivalent code), State, plant code, county, latitude and longitude, 
unit identification number and type, identification number and 
nameplate capacity (in MWe, rounded to the nearest tenth) of each 
generator served by each such unit, actual or projected date of 
commencement of commercial operation, and a statement of whether such 
source is located in Indian Country. If a projected date of 
commencement of commercial operation is provided, the actual date of 
commencement of commercial operation shall be provided when such 
information becomes available.
    (2) The name, address, e-mail address (if any), telephone number, 
and facsimile transmission number (if any) of the designated 
representative and any alternate designated representative.
    (3) A list of the owners and operators of the TR NOX 
Ozone Season source and of each TR NOX Ozone Season unit at 
the source.
    (4) The following certification statements by the designated 
representative and any alternate designated representative--
    (i) ``I certify that I was selected as the designated 
representative or alternate designated representative, as applicable, 
by an agreement binding on the owners and operators of the source and 
each TR 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 TR NOX Ozone 
Season Trading Program on behalf of the owners and operators of the 
source and of each TR 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 and by any decision 
or order issued to me by the Administrator regarding the source or 
unit.''
    (iii) ``Where there are multiple holders of a legal or equitable 
title to, or a leasehold interest in, a TR NOX Ozone Season 
unit, or where a utility or industrial customer purchases power from a 
TR 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 `designated representative' or `alternate 
designated representative', as applicable, and of the agreement by 
which I was selected to each owner and operator of the source and of 
each TR NOX Ozone Season unit at the source; and TR 
NOX Ozone Season allowances and proceeds of transactions 
involving TR 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 TR NOX Ozone Season allowances by contract, 
TR NOX Ozone Season allowances and proceeds of transactions 
involving TR NOX Ozone Season allowances will be deemed to 
be held or distributed in accordance with the contract.''
    (5) The signature of the designated representative and any 
alternate designated representative and the dates signed.

[[Page 48422]]

    (b) Unless otherwise required by the Administrator, documents of 
agreement referred to in the certificate of representation shall not be 
submitted to the Administrator. The Administrator shall not be under 
any obligation to review or evaluate the sufficiency of such documents, 
if submitted.

Sec.  97.517  Objections concerning designated representative and 
alternate designated representative.

    (a) Once a complete certificate of representation under Sec.  
97.516 has been submitted and received, the Administrator will rely on 
the certificate of representation unless and until a superseding 
complete certificate of representation under Sec.  97.516 is received 
by the Administrator.
    (b) Except as provided in paragraph (a) of this section, no 
objection or other communication submitted to the Administrator 
concerning the authorization, or any representation, action, inaction, 
or submission, of a designated representative or alternate designated 
representative shall affect any representation, action, inaction, or 
submission of the designated representative or alternate designated 
representative or the finality of any decision or order by the 
Administrator under the TR NOX Ozone Season Trading Program.
    (c) The Administrator will not adjudicate any private legal dispute 
concerning the authorization or any representation, action, inaction, 
or submission of any designated representative or alternate designated 
representative, including private legal disputes concerning the 
proceeds of TR NOX Ozone Season allowance transfers.

Sec.  97.518  Delegation by designated representative and alternate 
designated representative.

    (a) A designated representative may delegate, to one or more 
natural persons, his or her authority to make an electronic submission 
to the Administrator provided for or required under this subpart.
    (b) An alternate designated representative may delegate, to one or 
more natural persons, his or her authority to make an electronic 
submission to the Administrator provided for or required under this 
subpart.
    (c) In order to delegate authority to a natural person to make an 
electronic submission to the Administrator in accordance with paragraph 
(a) or (b) of this section, the designated representative or alternate 
designated representative, as appropriate, must submit to the 
Administrator a notice of delegation, in a format prescribed by the 
Administrator, that includes the following elements:
    (1) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of such designated 
representative or alternate designated representative;
    (2) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of each such natural person 
(referred to in this section as an ``agent'');
    (3) For each such natural person, a list of the type or types of 
electronic submissions under paragraph (a) or (b) of this section for 
which authority is delegated to him or her; and
    (4) The following certification statements by such designated 
representative or alternate designated representative:
    (i) ``I agree that any electronic submission to the Administrator 
that is made by an agent identified in this notice of delegation and of 
a type listed for such agent in this notice of delegation and that is 
made when I am a designated representative or alternate designated 
representative, as appropriate, and before this notice of delegation is 
superseded by another notice of delegation under 40 CFR 97.518(d) shall 
be deemed to be an electronic submission by me.''
    (ii) ``Until this notice of delegation is superseded by another 
notice of delegation under 40 CFR 97.518(d), I agree to maintain an e-
mail account and to notify the Administrator immediately of any change 
in my e-mail address unless all delegation of authority by me under 40 
CFR 97.518 is terminated.''.
    (d) A notice of delegation submitted under paragraph (c) of this 
section shall be effective, with regard to the designated 
representative or alternate designated representative identified in 
such notice, upon receipt of such notice by the Administrator and until 
receipt by the Administrator of a superseding notice of delegation 
submitted by such designated representative or alternate designated 
representative, as appropriate. The superseding notice of delegation 
may replace any previously identified agent, add a new agent, or 
eliminate entirely any delegation of authority.
    (e) Any electronic submission covered by the certification in 
paragraph (c)(4)(i) of this section and made in accordance with a 
notice of delegation effective under paragraph (d) of this section 
shall be deemed to be an electronic submission by the designated 
representative or alternate designated representative submitting such 
notice of delegation.

Sec.  97.519  [Reserved]

Sec.  97.520  Establishment of compliance accounts, assurance accounts, 
and general accounts.

    (a) Compliance accounts. Upon receipt of a complete certificate of 
representation under Sec.  97.516, the Administrator will establish a 
compliance account for the TR NOX Ozone Season source for 
which the certificate of representation was submitted, unless the 
source already has a compliance account. The designated representative 
and any alternate designated representative of the source shall be the 
authorized account representative and the alternate authorized account 
representative respectively of the compliance account.
    (b) Assurance accounts. The Administrator will establish assurance 
accounts for certain owners and operators and States in accordance with 
Sec.  97.525(b)(3).
    (c) General accounts. (1) Application for general account. (i) Any 
person may apply to open a general account, for the purpose of holding 
and transferring TR NOX Ozone Season allowances, by 
submitting to the Administrator a complete application for a general 
account. Such application shall designate one and only one authorized 
account representative and may designate one and only one alternate 
authorized account representative who may act on behalf of the 
authorized account representative.
    (A) The authorized account representative and alternate authorized 
account representative shall be selected by an agreement binding on the 
persons who have an ownership interest with respect to TR 
NOX Ozone Season allowances held in the general account.
    (B) The agreement by which the alternate authorized account 
representative is selected shall include a procedure for authorizing 
the alternate authorized account representative to act in lieu of the 
authorized account representative.
    (ii) A complete application for a general account 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 authorized 
account representative and any alternate authorized account 
representative;
    (B) An identifying name for the general account;
    (C) A list of all persons subject to a binding agreement for the 
authorized account representative and any alternate authorized account 
representative to

[[Page 48423]]

represent their ownership interest with respect to the TR 
NOX Ozone Season allowances held in the general account;
    (D) The following certification statement by the authorized account 
representative and any alternate authorized account representative: ``I 
certify that I was selected as the authorized account representative or 
the alternate authorized account representative, as applicable, by an 
agreement that is binding on all persons who have an ownership interest 
with respect to TR 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 TR 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 decision or order issued to me by 
the Administrator regarding the general account.''
    (E) The signature of the authorized account representative and any 
alternate authorized account representative and the dates signed.
    (iii) Unless otherwise required by the Administrator, documents of 
agreement referred to in the application for a general account shall 
not be submitted to the Administrator. The Administrator shall not be 
under any obligation to review or evaluate the sufficiency of such 
documents, if submitted.
    (2) Authorization of authorized account representative and 
alternate authorized account representative. (i) Upon receipt by the 
Administrator of a complete application for a general account under 
paragraph (b)(1) of this section, the Administrator will establish a 
general account for the person or persons for whom the application is 
submitted, and upon and after such receipt by the Administrator:
    (A) The authorized account representative of the general account 
shall be authorized and shall represent and, by his or her 
representations, actions, inactions, or submissions, legally bind each 
person who has an ownership interest with respect to TR NOX 
Ozone Season allowances held in the general account in all matters 
pertaining to the TR NOX Ozone Season Trading Program, 
notwithstanding any agreement between the authorized account 
representative and such person.
    (B) Any alternate authorized account representative shall be 
authorized, and any representation, action, inaction, or submission by 
any alternate authorized account representative shall be deemed to be a 
representation, action, inaction, or submission by the authorized 
account representative.
    (C) Each person who has an ownership interest with respect to TR 
NOX Ozone Season allowances held in the general account 
shall be bound by any decision or order issued to the authorized 
account representative or alternate authorized account representative 
by the Administrator regarding the general account.
    (ii) Except as provided in paragraph (c)(5) of this section 
concerning delegation of authority to make submissions, each submission 
concerning the general account shall be made, signed, and certified by 
the authorized account representative or any alternate authorized 
account representative for the persons having an ownership interest 
with respect to TR NOX Ozone Season allowances held in the 
general account. Each such submission shall include the following 
certification statement by the authorized account representative or any 
alternate authorized account representative: ``I am authorized to make 
this submission on behalf of the persons having an ownership interest 
with respect to the TR 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) Except in this section, whenever the term ``authorized 
account representative'' is used in this subpart, the term shall be 
construed to include the authorized account representative or any 
alternate authorized account representative.
    (3) Changing authorized account representative and alternate 
authorized account representative; changes in persons with ownership 
interest. (i) The authorized account representative of 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 (c)(1) of this section. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
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 authorized account representative 
and the persons with an ownership interest with respect to the TR 
NOX Ozone Season allowances in the general account.
    (ii) The alternate authorized account representative of 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 (c)(1) of this section. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
alternate 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 authorized 
account representative, the authorized account representative, and the 
persons with an ownership interest with respect to the TR 
NOX Ozone Season allowances in the general account.
    (iii)(A) In the event a person having an ownership interest with 
respect to TR 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 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 authorized account 
representative and any alternate authorized account representative of 
the account, and the decisions and orders of the Administrator, as if 
the person were included in such list.
    (B) Within 30 days after any change in the persons having an 
ownership interest with respect to NOX Ozone Season 
allowances in the general account, including the addition or removal of 
a person, the authorized account representative or any alternate 
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 TR NOX Ozone 
Season allowances in the general account to include the change.
    (4) Objections concerning authorized account representative and 
alternate authorized account representative. (i) Once a complete 
application for a general account under paragraph (c)(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.

[[Page 48424]]

    (ii) Except as provided in paragraph (c)(4)(i) of this section, no 
objection or other communication submitted to the Administrator 
concerning the authorization, or any representation, action, inaction, 
or submission of the authorized account representative or any alternate 
authorized account representative of a general account shall affect any 
representation, action, inaction, or submission of the authorized 
account representative or any alternate authorized account 
representative or the finality of any decision or order by the 
Administrator under the TR 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 authorized account representative or any 
alternate authorized account representative of a general account, 
including private legal disputes concerning the proceeds of TR 
NOX Ozone Season allowance transfers.
    (5) Delegation by authorized account representative and alternate 
authorized account representative. (i) An authorized account 
representative of a general account may delegate, to one or more 
natural persons, his or her authority to make an electronic submission 
to the Administrator provided for or required under this subpart.
    (ii) An alternate authorized account representative of a general 
account may delegate, to one or more natural persons, his or her 
authority to make an electronic submission to the Administrator 
provided for or required under this subpart.
    (iii) In order to delegate authority to a natural person to make an 
electronic submission to the Administrator in accordance with paragraph 
(c)(5)(i) or (ii) of this section, the authorized account 
representative or alternate authorized account representative, as 
appropriate, must submit to the Administrator a notice of delegation, 
in a format prescribed by the Administrator, that includes the 
following elements:
    (A) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of such authorized account 
representative or alternate authorized account representative;
    (B) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of each such natural person 
(referred to in this section as an ``agent'');
    (C) For each such natural person, a list of the type or types of 
electronic submissions under paragraph (c)(5)(i) or (ii) of this 
section for which authority is delegated to him or her;
    (D) The following certification statement by such authorized 
account representative or alternate authorized account representative: 
``I agree that any electronic submission to the Administrator that is 
made by an agent identified in this notice of delegation and of a type 
listed for such agent in this notice of delegation and that is made 
when I am an authorized account representative or alternate authorized 
representative, as appropriate, and before this notice of delegation is 
superseded by another notice of delegation under 40 CFR 
97.520(c)(5)(iv) shall be deemed to be an electronic submission by 
me.''; and
    (E) The following certification statement by such authorized 
account representative or alternate authorized account representative: 
``Until this notice of delegation is superseded by another notice of 
delegation under 40 CFR 97.520(c)(5)(iv), I agree to maintain an e-mail 
account and to notify the Administrator immediately of any change in my 
e-mail address unless all delegation of authority by me under 40 CFR 
97.520(c)(5) is terminated.''.
    (iv) A notice of delegation submitted under paragraph (c)(5)(iii) 
of this section shall be effective, with regard to the authorized 
account representative or alternate authorized account representative 
identified in such notice, upon receipt of such notice by the 
Administrator and until receipt by the Administrator of a superseding 
notice of delegation submitted by such authorized account 
representative or alternate authorized account representative, as 
appropriate. The superseding notice of delegation may replace any 
previously identified agent, add a new agent, or eliminate entirely any 
delegation of authority.
    (v) Any electronic submission covered by the certification in 
paragraph (c)(5)(iii)(D) of this section and made in accordance with a 
notice of delegation effective under paragraph (c)(5)(iv) of this 
section shall be deemed to be an electronic submission by the 
designated representative or alternate designated representative 
submitting such notice of delegation.
    (6) Closing a general account. (i) The authorized account 
representative or alternate authorized account representative of a 
general account may submit to the Administrator a request to close the 
account. Such request shall include a correctly submitted TR 
NOX Ozone Season allowance transfer under Sec.  97.522 for 
any TR NOX Ozone Season allowances in the account to one or 
more other Allowance Management System accounts.
    (ii) If a general account has no TR NOX Ozone Season 
allowance transfers to or from the account for a 12-month period or 
longer and does not contain any TR NOX Ozone Season 
allowances, the Administrator may notify the authorized account 
representative for the account that the account will be closed after 30 
days after the notice is sent. The account will be closed after the 30-
day period unless, before the end of the 30-day period, the 
Administrator receives a correctly submitted TR NOX Ozone 
Season allowance transfer under Sec.  97.522 to the account or a 
statement submitted by the authorized account representative or 
alternate authorized account representative demonstrating to the 
satisfaction of the Administrator good cause as to why the account 
should not be closed.
    (d) Account identification. The Administrator will assign a unique 
identifying number to each account established under paragraph (a), 
(b), or (c) of this section.
    (e) Responsibilities of authorized account representative and 
alternate authorized account representative. After the establishment of 
a compliance account or general account, the Administrator will accept 
or act on a submission pertaining to the account, including, but not 
limited to, submissions concerning the deduction or transfer of TR 
NOX Ozone Season allowances in the account, only if the 
submission has been made, signed, and certified in accordance with 
Sec. Sec.  97.514(a) and 97.518 or paragraphs (c)(2)(ii) and (c)(5) of 
this section.

Sec.  97.521  Recordation of TR NOX Ozone Season allowance allocations 
and auction results.

    (a) By November 7, 2011, the Administrator will record in each TR 
NOX Ozone Season source's compliance account the TR 
NOX Ozone Season allowances allocated to the TR 
NOX Ozone Season units at the source in accordance with 
Sec.  97.511(a) for the control period in 2012.
    (b) By November 7, 2011, the Administrator will record in each TR 
NOX Ozone Season source's compliance account the TR 
NOX Ozone Season allowances allocated to the TR 
NOX Ozone Season units at the source in accordance with 
Sec.  97.511(a) for the control period in 2013, unless the State in 
which the source is located notifies the Administrator in writing by 
October 17, 2011 of the State's intent to submit to the Administrator a 
complete SIP revision by April 1, 2012 meeting the

[[Page 48425]]

requirements of Sec.  52.38(b)(3)(i) through (iv) of this chapter.
    (1) If, by April 1, 2012, the State does not submit to the 
Administrator such complete SIP revision, the Administrator will record 
by April 15, 2012 in each TR NOX Ozone Season source's 
compliance account the TR NOX Ozone Season allowances 
allocated to the TR NOX Ozone Season units at the source in 
accordance with Sec.  97.511(a) for the control period in 2013.
    (2) If the State submits to the Administrator by April 1, 2012, and 
the Administrator approves by October 1, 2012, such complete SIP 
revision, the Administrator will record by October 1, 2012 in each TR 
NOX Ozone Season source's compliance account the TR 
NOX Ozone Season allowances allocated to the TR 
NOX Ozone Season units at the source as provided in such 
approved, complete SIP revision for the control period in 2013.
    (3) If the State submits to the Administrator by April 1, 2012, and 
the Administrator does not approve by October 1, 2012, such complete 
SIP revision, the Administrator will record by October 1, 2012 in each 
TR NOX Ozone Season source's compliance account the TR 
NOX Ozone Season allowances allocated to the TR 
NOX Ozone Season units at the source in accordance with 
Sec.  97.511(a) for the control period in 2013.
    (c) By July 1, 2013, the Administrator will record in each TR 
NOX Ozone Season source's compliance account the TR 
NOX Ozone Season allowances allocated to the TR 
NOX Ozone Season units at the source, or in each appropriate 
Allowance Management System account the TR NOX Ozone Season 
allowances auctioned to TR NOX Ozone Season units, in 
accordance with Sec.  97.511(a), or with a SIP revision approved under 
Sec.  52.38(b)(4) or (5) of this chapter, for the control period in 
2014 and 2015.
    (d) By July 1, 2014, the Administrator will record in each TR 
NOX Ozone Season source's compliance account the TR 
NOX Ozone Season allowances allocated to the TR 
NOX Ozone Season units at the source, or in each appropriate 
Allowance Management System account the TR NOX Ozone Season 
allowances auctioned to TR NOX Ozone Season units, in 
accordance with Sec.  97.511(a), or with a SIP revision approved under 
Sec.  52.38(b)(4) or (5) of this chapter, for the control period in 
2016 and 2017.
    (e) By July 1, 2015, the Administrator will record in each TR 
NOX Ozone Season source's compliance account the TR 
NOX Ozone Season allowances allocated to the TR 
NOX Ozone Season units at the source, or in each appropriate 
Allowance Management System account the TR NOX Ozone Season 
allowances auctioned to TR NOX Ozone Season units, in 
accordance with Sec.  97.511(a), or with a SIP revision approved under 
Sec.  52.38(b)(4) or (5) of this chapter, for the control period in 
2018 and 2019.
    (f) By July 1, 2016 and July 1 of each year thereafter, the 
Administrator will record in each TR NOX Ozone Season 
source's compliance account the TR NOX Ozone Season 
allowances allocated to the TR NOX Ozone Season units at the 
source, or in each appropriate Allowance Management System account the 
TR NOX Ozone Season allowances auctioned to TR 
NOX Ozone Season units, in accordance with Sec.  97.511(a), 
or with a SIP revision approved under Sec.  52.38(b)(4) or (5) of this 
chapter, for the control period in the fourth year after the year of 
the applicable recordation deadline under this paragraph.
    (g) By August 1, 2012 and August 1 of each year thereafter, the 
Administrator will record in each TR NOX Ozone Season 
source's compliance account the TR NOX Ozone Season 
allowances allocated to the TR NOX Ozone Season units at the 
source, or in each appropriate Allowance Management System account the 
TR NOX Ozone Season allowances auctioned to TR 
NOX Ozone Season units, in accordance with Sec.  
97.512(a)(2) through (8) and (12), or with a SIP revision approved 
under Sec.  52.38(b)(4) or (5) of this chapter, for the control period 
in the year of the applicable recordation deadline under this 
paragraph.
    (h) By August 1, 2012 and August 1 of each year thereafter, the 
Administrator will record in each TR NOX Ozone Season 
source's compliance account the TR NOX Ozone Season 
allowances allocated to the TR NOX Ozone Season units at the 
source in accordance with Sec.  97.512(b)(2) through (8) and (12) for 
the control period in the year of the applicable recordation deadline 
under this paragraph.
    (i) By November 15, 2012 and November 15 of each year thereafter, 
the Administrator will record in each TR NOX Ozone Season 
source's compliance account the TR NOX Ozone Season 
allowances allocated to the TR NOX Ozone Season units at the 
source in accordance with Sec.  97.512(a)(9) through (12), for the 
control period in the year of the applicable recordation deadline under 
this paragraph.
    (j) By the date on which any allocation or auction results, other 
than an allocation or auction results described in paragraphs (a) 
through (i) of this section, of TR NOX Ozone Season 
allowances to a recipient is made by or are submitted to the 
Administrator in accordance with Sec.  97.511 or Sec.  97.512 or with a 
SIP revision approved under Sec.  52.38(b)(4) or (5) of this chapter, 
the Administrator will record such allocation or auction results in the 
appropriate Allowance Management System account.
    (k) When recording the allocation or auction of TR NOX 
Ozone Season allowances to a TR NOX Ozone Season unit or 
other entity in an Allowance Management System account, the 
Administrator will assign each TR NOX Ozone Season allowance 
a unique identification number that will include digits identifying the 
year of the control period for which the TR NOX Ozone Season 
allowance is allocated or auctioned.

Sec.  97.522  Submission of TR NOX Ozone Season allowance transfers.

    (a) An authorized account representative seeking recordation of a 
TR NOX Ozone Season allowance transfer shall submit the 
transfer to the Administrator.
    (b) A TR NOX Ozone Season allowance transfer shall be 
correctly submitted if:
    (1) The transfer includes the following elements, in a format 
prescribed by the Administrator:
    (i) The account numbers established by the Administrator for both 
the transferor and transferee accounts;
    (ii) The serial number of each TR NOX Ozone Season 
allowance that is in the transferor account and is to be transferred; 
and
    (iii) The name and signature of the authorized account 
representative of the transferor account and the date signed; and
    (2) When the Administrator attempts to record the transfer, the 
transferor account includes each TR NOX Ozone Season 
allowance identified by serial number in the transfer.

Sec.  97.523  Recordation of TR NOX Ozone Season allowance transfers.

    (a) Within 5 business days (except as provided in paragraph (b) of 
this section) of receiving a TR NOX Ozone Season allowance 
transfer that is correctly submitted under Sec.  97.522, the 
Administrator will record a TR NOX Ozone Season allowance 
transfer by moving each TR NOX Ozone Season allowance from 
the transferor account to the transferee account as specified in the 
transfer.
    (b) A TR NOX Ozone Season allowance transfer to or from 
a

[[Page 48426]]

compliance account that is submitted for recordation after the 
allowance transfer deadline for a control period and that includes any 
TR 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 from such 
compliance account under Sec.  97.524 for the control period 
immediately before such allowance transfer deadline.
    (c) Where a TR NOX Ozone Season allowance transfer is 
not correctly submitted under Sec.  97.522, the Administrator will not 
record such transfer.
    (d) Within 5 business days of recordation of a TR NOX 
Ozone Season allowance transfer under paragraphs (a) and (b) of the 
section, the Administrator will notify the authorized account 
representatives of both the transferor and transferee accounts.
    (e) Within 10 business days of receipt of a TR NOX Ozone 
Season allowance transfer that is not correctly submitted under Sec.  
97.522, the Administrator will notify the 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.

Sec.  97.524  Compliance with TR NOX Ozone Season emissions limitation.

    (a) Availability for deduction for compliance. TR NOX 
Ozone Season allowances are available to be deducted for compliance 
with a source's TR NOX Ozone Season emissions limitation for 
a control period in a given year only if the TR NOX Ozone 
Season allowances:
    (1) Were allocated for such control period or a control period in a 
prior year; and
    (2) Are held in the source's compliance account as of the allowance 
transfer deadline for such control period.
    (b) Deductions for compliance. After the recordation, in accordance 
with Sec.  97.523, of TR NOX Ozone Season allowance 
transfers submitted by the allowance transfer deadline for a control 
period in a given year, the Administrator will deduct from each 
source's compliance account TR NOX Ozone Season allowances 
available under paragraph (a) of this section in order to determine 
whether the source meets the TR NOX Ozone Season emissions 
limitation for such control period, as follows:
    (1) Until the amount of TR NOX Ozone Season allowances 
deducted equals the number of tons of total NOX emissions 
from all TR NOX Ozone Season units at the source for such 
control period; or
    (2) If there are insufficient TR NOX Ozone Season 
allowances to complete the deductions in paragraph (b)(1) of this 
section, until no more TR NOX Ozone Season allowances 
available under paragraph (a) of this section remain in the compliance 
account.
    (c)(1) Identification of TR NOX Ozone Season allowances by serial 
number. The authorized account representative for a source's compliance 
account may request that specific TR NOX Ozone Season 
allowances, identified by serial number, in the compliance account be 
deducted for emissions or excess emissions for a control period in a 
given year in accordance with paragraph (b) or (d) of this section. In 
order to be complete, such request shall be submitted to the 
Administrator by the allowance transfer deadline for such control 
period and include, in a format prescribed by the Administrator, the 
identification of the TR NOX Ozone Season source and the 
appropriate serial numbers.
    (2) First-in, first-out. The Administrator will deduct TR 
NOX Ozone Season allowances under paragraph (b) or (d) of 
this section from the source's compliance account in accordance with a 
complete request under paragraph (c)(1) of this section or, in the 
absence of such request or in the case of identification of an 
insufficient amount of TR NOX Ozone Season allowances in 
such request, on a first-in, first-out accounting basis in the 
following order:
    (i) Any TR NOX Ozone Season allowances that were 
allocated to the units at the source and not transferred out of the 
compliance account, in the order of recordation; and then
    (ii) Any TR NOX Ozone Season allowances that were 
allocated to any unit and transferred to and recorded in the compliance 
account pursuant to this subpart, in the order of recordation.
    (d) Deductions for excess emissions. After making the deductions 
for compliance under paragraph (b) of this section for a control period 
in a year in which the TR NOX Ozone Season source has excess 
emissions, the Administrator will deduct from the source's compliance 
account an amount of TR NOX Ozone Season allowances, 
allocated for a control period in a prior year or the control period in 
the year of the excess emissions or in the immediately following year, 
equal to two times the number of tons of the source's excess emissions.
    (e) Recordation of deductions. The Administrator will record in the 
appropriate compliance account all deductions from such an account 
under paragraphs (b) and (d) of this section.

Sec.  97.525  Compliance with TR NOX Ozone Season assurance provisions.

    (a) Availability for deduction. TR NOX Ozone Season 
allowances are available to be deducted for compliance with the TR 
NOX Ozone Season assurance provisions for a control period 
in a given year by the owners and operators of a group of one or more 
TR NOX Ozone Season sources and units in a State (and Indian 
country within the borders of such State) only if the TR NOX 
Ozone Season allowances:
    (1) Were allocated for a control period in a prior year or the 
control period in the given year or in the immediately following year; 
and
    (2) Are held in the assurance account, established by the 
Administrator for such owners and operators of such group of TR 
NOX Ozone Season sources and units in such State (and Indian 
country within the borders of such State) under paragraph (b)(3) of 
this section, as of the deadline established in paragraph (b)(4) of 
this section.
    (b) Deductions for compliance. The Administrator will deduct TR 
NOX Ozone Season allowances available under paragraph (a) of 
this section for compliance with the TR NOX Ozone Season 
assurance provisions for a State for a control period in a given year 
in accordance with the following procedures:
    (1) By June 1, 2013 and June 1 of each year thereafter, the 
Administrator will:
    (i) Calculate, for each State (and Indian country within the 
borders of such State), the total NOX emissions from all TR 
NOX Ozone Season units at TR NOX Ozone Season 
sources in the State (and Indian country within the borders of such 
State) during the control period in the year before the year of this 
calculation deadline and the amount, if any, by which such total 
NOX emissions exceed the State assurance level as described 
in Sec.  97.506(c)(2)(iii); and
    (ii) Promulgate a notice of data availability of the results of the 
calculations required in paragraph (b)(1)(i) of this section, including 
separate calculations of the NOX emissions from each TR 
NOX Ozone Season source.
    (2) For each notice of data availability required in paragraph 
(b)(1)(ii) of this section and for any State (and Indian country within 
the borders of such State) identified in such notice as having TR 
NOX Ozone Season units with total NOX emissions 
exceeding the State assurance level for a control

[[Page 48427]]

period in a given year, as described in Sec.  97.506(c)(2)(iii):
    (i) By July 1 immediately after the promulgation of such notice, 
the designated representative of each TR NOX Ozone Season 
source in each such State (and Indian country within the borders of 
such State) shall submit a statement, in a format prescribed by the 
Administrator, providing for each TR NOX Ozone Season unit 
(if any) at the source that operates during, but is not allocated an 
amount of TR NOX Ozone Season allowances for, such control 
period, the unit's allowable NOX emission rate for such 
control period and, if such rate is expressed in lb per mmBtu, the 
unit's heat rate.
    (ii) By August 1 immediately after the promulgation of such notice, 
the Administrator will calculate, for each such State (and Indian 
country within the borders of such State) and such control period and 
each common designated representative for such control period for a 
group of one or more TR NOX Ozone Season sources and units 
in the State (and Indian country within the borders of such State), the 
common designated representative's share of the total NOX 
emissions from all TR NOX Ozone Season units at TR 
NOX Ozone Season sources in the State (and Indian country 
within the borders of such State), the common designated 
representative's assurance level, and the amount (if any) of TR 
NOX Ozone Season allowances that the owners and operators of 
such group of sources and units must hold in accordance with the 
calculation formula in Sec.  97.506(c)(2)(i) and will promulgate a 
notice of data availability of the results of these calculations.
    (iii) The Administrator will provide an opportunity for submission 
of objections to the calculations referenced by the notice of data 
availability required in paragraph (b)(2)(ii) of this section and the 
calculations referenced by the relevant notice of data availability 
required in paragraph (b)(1)(i) of this section.
    (A) Objections shall be submitted by the deadline specified in such 
notice and shall be limited to addressing whether the calculations 
referenced in the relevant notice required under paragraph (b)(1)(ii) 
of this section and referenced in the notice required under paragraph 
(b)(2)(ii) of this section are in accordance with Sec.  
97.506(c)(2)(iii), Sec. Sec.  97.506(b) and 97.530 through 97.535, the 
definitions of ``common designated representative'', ``common 
designated representative's assurance level'', and ``common designated 
representative's share'' in Sec.  97.502, and the calculation formula 
in Sec.  97.506(c)(2)(i).
    (B) The Administrator will adjust the calculations to the extent 
necessary to ensure that they are in accordance with the provisions 
referenced in paragraph (b)(2)(iii)(A) of this section. By October 1 
immediately after the promulgation of such notice, the Administrator 
will promulgate a notice of data availability of any adjustments that 
the Administrator determines to be necessary and the reasons for 
accepting or rejecting any objections submitted in accordance with 
paragraph (b)(2)(iii)(A) of this section.
    (3) For any State (and Indian country within the borders of such 
State) referenced in each notice of data availability required in 
paragraph (b)(2)(iii)(B) of this section as having TR NOX 
Ozone Season units with total NOX emissions exceeding the 
State assurance level for a control period in a given year, the 
Administrator will establish one assurance account for each set of 
owners and operators referenced, in the notice of data availability 
required under paragraph (b)(2)(iii)(B) of this section, as all of the 
owners and operators of a group of TR NOX Ozone Season 
sources and units in the State (and Indian country within the borders 
of such State) having a common designated representative for such 
control period and as being required to hold TR NOX Ozone 
Season allowances.
    (4)(i) As of midnight of November 1 immediately after the 
promulgation of each notice of data availability required in paragraph 
(b)(2)(iii)(B) of this section, the owners and operators described in 
paragraph (b)(3) of this section shall hold in the assurance account 
established for the them and for the appropriate TR NOX 
Ozone Season sources, TR NOX Ozone Season units, and State 
(and Indian country within the borders of such State) under paragraph 
(b)(3) of this section a total amount of TR NOX Ozone Season 
allowances, available for deduction under paragraph (a) of this 
section, equal to the amount such owners and operators are required to 
hold with regard to such sources, units and State (and Indian country 
within the borders of such State) as calculated by the Administrator 
and referenced in such notice.
    (ii) Notwithstanding the allowance-holding deadline specified in 
paragraph (b)(4)(i) of this section, if November 1 is not a business 
day, then such allowance-holding deadline shall be midnight of the 
first business day thereafter.
    (5) After November 1 (or the date described in paragraph (b)(4)(ii) 
of this section) immediately after the promulgation of each notice of 
data availability required in paragraph (b)(2)(iii)(B) of this section 
and after the recordation, in accordance with Sec.  97.523, of TR 
NOX Ozone Season allowance transfers submitted by midnight 
of such date, the Administrator will determine whether the owners and 
operators described in paragraph (b)(3) of this section hold, in the 
assurance account for the appropriate TR NOX Ozone Season 
sources, TR NOX Ozone Season units, and State (and Indian 
country within the borders of such State) established under paragraph 
(b)(3) of this section, the amount of TR NOX Ozone Season 
allowances available under paragraph (a) of this section that the 
owners and operators are required to hold with regard to such sources, 
units, and State (and Indian country within the borders of such State) 
as calculated by the Administrator and referenced in the notice 
required in paragraph (b)(2)(iii)(B) of this section.
    (6) Notwithstanding any other provision of this subpart and any 
revision, made by or submitted to the Administrator after the 
promulgation of the notice of data availability required in paragraph 
(b)(2)(iii)(B) of this section for a control period in a given year, of 
any data used in making the calculations referenced in such notice, the 
amounts of TR NOX Ozone Season allowances that the owners 
and operators are required to hold in accordance with Sec.  
97.506(c)(2)(i) for such control period shall continue to be such 
amounts as calculated by the Administrator and referenced in such 
notice required in paragraph (b)(2)(iii)(B) of this section, except as 
follows:
    (i) If any such data are revised by the Administrator as a result 
of a decision in or settlement of litigation concerning such data on 
appeal under part 78 of this chapter of such notice, or on appeal under 
section 307 of the Clean Air Act of a decision rendered under part 78 
of this chapter on appeal of such notice, then the Administrator will 
use the data as so revised to recalculate the amounts of TR 
NOX Ozone Season allowances that owners and operators are 
required to hold in accordance with the calculation formula in Sec.  
97.506(c)(2)(i) for such control period with regard to the TR 
NOX Ozone Season sources, TR NOX Ozone Season 
units, and State (and Indian country within the borders of such State) 
involved, provided that such litigation under part 78 of this chapter, 
or the proceeding under part 78 of this chapter that resulted in the 
decision appealed in such litigation under section 307 of the Clean Air 
Act, was initiated no later than 30 days after

[[Page 48428]]

promulgation of such notice required in paragraph (b)(2)(iii)(B) of 
this section.
    (ii) If any such data are revised by the owners and operators of a 
TR NOX Ozone Season source and TR NOX Ozone 
Season unit whose designated representative submitted such data under 
paragraph (b)(2)(i) of this section, as a result of a decision in or 
settlement of litigation concerning such submission, then the 
Administrator will use the data as so revised to recalculate the 
amounts of TR NOX Ozone Season allowances that owners and 
operators are required to hold in accordance with the calculation 
formula in Sec.  97.506(c)(2)(i) for such control period with regard to 
the TR NOX Ozone Season sources, TR NOX Ozone 
Season units, and State (and Indian country within the borders of such 
State) involved, provided that such litigation was initiated no later 
than 30 days after promulgation of such notice required in paragraph 
(b)(2)(iii)(B) of this section.
    (iii) If the revised data are used to recalculate, in accordance 
with paragraphs (b)(6)(i) and (ii) of this section, the amount of TR 
NOX Ozone Season allowances that the owners and operators 
are required to hold for such control period with regard to the TR 
NOX Ozone Season sources, TR NOX Ozone Season 
units, and State (and Indian country within the borders of such State) 
involved--
    (A) Where the amount of TR NOX Ozone Season allowances 
that the owners and operators are required to hold increases as a 
result of the use of all such revised data, the Administrator will 
establish a new, reasonable deadline on which the owners and operators 
shall hold the additional amount of TR NOX Ozone Season 
allowances in the assurance account established by the Administrator 
for the appropriate TR NOX Ozone Season sources, TR 
NOX Ozone Season units, and State (and Indian country within 
the borders of such State) under paragraph (b)(3) of this section. The 
owners' and operators' failure to hold such additional amount, as 
required, before the new deadline shall not be a violation of the Clean 
Air Act. The owners' and operators' failure to hold such additional 
amount, as required, as of the new deadline shall be a violation of the 
Clean Air Act. Each TR NOX Ozone Season allowance that the 
owners and operators fail to hold as required as of the new deadline, 
and each day in such control period, shall be a separate violation of 
the Clean Air Act.
    (B) For the owners and operators for which the amount of TR 
NOX Ozone Season allowances required to be held decreases as 
a result of the use of all such revised data, the Administrator will 
record, in all accounts from which TR NOX Ozone Season 
allowances were transferred by such owners and operators for such 
control period to the assurance account established by the 
Administrator for the appropriate at TR NOX Ozone Season 
sources, TR NOX Ozone Season units, and State (and Indian 
country within the borders of such State) under paragraph (b)(3) of 
this section, a total amount of the TR NOX Ozone Season 
allowances held in such assurance account equal to the amount of the 
decrease. If TR NOX Ozone Season allowances were transferred 
to such assurance account from more than one account, the amount of TR 
NOX Ozone Season allowances recorded in each such transferor 
account will be in proportion to the percentage of the total amount of 
TR NOX Ozone Season allowances transferred to such assurance 
account for such control period from such transferor account.
    (C) Each TR NOX Ozone Season allowance held under 
paragraph (b)(6)(iii)(A) of this section as a result of recalculation 
of requirements under the TR NOX Ozone Season assurance 
provisions for such control period must be a TR NOX Ozone 
Season allowance allocated for a control period in a year before or the 
year immediately following, or in the same year as, the year of such 
control period.

Sec.  97.526  Banking.

    (a) A TR NOX Ozone Season allowance 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 TR NOX Ozone Season allowance that is held in a 
compliance account or a general account will remain in such account 
unless and until the TR NOX Ozone Season allowance is 
deducted or transferred under Sec.  97.511(c), Sec.  97.523, Sec.  
97.524, Sec.  97.525, Sec.  97.527, or Sec.  97.528.

Sec.  97.527  Account error.

    The Administrator may, at his or her sole discretion and on his or 
her own motion, correct any error in any Allowance Management System 
account. Within 10 business days of making such correction, the 
Administrator will notify the authorized account representative for the 
account.

Sec.  97.528  Administrator's action on submissions.

    (a) The Administrator may review and conduct independent audits 
concerning any submission under the TR NOX Ozone Season 
Trading Program and make appropriate adjustments of the information in 
the submission.
    (b) The Administrator may deduct TR NOX Ozone Season 
allowances from or transfer TR NOX Ozone Season allowances 
to a compliance account or an assurance account, based on the 
information in a submission, as adjusted under paragraph (a)(1) of this 
section, and record such deductions and transfers.

Sec.  97.529  [Reserved]

Sec.  97.530  General monitoring, recordkeeping, and reporting 
requirements.

    The owners and operators, and to the extent applicable, the 
designated representative, of a TR NOX Ozone Season unit, 
shall comply with the monitoring, recordkeeping, and reporting 
requirements as provided in this subpart and subpart H of part 75 of 
this chapter. For purposes of applying such requirements, the 
definitions in Sec.  97.502 and in Sec.  72.2 of this chapter shall 
apply, 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 ``TR NOX 
Ozone Season unit,'' ``designated representative,'' and ``continuous 
emission monitoring system'' (or ``CEMS'') respectively as defined in 
Sec.  97.502, and the term ``newly affected unit'' shall be deemed to 
mean ``newly affected TR NOX Ozone Season unit''. The owner 
or operator of a unit that is not a TR 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 TR NOX Ozone Season unit.
    (a) Requirements for installation, certification, and data 
accounting. The owner or operator of each TR 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.  97.531 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.

[[Page 48429]]

    (b) Compliance deadlines. Except as provided in paragraph (e) of 
this section, 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 and 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 TR NOX Ozone Season 
unit that commences commercial operation before July 1, 2011, May 1, 
2012.
    (2) For the owner or operator of a TR NOX Ozone Season 
unit that commences commercial operation on or after July 1, 2011 and 
that reports on an annual basis under Sec.  97.534(d), by the later of 
the following:
    (i) 180 calendar days after the date on which the unit commences 
commercial operation; or
    (ii) May 1, 2012.
    (3) For the owner or operator of a TR NOX Ozone Season 
unit that commences commercial operation on or after July 1, 2011 and 
that reports on a control period basis under Sec.  97.534(d)(2)(ii), by 
the following date:
    (i) 180 calendar days 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 after the 
compliance date under paragraph (b)(3)(i) of this section.
    (4) The owner or operator of a TR 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), or (3) of this section shall meet 
the requirements of Sec. Sec.  75.4(e)(1) through (e)(4) of this 
chapter, except that:
    (i) Such requirements shall apply to the monitoring systems 
required under Sec.  97.530 through Sec.  97.535, rather than the 
monitoring systems required under part 75 of this chapter;
    (ii) NOX emission rate, NOX concentration, 
stack gas moisture content, stack gas volumetric flow rate, and 
O2 or CO2 concentration data shall be determined 
and reported, rather than the data listed in Sec.  75.4(e)(2) of this 
chapter; and
    (iii) Any petition for another procedure under Sec.  75.4(e)(2) of 
this chapter shall be submitted under Sec.  97.535, rather than Sec.  
75.66.
    (c) Reporting data. The owner or operator of a TR 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.
    (d) Prohibitions. (1) No owner or operator of a TR 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.  97.535.
    (2) No owner or operator of a TR NOX Ozone Season unit 
shall operate the unit so as to discharge, or allow to be discharged, 
NOX to the atmosphere without accounting for all such 
NOX in accordance with the applicable provisions of this 
subpart and part 75 of this chapter.
    (3) No owner or operator of a TR 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 discharged into the 
atmosphere or heat input, 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 TR 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.  97.505 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 Administrator 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 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.  
97.531(d)(3)(i).
    (e) Long-term cold storage. The owner or operator of a TR 
NOX Ozone Season unit is subject to the applicable 
provisions of Sec.  75.4(d) of this chapter concerning units in long-
term cold storage.

Sec.  97.531  Initial monitoring system certification and 
recertification procedures.

    (a) The owner or operator of a TR NOX Ozone Season unit 
shall be exempt from the initial certification requirements of this 
section for a monitoring system under Sec.  97.530(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 appendices B, D, and 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.  97.530(a)(1) that is 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 or Sec.  75.17 of this chapter, the designated 
representative shall resubmit the petition to the Administrator under 
Sec.  97.535 to determine whether the approval applies under the TR 
NOX Ozone Season Trading Program.
    (d) Except as provided in paragraph (a) of this section, the owner 
or operator of a TR 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.  97.530(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.

[[Page 48430]]

    (1) Requirements for initial certification. The owner or operator 
shall ensure that each continuous monitoring system under Sec.  
97.530(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.  97.530(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.  97.530(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.  97.530(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. 
For initial certification of a continuous monitoring system under Sec.  
97.530(a)(1), paragraphs (d)(3)(i) through (v) of this section apply. 
For recertifications of such monitoring systems, paragraphs (d)(3)(i) 
through (iv) of this section and 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) apply, provided that in applying 
paragraphs (d)(3)(i) through (iv) of this section, the words 
``certification'' and ``initial certification'' are replaced by the 
word ``recertification'' and the word ``certified'' is replaced by with 
the word ``recertified''.
    (i) Notification of certification. The designated representative 
shall submit to the appropriate EPA Regional Office and the 
Administrator written notice of the dates of certification testing, in 
accordance with Sec.  97.533.
    (ii) Certification application. The designated representative shall 
submit to the Administrator 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 TR NOX Ozone Season Trading 
Program for a period not to exceed 120 days after receipt by the 
Administrator 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 Administrator 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 Administrator.
    (iv) Certification application approval process. The Administrator 
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 Administrator 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 TR 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 Administrator 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 Administrator will issue a written notice of 
incompleteness that sets a reasonable date by which the designated 
representative must submit the additional information required to 
complete the certification application. If the designated 
representative does not comply with the notice of incompleteness by the 
specified date, then the Administrator may issue a notice of 
disapproval under paragraph (d)(3)(iv)(C) of this section.
    (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 Administrator 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 Administrator 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).
    (D) Audit decertification. The Administrator may issue a notice of 
disapproval of the certification status of a monitor in accordance with 
Sec.  97.532(b).
    (v) Procedures for loss of certification. If 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

[[Page 48431]]

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 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 Administrator's notice of disapproval, no later than 
30 unit operating days after the date of issuance of the notice of 
disapproval.
    (e) 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) The designated representative of each unit for which the owner 
or operator intends to use an alternative monitoring system approved by 
the Administrator 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.  97.532  Monitoring system out-of-control periods.

    (a) General provisions. 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.  97.531 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 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 Administrator or any 
State or permitting authority. By issuing the notice of disapproval, 
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.  
97.531 for each disapproved monitoring system.

Sec.  97.533  Notifications concerning monitoring.

    The designated representative of a TR NOX Ozone Season 
unit shall submit written notice to the Administrator in accordance 
with Sec.  75.61 of this chapter.

Sec.  97.534  Recordkeeping and reporting.

    (a) General provisions. The designated representative shall comply 
with all recordkeeping and reporting requirements in paragraphs (b) 
through (e) of this section, the applicable recordkeeping and reporting 
requirements under Sec.  75.73 of this chapter, and the requirements of 
Sec.  97.514(a).
    (b) Monitoring plans. The owner or operator of a TR NOX 
Ozone Season unit shall comply with requirements of Sec.  75.73(c) and 
(e) of this chapter.
    (c) Certification applications. The designated representative shall 
submit an application to the Administrator within 45 days after 
completing all initial certification or recertification tests required 
under Sec.  97.531, including the information required under Sec.  
75.63 of this chapter.
    (d) Quarterly reports. The designated representative shall submit 
quarterly reports, as follows:
    (1) If the TR NOX Ozone Season unit is subject to the 
Acid Rain Program or a TR NOX Annual emissions limitation or 
if the owner or operator of such unit chooses to report on an annual 
basis under this subpart, the designated representative shall meet the 
requirements of subpart H of part 75 of this chapter (concerning 
monitoring of NOX mass emissions) for 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, 
2011, the calendar quarter covering May 1, 2012 through June 30, 2012; 
or
    (ii) For a unit that commences commercial operation on or after 
July 1, 2011, the calendar quarter corresponding to the earlier of the 
date of provisional certification or the applicable deadline for 
initial certification under Sec.  97.530(b), unless that quarter is the 
third or fourth quarter of 2011 or the first quarter of 2012, in which 
case reporting shall commence in the quarter covering May 1, 2012 
through June 30, 2012.
    (2) If the TR NOX Ozone Season unit is not subject to 
the Acid Rain Program or a TR NOX Annual emissions 
limitation, then the 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, 
2011, the calendar quarter covering May 1, 2012 through June 30, 2012; 
or
    (B) For a unit that commences commercial operation on or after July 
1, 2011, the calendar quarter corresponding to the earlier of the date

[[Page 48432]]

of provisional certification or the applicable deadline for initial 
certification under Sec.  97.530(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.
    (3) The designated representative shall submit each quarterly 
report to the Administrator within 30 days after 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.
    (4) For TR NOX Ozone Season units that are also subject 
to the Acid Rain Program, TR NOX Annual Trading Program, TR 
SO2 Group 1 Trading Program, or TR SO2 Group 2 
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.
    (5) The Administrator may review and conduct independent audits of 
any quarterly report in order to determine whether the quarterly report 
meets the requirements of this subpart and part 75 of this chapter, 
including the requirement to use substitute data.
    (i) The Administrator will notify the designated representative of 
any determination that the quarterly report fails to meet any such 
requirements and specify in such notification any corrections that the 
Administrator believes are necessary to make through resubmission of 
the quarterly report and a reasonable time period within which the 
designated representative must respond. Upon request by the designated 
representative, the Administrator may specify reasonable extensions of 
such time period. Within the time period (including any such 
extensions) specified by the Administrator, the designated 
representative shall resubmit the quarterly report with the corrections 
specified by the Administrator, except to the extent the designated 
representative provides information demonstrating that a specified 
correction is not necessary because the quarterly report already meets 
the requirements of this subpart and part 75 of this chapter that are 
relevant to the specified correction.
    (6) Any resubmission of a quarterly report shall meet the 
requirements applicable to the submission of a quarterly report under 
this subpart and part 75 of this chapter, except for the deadline set 
forth in paragraph (d)(3) of this section.
    (e) Compliance certification. The 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.  97.535  Petitions for alternatives to monitoring, recordkeeping, 
or reporting requirements.

    (a) The designated representative of a TR NOX Ozone 
Season unit may submit a petition under Sec.  75.66 of this chapter to 
the Administrator, requesting approval to apply an alternative to any 
requirement of Sec. Sec.  97.530 through 97.534.
    (b) A petition submitted under paragraph (a) of this section shall 
include sufficient information for the evaluation of the petition, 
including, at a minimum, the following information:
    (i) Identification of each unit and source covered by the petition;
    (ii) A detailed explanation of why the proposed alternative is 
being suggested in lieu of the requirement;
    (iii) A description and diagram of any equipment and procedures 
used in the proposed alternative;
    (iv) A demonstration that the proposed alternative is consistent 
with the purposes of the requirement for which the alternative is 
proposed and with the purposes of this subpart and part 75 of this 
chapter and that any adverse effect of approving the alternative will 
be de minimis: and
    (v) Any other relevant information that the Administrator may 
require.
    (c) Use of an alternative to any requirement referenced in 
paragraph (a) of this section is in accordance with this subpart only 
to the extent that the petition is approved in writing by the 
Administrator and that such use is in accordance with such approval.
    76. Part 97 is amended by adding subpart CCCCC to read as follows:

Subpart CCCCC--TR SO2 Group 1 Trading Program

Sec.
97.601 Purpose.
97.602 Definitions.
97.603 Measurements, abbreviations, and acronyms.
97.604 Applicability.
97.605 Retired unit exemption.
97.606 Standard requirements.
97.607 Computation of time.
97.608 Administrative appeal procedures.
97.609 [Reserved]
97.610 State SO2 Group 1 trading budgets, new unit set-
asides, Indian country new unit set-asides and variability limits.
97.611 Timing requirements for TR SO2 Group 1 allowance 
allocations.
97.612 TR SO2 Group 1 allowance allocations to new units.
97.613 Authorization of designated representative and alternate 
designated representative.
97.614 Responsibilities of designated representative and alternate 
designated representative.
97.615 Changing designated representative and alternate designated 
representative; changes in owners and operators.
97.616 Certificate of representation.
97.617 Objections concerning designated representative and alternate 
designated representative.
97.618 Delegation by designated representative and alternate 
designated representative.
97.619 [Reserved]
97.620 Establishment of compliance accounts and general accounts.
97.621 Recordation of TR SO2 Group 1 allowance 
allocations.
97.622 Submission of TR SO2 Group 1 allowance transfers.
97.623 Recordation of TR SO2 Group 1 allowance transfers.
97.624 Compliance with TR SO2 Group 1 emissions 
limitation.
97.625 Compliance with TR SO2 Group 1 assurance 
provisions.
97.626 Banking.
97.627 Account error.
97.628 Administrator's action on submissions.
97.629 [Reserved]
97.630 General monitoring, recordkeeping, and reporting 
requirements.
97.631 Initial monitoring system certification and recertification 
procedures.
97.632 Monitoring system out-of-control periods.

[[Page 48433]]

97.633 Notifications concerning monitoring.
97.634 Recordkeeping and reporting.
97.635 Petitions for alternatives to monitoring, recordkeeping, or 
reporting requirements.

Subpart CCCCC--TR SO2 Group 1 Trading Program

Sec.  97.601  Purpose.

    This subpart sets forth the general, designated representative, 
allowance, and monitoring provisions for the Transport Rule (TR) 
SO2 Group 1 Trading Program, under section 110 of the Clean 
Air Act and Sec.  52.39 of this chapter, as a means of mitigating 
interstate transport of fine particulates and sulfur dioxide.

Sec.  97.602  Definitions.

    The terms used in this subpart shall have the meanings set forth in 
this section as follows:
    Acid Rain Program means a multi-state SO2 and 
NOX air pollution control and emission reduction program 
established by the Administrator under title IV of the Clean Air Act 
and parts 72 through 78 of this chapter.
    Administrator means the Administrator of the United States 
Environmental Protection Agency or the Director of the Clean Air 
Markets Division (or its successor determined by the Administrator) of 
the United States Environmental Protection Agency, the Administrator's 
duly authorized representative under this subpart.
    Allocate or allocation means, with regard to TR SO2 
Group 1 allowances, the determination by the Administrator, State, or 
permitting authority, in accordance with this subpart and any SIP 
revision submitted by the State and approved by the Administrator under 
Sec.  52.39(d), (e), or (f) of this chapter, of the amount of such TR 
SO2 Group 1 allowances to be initially credited, at no cost 
to the recipient, to:
    (1) A TR SO2 Group 1 unit;
    (2) A new unit set-aside;
    (3) An Indian country new unit set-aside; or
    (4) An entity not listed in paragraphs (1) through (3) of this 
definition;
    (5) Provided that, if the Administrator, State, or permitting 
authority initially credits, to a TR SO2 Group 1 unit 
qualifying for an initial credit, a credit in the amount of zero TR 
SO2 Group 1 allowances, the TR SO2 Group 1 unit 
will be treated as being allocated an amount (i.e., zero) of TR 
SO2 Group 1 allowances.
    Allowable SO2 emission rate means, for a unit, the most stringent 
State or federal SO2 emission rate limit (in lb/MWhr or, if 
in lb/mmBtu, converted to lb/MWhr by multiplying it by the unit's heat 
rate in mmBtu/MWhr) that is applicable to the unit and covers the 
longest averaging period not exceeding one year.
    Allowance Management System means the system by which the 
Administrator records allocations, deductions, and transfers of TR 
SO2 Group 1 allowances under the TR SO2 Group 1 
Trading Program. Such allowances are allocated, recorded, held, 
deducted, or transferred only as whole allowances.
    Allowance Management System account means an account in the 
Allowance Management System established by the Administrator for 
purposes of recording the allocation, holding, transfer, or deduction 
of TR SO2 Group 1 allowances.
    Allowance transfer deadline means, for a control period in a given 
year, midnight of March 1 (if it is a business day), or midnight of the 
first business day thereafter (if March 1 is not a business day), 
immediately after such control period and is the deadline by which a TR 
SO2 Group 1 allowance transfer must be submitted for 
recordation in a TR SO2 Group 1 source's compliance account 
in order to be available for use in complying with the source's TR 
SO2 Group 1 emissions limitation for such control period in 
accordance with Sec. Sec.  97.606 and 97.624.
    Alternate designated representative means, for a TR SO2 
Group 1 source and each TR SO2 Group 1 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 this 
subpart, to act on behalf of the designated representative in matters 
pertaining to the TR SO2 Group 1 Trading Program. If the TR 
SO2 Group 1 source is also subject to the Acid Rain Program, 
TR NOX Annual Trading Program, or TR NOX Ozone 
Season Trading Program, then this natural person shall be the same 
natural person as the alternate designated representative, as defined 
in the respective program.
    Assurance account means an Allowance Management System account, 
established by the Administrator under Sec.  97.625(b)(3) for certain 
owners and operators of a group of one or more TR SO2 Group 
1 sources and units in a given State (and Indian country within the 
borders of such State), in which are held TR SO2 Group 1 
allowances available for use for a control period in a given year in 
complying with the TR SO2 Group 1 assurance provisions in 
accordance with Sec. Sec.  97.606 and 97.625.
    Authorized account representative means, for a general account, the 
natural person who is authorized, in accordance with this subpart, to 
transfer and otherwise dispose of TR SO2 Group 1 allowances 
held in the general account and, for a TR SO2 Group 1 
source's compliance account, the designated representative of the 
source.
    Automated data acquisition and handling system or DAHS means the 
component of the continuous emission monitoring system, or other 
emissions monitoring system approved for use under this subpart, 
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 this subpart.
    Biomass means--
    (1) Any organic material grown for the purpose of being converted 
to energy;
    (2) Any organic byproduct of agriculture that can be converted into 
energy; or
    (3) Any material that can be converted into energy and is 
nonmerchantable for other purposes, that is segregated from other 
material that is nonmerchantable for other purposes, and that is;
    (i) A forest-related organic resource, including mill residues, 
precommercial thinnings, slash, brush, or byproduct from conversion of 
trees to merchantable material; or
    (ii) A wood material, including pallets, crates, dunnage, 
manufacturing and construction materials (other than pressure-treated, 
chemically-treated, or painted wood products), and landscape or right-
of-way tree trimmings.
    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 unit means a unit in which the energy input to the 
unit is first used to produce useful thermal energy, where at least 
some of the reject heat from the useful thermal energy application or 
process is then used for electricity production.
    Business day means a day that does not fall on a weekend or a 
federal holiday.
    Certifying official means a natural person who is:
    (1) For a corporation, a president, secretary, treasurer, or vice-
president of the corporation in charge of a principal business function 
or any other person who performs similar policy- or decision-making 
functions for the corporation;

[[Page 48434]]

    (2) For a partnership or sole proprietorship, a general partner or 
the proprietor respectively; or
    (3) For a local government entity or State, federal, or other 
public agency, a principal executive officer or ranking elected 
official.
    Clean Air Act means the Clean Air Act, 42 U.S.C. 7401, et seq.
    Coal means ``coal'' as defined in Sec.  72.2 of this chapter.
    Coal-derived fuel means any fuel (whether in a solid, liquid, or 
gaseous state) produced by the mechanical, thermal, or chemical 
processing of coal.
    Cogeneration system means an integrated group, at a source, of 
equipment (including a boiler, or combustion turbine, and a steam 
turbine generator) designed to produce useful thermal energy for 
industrial, commercial, heating, or cooling purposes and electricity 
through the sequential use of energy.
    Cogeneration unit means a stationary, fossil-fuel-fired boiler or 
stationary, fossil-fuel-fired combustion turbine that is a topping-
cycle unit or a bottoming-cycle unit:
    (1) Operating as part of a cogeneration system; and
    (2) Producing on an annual average basis--
    (i) For a topping-cycle 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 than 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 unit, useful power not less than 45 
percent of total energy input;
    (3) Provided that the requirements in paragraph (2) of this 
definition shall not apply to a calendar year referenced in paragraph 
(2) of this definition during which the unit did not operate at all;
    (4) Provided that the total energy input under paragraphs (2)(i)(B) 
and (2)(ii) of this definition shall equal the unit's total energy 
input from all fuel, except biomass if the unit is a boiler; and
    (5) Provided that, if, throughout its operation during the 12-month 
period or a calendar year referenced in paragraph (2) of this 
definition, a unit is operated as part of a cogeneration system and the 
cogeneration system meets on a system-wide basis the requirement in 
paragraph (2)(i)(B) or (2)(ii) of this definition, the unit shall be 
deemed to meet such requirement during that 12-month period or calendar 
year.
    Combustion turbine means an enclosed device comprising:
    (1) If the device is simple cycle, 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 device is combined cycle, the equipment described in 
paragraph (1) of this definition and any associated duct burner, heat 
recovery steam generator, and steam turbine.
    Commence commercial operation means, with regard to a unit:
    (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.  97.605.
    (i) For a unit that is a TR SO2 Group 1 unit under Sec.  
97.604 on the later of January 1, 2005 or the date the unit commences 
commercial operation as defined in the introductory text of paragraph 
(1) of this definition and that subsequently undergoes a physical 
change or is moved to a new location or source, such date shall remain 
the date of commencement of commercial operation of the unit, which 
shall continue to be treated as the same unit.
    (ii) For a unit that is a TR SO2 Group 1 unit under 
Sec.  97.604 on the later of January 1, 2005 or the date the unit 
commences commercial operation as defined in the introductory text of 
paragraph (1) of this definition and that is subsequently replaced by a 
unit at the same or a different source, such date shall remain the 
replaced unit's date of commencement of commercial operation, and the 
replacement unit shall be treated as a separate unit with a separate 
date for commencement of commercial operation as defined in paragraph 
(1) or (2) of this definition as appropriate.
    (2) Notwithstanding paragraph (1) of this definition and except as 
provided in Sec.  97.605, for a unit that is not a TR SO2 
Group 1 unit under Sec.  97.604 on the later of January 1, 2005 or the 
date the unit commences commercial operation as defined in introductory 
text of paragraph (1) of this definition, the unit's date for 
commencement of commercial operation shall be the date on which the 
unit becomes a TR SO2 Group 1 unit under Sec.  97.604.
    (i) For a unit with a date for commencement of commercial operation 
as defined in the introductory text of paragraph (2) of this definition 
and that subsequently undergoes a physical change or is moved to a 
different location or source, such date shall remain the date of 
commencement of commercial operation of the unit, which shall continue 
to be treated as the same unit.
    (ii) For a unit with a date for commencement of commercial 
operation as defined in the introductory text of paragraph (2) of this 
definition and that is subsequently replaced by a unit at the same or a 
different source, such date shall remain the replaced unit's date of 
commencement of commercial operation, and the replacement unit shall be 
treated as a separate unit with a separate date for commencement of 
commercial operation as defined in paragraph (1) or (2) of this 
definition as appropriate.
    Common designated representative means, with regard to a control 
period in a given year, a designated representative where, as of April 
1 immediately after the allowance transfer deadline for such control 
period, the same natural person is authorized under Sec. Sec.  
97.613(a) and 97.615(a) as the designated representative for a group of 
one or more TR SO2 Group 1 sources and units located in a 
State (and Indian country within the borders of such State).
    Common designated representative's assurance level means, with 
regard to a specific common designated representative and a State (and 
Indian country within the borders of such State) and control period in 
a given year for which the State assurance level is exceeded as 
described in Sec.  97.606(c)(2)(iii), the common designated 
representative's share of the State SO2 Group 1 trading 
budget with the variability limit for the State for such control 
period.
    Common designated representative's share means, with regard to a 
specific common designated representative for a control period in a 
given year:
    (1) With regard to a total amount of SO2 emissions from 
all TR SO2 Group 1 units in a State (and Indian country 
within the borders of such State) during such control period, the total 
tonnage of SO2 emissions during such control period from a 
group of one or more TR SO2 Group 1 units located in such 
State (and such Indian country) and having the common designated 
representative for such control period;
    (2) With regard to a State SO2 Group 1 trading budget 
with the variability limit for such control period, the amount (rounded 
to the nearest allowance) equal to the sum of the total amount of TR 
SO2 Group 1 allowances allocated for such control period to 
a group of one or more TR SO2 Group 1 units located in the 
State (and Indian country within the borders of such

[[Page 48435]]

State) and having the common designated representative for such control 
period and of the total amount of TR SO2 Group 1 allowances 
purchased by an owner or operator of such TR SO2 Group 1 
units in an auction for such control period and submitted by the State 
or the permitting authority to the Administrator for recordation in the 
compliance accounts for such TR SO2 Group 1 units in 
accordance with the TR SO2 Group 1 allowance auction 
provisions in a SIP revision approved by the Administrator under Sec.  
52.39(e) or (f) of this chapter, multiplied by the sum of the State 
SO2 Group 1 trading budget under Sec.  97.610(a) and the 
State's variability limit under Sec.  97.610(b) for such control period 
and divided by such State SO2 Group 1 trading budget;
    (3) Provided that, in the case of a unit that operates during, but 
has no amount of TR SO2 Group 1 allowances allocated under 
Sec. Sec.  97.611 and 97.612 for, such control period, the unit shall 
be treated, solely for purposes of this definition, as being allocated 
an amount (rounded to the nearest allowance) of TR SO2 Group 
1 allowances for such control period equal to the unit's allowable 
SO2 emission rate applicable to such control period, 
multiplied by a capacity factor of 0.85 (if the unit is a boiler 
combusting any amount of coal or coal-derived fuel during such control 
period), 0.24 (if the unit is a simple combustion turbine during such 
control period), 0.67 (if the unit is a combined cycle turbine during 
such control period), 0.74 (if the unit is an integrated coal 
gasification combined cycle unit during such control period), or 0.36 
(for any other unit), multiplied by the unit's maximum hourly load as 
reported in accordance with this subpart and by 8,760 hours/control 
period, and divided by 2,000 lb/ton.
    Common stack means a single flue through which emissions from 2 or 
more units are exhausted.
    Compliance account means an Allowance Management System account, 
established by the Administrator for a TR SO2 Group 1 source 
under this subpart, in which any TR SO2 Group 1 allowance 
allocations to the TR SO2 Group 1 units at the source are 
recorded and in which are held any TR SO2 Group 1 allowances 
available for use for a control period in a given year in complying 
with the source's TR SO2 Group 1 emissions limitation in 
accordance with Sec. Sec.  97.606 and 97.624.
    Continuous emission monitoring system or CEMS means the equipment 
required under this subpart to sample, analyze, measure, and provide, 
by means of readings recorded at least once every 15 minutes and using 
an automated data acquisition and handling system (DAHS), a permanent 
record of SO2 emissions, stack gas volumetric flow rate, 
stack gas moisture content, and O2 or CO2 
concentration (as applicable), in a manner consistent with part 75 of 
this chapter and Sec. Sec.  97.630 through 97.635. The following 
systems are the principal types of continuous emission monitoring 
systems:
    (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 SO2 monitoring system, consisting of a 
SO2 pollutant concentration monitor and an automated data 
acquisition and 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 CO2 monitoring system, consisting of a 
CO2 pollutant concentration monitor (or an O2 
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 O2 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 starting January 1 of a calendar 
year, except as provided in Sec.  97.606(c)(3), and ending on December 
31 of the same year, inclusive.
    Designated representative means, for a TR SO2 Group 1 
source and each TR SO2 Group 1 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 this 
subpart, to represent and legally bind each owner and operator in 
matters pertaining to the TR SO2 Group 1 Trading Program. If 
the TR SO2 Group 1 source is also subject to the Acid Rain 
Program, TR NOX Annual Trading Program, or TR NOX 
Ozone Season Trading Program, then this natural person shall be the 
same natural person as the designated representative, as defined in the 
respective program.
    Emissions means air pollutants exhausted from a unit or source into 
the atmosphere, as measured, recorded, and reported to the 
Administrator by the designated representative, and as modified by the 
Administrator:
    (1) In accordance with this subpart; and
    (2) With regard to a period before the unit or source is required 
to measure, record, and report such air pollutants in accordance with 
this subpart, in accordance with part 75 of this chapter.
    Excess emissions means any ton of emissions from the TR 
SO2 Group 1 units at a TR SO2 Group 1 source 
during a control period in a given year that exceeds the TR 
SO2 Group 1 emissions limitation for the source for such 
control period.
    Fossil fuel means--
    (1) Natural gas, petroleum, coal, or any form of solid, liquid, or 
gaseous fuel derived from such material; or
    (2) For purposes of applying the limitation on ``average annual 
fuel consumption of fossil fuel'' in Sec. Sec.  97.604(b)(2)(i)(B) and 
(ii), natural gas, petroleum, coal, or any form of solid, liquid, or 
gaseous fuel derived from such material for the purpose of creating 
useful heat.
    Fossil-fuel-fired means, with regard to a unit, combusting any 
amount of fossil fuel in 2005 or any calendar year thereafter.
    General account means an Allowance Management System account, 
established under this subpart, that is not a compliance account or an 
assurance account.
    Generator means a device that produces electricity.
    Gross electrical output means, for a 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, for a unit for a specified period of time, the 
product (in mmBtu/time) of the gross calorific value of the fuel (in 
mmBtu/lb) fed into the unit multiplied by the fuel feed rate (in lb of 
fuel/time), as measured, recorded, and reported to the Administrator by 
the designated representative and as modified by the Administrator in 
accordance with this subpart and excluding the heat derived from 
preheated combustion air, recirculated flue gases, or exhaust.
    Heat input rate means, for a unit, the amount of heat input (in 
mmBtu) divided by unit operating time (in hr) or, for a unit and a 
specific fuel, the amount of heat input attributed to the

[[Page 48436]]

fuel (in mmBtu) divided by the unit operating time (in hr) during which 
the unit combusts the fuel.
    Heat rate means, for a unit, the unit's maximum design heat input 
(in Btu/hr), divided by the product of 1,000,000 Btu/mmBtu and the 
unit's maximum hourly load.
    Indian country means ``Indian country'' as defined in 18 U.S.C. 
1151.
    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, for a unit, the maximum amount of 
fuel per hour (in Btu/hr) that the unit is capable of combusting on a 
steady state basis as of the initial installation of the unit as 
specified by the manufacturer of the unit.
    Monitoring system means any monitoring system that meets the 
requirements of this subpart, including a continuous emission 
monitoring system, an alternative monitoring system, or an excepted 
monitoring system under part 75 of this chapter.
    Nameplate capacity means, starting from the initial installation of 
a generator, the maximum electrical generating output (in MWe, rounded 
to the nearest tenth) 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 of such installation 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 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 (in MWe, rounded to the nearest tenth) as of 
such completion as specified by the person conducting the physical 
change.
    Natural gas means ``natural gas'' as defined in Sec.  72.2 of this 
chapter.
    Newly affected TR SO2 Group 1 unit means a unit that was not a TR 
SO2 Group 1 unit when it began operating but that thereafter 
becomes a TR SO2 Group 1 unit.
    Operate or operation means, with regard to a unit, to combust fuel.
    Operator means, for a TR SO2 Group 1 source or a TR 
SO2 Group 1 unit at a source respectively, any person who 
operates, controls, or supervises a TR SO2 Group 1 unit at 
the source or the TR SO2 Group 1 unit and shall include, but 
not be limited to, any holding company, utility system, or plant 
manager of such source or unit.
    Owner means, for a TR SO2 Group 1 source or a TR 
SO2 Group 1 unit at a source respectively, any of the 
following persons:
    (1) Any holder of any portion of the legal or equitable title in a 
TR SO2 Group 1 unit at the source or the TR SO2 
Group 1 unit;
    (2) Any holder of a leasehold interest in a TR SO2 Group 
1 unit at the source or the TR SO2 Group 1 unit, 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 TR 
SO2 Group 1 unit; and
    (3) Any purchaser of power from a TR SO2 Group 1 unit at 
the source or the TR SO2 Group 1 unit under a life-of-the-
unit, firm power contractual arrangement.
    Permanently retired means, with regard to a unit, a unit that is 
unavailable for service and that the unit's owners and operators do not 
expect to return to service in the future.
    Permitting authority means ``permitting authority'' as defined in 
Sec. Sec.  70.2 and 71.2 of this chapter.
    Potential electrical output capacity means, for a unit, 33 percent 
of the 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 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 log, or by a notation made on the document, 
information, or correspondence, by the Administrator in the regular 
course of business.
    Recordation, record, or recorded means, with regard to TR 
SO2 Group 1 allowances, the moving of TR SO2 
Group 1 allowances by the Administrator into, out of, or between 
Allowance Management System accounts, for purposes of allocation, 
auction, 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.
    Replacement, replace, or replaced means, with regard to a unit, the 
demolishing of a unit, or the permanent retirement and permanent 
disabling of a unit, and the construction of another unit (the 
replacement unit) to be used instead of the demolished or retired unit 
(the replaced unit).
    Sequential use of energy means:
    (1) The use of reject heat from electricity production in a useful 
thermal energy application or process; or
    (2) The use of reject heat from useful thermal energy application 
or process in electricity production.
    Serial number means, for a TR SO2 Group 1 allowance, the 
unique identification number assigned to each TR SO2 Group 1 
allowance by the Administrator.
    Solid waste incineration unit means a stationary, fossil-fuel-fired 
boiler or stationary, fossil-fuel-fired combustion turbine that is a 
``solid waste incineration unit'' as defined in section 129(g)(1) of 
the Clean Air Act.
    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. This definition does not change or 
otherwise affect the definition of ``major source'', ``stationary 
source'', or ``source'' as set forth and implemented in a title V 
operating permit program or any other program under the Clean Air Act.
    State means one of the States that is subject to the TR 
SO2 Group 1 Trading Program pursuant to Sec.  52.39(a), (b), 
(d), (e), and (f) 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;
    (4) Provided that compliance with any ``submission'' or ``service'' 
deadline shall be determined by the date of dispatch, transmission, or 
mailing and not the date of receipt.

[[Page 48437]]

    Topping-cycle unit means a unit in which the energy input to the 
unit is first used to produce useful power, including electricity, 
where at least some of the reject heat from the electricity production 
is then used to provide useful thermal energy.
    Total energy input means, for a unit, total energy of all forms 
supplied to the unit, excluding energy produced by the unit. Each form 
of energy supplied shall be measured by the lower heating value of that 
form of energy calculated as follows:

LHV = HHV - 10.55(W + 9H)

Where:

LHV = lower heating value of the form of energy in Btu/lb,
HHV = higher heating value of the form of energy in Btu/lb,
W = weight % of moisture in the form of energy, and
H = weight % of hydrogen in the form of energy.

    Total energy output means, for a unit, the sum of useful power and 
useful thermal energy produced by the unit.
    TR NOX Annual Trading Program means a multi-state NOX 
air pollution control and emission reduction program established in 
accordance with subpart AAAAA of this part and Sec.  52.38(a) of this 
chapter (including such a program that is revised in a SIP revision 
approved by the Administrator under Sec.  52.38(a)(3) or (4) of this 
chapter or that is established in a SIP revision approved by the 
Administrator under Sec.  52.38(a)(5) of this chapter), as a means of 
mitigating interstate transport of fine particulates and 
NOX.
    TR NOX Ozone Season Trading Program means a multi-state 
NOX air pollution control and emission reduction program 
established in accordance with subpart BBBBB of this part and Sec.  
52.38(b) of this chapter (including such a program that is revised in a 
SIP revision approved by the Administrator under Sec.  52.38(b)(3) or 
(4) of this chapter or that is established in a SIP revision approved 
by the Administrator under Sec.  52.38(b)(5) of this chapter), as a 
means of mitigating interstate transport of ozone and NOX.
    TR SO2 Group 1 allowance means a limited authorization issued and 
allocated or auctioned by the Administrator under this subpart, or by a 
State or permitting authority under a SIP revision approved by the 
Administrator under Sec.  52.39(d), (e), or (f) of this chapter, to 
emit one ton of SO2 during a control period of the specified 
calendar year for which the authorization is allocated or auctioned or 
of any calendar year thereafter under the TR SO2 Group 1 
Trading Program.
    TR SO2 Group 1 allowance deduction or deduct TR SO2 
Group 1 allowances means the permanent withdrawal of TR SO2 
Group 1 allowances by the Administrator from a compliance account 
(e.g., in order to account for compliance with the TR SO2 
Group 1 emissions limitation) or from an assurance account (e.g., in 
order to account for compliance with the assurance provisions under 
Sec. Sec.  97.606 and 97.625).
    TR SO2 Group 1 allowances held or hold TR SO2 Group 1 allowances 
means the TR SO2 Group 1 allowances treated as included in 
an Allowance Management System account as of a specified point in time 
because at that time they:
    (1) Have been recorded by the Administrator in the account or 
transferred into the account by a correctly submitted, but not yet 
recorded, TR SO2 Group 1 allowance transfer in accordance 
with this subpart; and
    (2) Have not been transferred out of the account by a correctly 
submitted, but not yet recorded, TR SO2 Group 1 allowance 
transfer in accordance with this subpart.
    TR SO2 Group 1 emissions limitation means, for a TR SO2 
Group 1 source, the tonnage of SO2 emissions authorized in a 
control period by the TR SO2 Group 1 allowances available 
for deduction for the source under Sec.  97.624(a) for such control 
period.
    TR SO2 Group 1 source means a source that includes one or more TR 
SO2 Group 1 units.
    TR SO2 Group 1 Trading Program means a multi-state SO2 
air pollution control and emission reduction program established in 
accordance with this subpart and Sec.  52.39(a), (b), (d) through (f), 
(j), and (k) of this chapter (including such a program that is revised 
in a SIP revision approved by the Administrator under Sec.  52.39(d) or 
(e) of this chapter or that is established in a SIP revision approved 
by the Administrator under Sec.  52.39(f) of this chapter), as a means 
of mitigating interstate transport of fine particulates and 
SO2.
    TR SO2 Group 1 unit means a unit that is subject to the TR 
SO2 Group 1 Trading Program under Sec.  97.604.
    Unit means a stationary, fossil-fuel-fired boiler, stationary, 
fossil-fuel-fired combustion turbine, or other stationary, fossil-fuel-
fired combustion device. A unit that undergoes a physical change or is 
moved to a different location or source shall continue to be treated as 
the same unit. A unit (the replaced unit) that is replaced by another 
unit (the replacement unit) at the same or a different source shall 
continue to be treated as the same unit, and the replacement unit shall 
be treated as a separate unit.
    Unit operating day means, with regard to a unit, a calendar day in 
which the unit combusts any fuel.
    Unit operating hour or hour of unit operation means, with regard to 
a unit, an hour in which the unit combusts any fuel.
    Useful power means, with regard to a unit, electricity or 
mechanical energy that the unit makes 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 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., in 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.  97.603  Measurements, abbreviations, and acronyms.

    Measurements, abbreviations, and acronyms used in this subpart are 
defined as follows:

Btu--British thermal unit
CO2--carbon dioxide
H2O--water
hr--hour
kW--kilowatt electrical
kWh--kilowatt hour
lb--pound
mmBtu--million Btu
MWe--megawatt electrical
MWh--megawatt hour
NOX--nitrogen oxides
O2--oxygen
ppm--parts per million
scfh--standard cubic feet per hour
SO2--sulfur dioxide
yr--year

Sec.  97.604  Applicability.

    (a) Except as provided in paragraph (b) of this section:
    (1) The following units in a State (and Indian country within the 
borders of such State) shall be TR SO2 Group 1 units, and 
any source that includes one or more such units shall be a TR 
SO2 Group 1 source, subject to the requirements of this 
subpart: any stationary, fossil-fuel-fired boiler or

[[Page 48438]]

stationary, fossil-fuel-fired combustion turbine serving at any time, 
on or after January 1, 2005, a generator with nameplate capacity of 
more than 25 MWe producing electricity for sale.
    (2) If a stationary boiler or stationary combustion turbine that, 
under paragraph (a)(1) of this section, is not a TR SO2 
Group 1 unit begins to combust fossil fuel or to serve a generator with 
nameplate capacity of more than 25 MWe producing electricity for sale, 
the unit shall become a TR SO2 Group 1 unit as provided in 
paragraph (a)(1) of this section on the first date on which it both 
combusts fossil fuel and serves such generator.
    (b) Any unit in a State (and Indian country within the borders of 
such State) that otherwise is a TR SO2 Group 1 unit under 
paragraph (a) of this section and that meets the requirements set forth 
in paragraph (b)(1)(i) or (2)(i) of this section shall not be a TR 
SO2 Group 1 unit:
    (1)(i) Any unit:
    (A) Qualifying as a cogeneration unit throughout the later of 2005 
or the 12-month period starting on the date the unit first produces 
electricity and continuing to qualify as a cogeneration unit throughout 
each calendar year ending after the later of 2005 or such 12-month 
period; and
    (B) Not supplying in 2005 or any calendar year thereafter 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.
    (ii) If, after qualifying under paragraph (b)(1)(i) of this section 
as not being a TR SO2 Group 1 unit, a unit subsequently no 
longer meets all the requirements of paragraph (b)(1)(i) of this 
section, the unit shall become a TR SO2 Group 1 unit 
starting on the earlier of January 1 after the first calendar year 
during which the unit first no longer qualifies as a cogeneration unit 
or January 1 after the first calendar year during which the unit no 
longer meets the requirements of paragraph (b)(1)(i)(B) of this 
section. The unit shall thereafter continue to be a TR SO2 
Group 1 unit.
    (2)(i) Any unit:
    (A) Qualifying as a solid waste incineration unit throughout the 
later of 2005 or the 12-month period starting on the date the unit 
first produces electricity and continuing to qualify as a solid waste 
incineration unit throughout each calendar year ending after the later 
of 2005 or such 12-month period; and
    (B) With an average annual fuel consumption of fossil fuel for the 
first 3 consecutive calendar years of operation starting no earlier 
than 2005 of less than 20 percent (on a Btu basis) and an average 
annual fuel consumption of fossil fuel for any 3 consecutive calendar 
years thereafter of less than 20 percent (on a Btu basis).
    (ii) If, after qualifying under paragraph (b)(2)(i) of this section 
as not being a TR SO2 Group 1 unit, a unit subsequently no 
longer meets all the requirements of paragraph (b)(1)(i) of this 
section, the unit shall become a TR SO2 Group 1 unit 
starting on the earlier of January 1 after the first calendar year 
during which the unit first no longer qualifies as a solid waste 
incineration unit or January 1 after the first 3 consecutive calendar 
years after 2005 for which the unit has an average annual fuel 
consumption of fossil fuel of 20 percent or more. The unit shall 
thereafter continue to be a TR SO2 Group 1 unit.
    (c) A certifying official of an owner or operator of any unit or 
other equipment may submit a petition (including any supporting 
documents) to the Administrator at any time for a determination 
concerning the applicability, under paragraphs (a) and (b) of this 
section or a SIP revision approved under Sec.  52.39(e) or (f) of this 
chapter, of the TR SO2 Group 1 Trading Program to the unit 
or other equipment.
    (1) Petition content. The petition shall be in writing and include 
the identification of the unit or other equipment and the relevant 
facts about the unit or other equipment. The petition and any other 
documents provided to the Administrator in connection with the petition 
shall include the following certification statement, signed by the 
certifying official: ``I am authorized to make this submission on 
behalf of the owners and operators of the unit or other equipment 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) Response. The Administrator will issue a written response to 
the petition and may request supplemental information determined by the 
Administrator to be relevant to such petition. The Administrator's 
determination concerning the applicability, under paragraphs (a) and 
(b) of this section, of the TR SO2 Group 1 Trading Program 
to the unit or other equipment shall be binding on any State or 
permitting authority unless the Administrator determines that the 
petition or other documents or information provided in connection with 
the petition contained significant, relevant errors or omissions.

Sec.  97.605  Retired unit exemption.

    (a)(1) Any TR SO2 Group 1 unit that is permanently 
retired shall be exempt from Sec.  97.606(b) and (c)(1), Sec.  97.624, 
and Sec. Sec.  97.630 through 97.635.
    (2) The exemption under paragraph (a)(1) of this section shall 
become effective the day on which the TR SO2 Group 1 unit is 
permanently retired. Within 30 days of the unit's permanent retirement, 
the designated representative shall submit a statement to the 
Administrator. The statement shall state, in a format prescribed by the 
Administrator, that the unit was permanently retired on a specified 
date and will comply with the requirements of paragraph (b) of this 
section.
    (b) Special provisions. (1) A unit exempt under paragraph (a) of 
this section shall not emit any SO2, 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 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 
designated representative of a unit exempt under paragraph (a) of this 
section shall comply with the requirements of the TR SO2 
Group 1 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 shall lose 
its exemption on the first date on which the unit resumes operation. 
Such unit shall be treated, for purposes of applying allocation, 
monitoring, reporting, and recordkeeping requirements under this 
subpart, as a unit that commences commercial operation on the first 
date on which the unit resumes operation.

[[Page 48439]]

Sec.  97.606  Standard requirements.

    (a) Designated representative requirements. The owners and 
operators shall comply with the requirement to have a designated 
representative, and may have an alternate designated representative, in 
accordance with Sec. Sec.  97.613 through 97.618.
    (b) Emissions monitoring, reporting, and recordkeeping 
requirements. (1) The owners and operators, and the designated 
representative, of each TR SO2 Group 1 source and each TR 
SO2 Group 1 unit at the source shall comply with the 
monitoring, reporting, and recordkeeping requirements of Sec. Sec.  
97.630 through 97.635.
    (2) The emissions data determined in accordance with Sec. Sec.  
97.630 through 97.635 shall be used to calculate allocations of TR 
SO2 Group 1 allowances under Sec. Sec.  97.611(a)(2) and (b) 
and 97.612 and to determine compliance with the TR SO2 Group 
1 emissions limitation and assurance provisions under paragraph (c) of 
this section, provided that, for each monitoring location from which 
mass emissions are reported, the mass emissions amount used in 
calculating such allocations and determining such compliance shall be 
the mass emissions amount for the monitoring location determined in 
accordance with Sec. Sec.  97.630 through 97.635 and rounded to the 
nearest ton, with any fraction of a ton less than 0.50 being deemed to 
be zero.
    (c) SO2 emissions requirements. (1) TR SO2 Group 1 
emissions limitation. (i) As of the allowance transfer deadline for a 
control period in a given year, the owners and operators of each TR 
SO2 Group 1 source and each TR SO2 Group 1 unit 
at the source shall hold, in the source's compliance account, TR 
SO2 Group 1 allowances available for deduction for such 
control period under Sec.  97.624(a) in an amount not less than the 
tons of total SO2 emissions for such control period from all 
TR SO2 Group 1 units at the source.
    (ii) If total SO2 emissions during a control period in a 
given year from the TR SO2 Group 1 units at a TR 
SO2 Group 1 source are in excess of the TR SO2 
Group 1 emissions limitation set forth in paragraph (c)(1)(i) of this 
section, then:
    (A) The owners and operators of the source and each TR 
SO2 Group 1 unit at the source shall hold the TR 
SO2 Group 1 allowances required for deduction under Sec.  
97.624(d); and
    (B) The owners and operators of the source and each TR 
SO2 Group 1 unit at the source shall pay any fine, penalty, 
or assessment or comply with any other remedy imposed, for the same 
violations, under the Clean Air Act, and each ton of such excess 
emissions and each day of such control period shall constitute a 
separate violation of this subpart and the Clean Air Act.
    (2) TR SO2 Group 1 assurance provisions. (i) If total 
SO2 emissions during a control period in a given year from 
all TR SO2 Group 1 units at TR SO2 Group 1 
sources in a State (and Indian country within the borders of such 
State) exceed the State assurance level, then the owners and operators 
of such sources and units in each group of one or more sources and 
units having a common designated representative for such control 
period, where the common designated representative's share of such 
SO2 emissions during such control period exceeds the common 
designated representative's assurance level for the State and such 
control period, shall hold (in the assurance account established for 
the owners and operators of such group) TR SO2 Group 1 
allowances available for deduction for such control period under Sec.  
97.625(a) in an amount equal to two times the product (rounded to the 
nearest whole number), as determined by the Administrator in accordance 
with Sec.  97.625(b), of multiplying--
    (A) The quotient of the amount by which the common designated 
representative's share of such SO2 emissions exceeds the 
common designated representative's assurance level divided by the sum 
of the amounts, determined for all common designated representatives 
for such sources and units in the State (and Indian country within the 
borders of such State) for such control period, by which each common 
designated representative's share of such SO2 emissions 
exceeds the respective common designated representative's assurance 
level; and
    (B) The amount by which total SO2 emissions from all TR 
SO2 Group 1 units at TR SO2 Group 1 sources in 
the State (and Indian country within the borders of such State) for 
such control period exceed the State assurance level.
    (ii) The owners and operators shall hold the TR SO2 
Group 1 allowances required under paragraph (c)(2)(i) of this section, 
as of midnight of November 1 (if it is a business day), or midnight of 
the first business day thereafter (if November 1 is not a business 
day), immediately after such control period.
    (iii) Total SO2 emissions from all TR SO2 
Group 1 units at TR SO2 Group 1 sources in a State (and 
Indian country within the borders of such State) during a control 
period in a given year exceed the State assurance level if such total 
SO2 emissions exceed the sum, for such control period, of 
the State SO2 Group 1 trading budget under Sec.  97.610(a) 
and the State's variability limit under Sec.  97.610(b).
    (iv) It shall not be a violation of this subpart or of the Clean 
Air Act if total SO2 emissions from all TR SO2 
Group 1 units at TR SO2 Group 1 sources in a State (and 
Indian country within the borders of such State) during a control 
period exceed the State assurance level or if a common designated 
representative's share of total SO2 emissions from the TR 
SO2 Group 1 units at TR SO2 Group 1 sources in a 
State (and Indian country within the borders of such State) during a 
control period exceeds the common designated representative's assurance 
level.
    (v) To the extent the owners and operators fail to hold TR 
SO2 Group 1 allowances for a control period in a given year 
in accordance with paragraphs (c)(2)(i) through (iii) of this section,
    (A) The owners and operators shall pay any fine, penalty, or 
assessment or comply with any other remedy imposed under the Clean Air 
Act; and
    (B) Each TR SO2 Group 1 allowance that the owners and 
operators fail to hold for such control period in accordance with 
paragraphs (c)(2)(i) through (iii) of this section and each day of such 
control period shall constitute a separate violation of this subpart 
and the Clean Air Act.
    (3) Compliance periods. A TR SO2 Group 1 unit shall be 
subject to the requirements under paragraphs (c)(1) and (c)(2) of this 
section for the control period starting on the later of January 1, 2012 
or the deadline for meeting the unit's monitor certification 
requirements under Sec.  97.630(b) and for each control period 
thereafter.
    (4) Vintage of allowances held for compliance. (i) A TR 
SO2 Group 1 allowance held for compliance with the 
requirements under paragraph (c)(1)(i) of this section for a control 
period in a given year must be a TR SO2 Group 1 allowance 
that was allocated for such control period or a control period in a 
prior year.
    (ii) A TR SO2 Group 1 allowance held for compliance with 
the requirements under paragraphs (c)(1)(ii)(A) and (2)(i) through 
(iii) of this section for a control period in a given year must be a TR 
SO2 Group 1 allowance that was allocated for a control 
period in a prior year or the control period in the given year or in 
the immediately following year.
    (5) Allowance Management System requirements. Each TR 
SO2 Group 1 allowance shall be held in, deducted from, or 
transferred into, out of, or between Allowance Management

[[Page 48440]]

System accounts in accordance with this subpart.
    (6) Limited authorization. A TR SO2 Group 1 allowance is 
a limited authorization to emit one ton of SO2 during the 
control period in one year. Such authorization is limited in its use 
and duration as follows:
    (i) Such authorization shall only be used in accordance with the TR 
SO2 Group 1 Trading Program; and
    (ii) Notwithstanding any other provision of this subpart, the 
Administrator has the authority to terminate or limit the use and 
duration of such authorization to the extent the Administrator 
determines is necessary or appropriate to implement any provision of 
the Clean Air Act.
    (7) Property right. A TR SO2 Group 1 allowance does not 
constitute a property right.
    (d) Title V permit requirements. (1) No title V permit revision 
shall be required for any allocation, holding, deduction, or transfer 
of TR SO2 Group 1 allowances in accordance with this 
subpart.
    (2) A description of whether a unit is required to monitor and 
report SO2 emissions using a continuous emission monitoring 
system (under subpart H of part 75 of this chapter), an excepted 
monitoring system (under appendices D and E to part 75 of this 
chapter), a low mass emissions excepted monitoring methodology (under 
Sec.  75.19 of this chapter), or an alternative monitoring system 
(under subpart E of part 75 of this chapter) in accordance with 
Sec. Sec.  97.630 through 97.635 may be added to, or changed in, a 
title V permit using minor permit modification procedures in accordance 
with Sec. Sec.  70.7(e)(2) and 71.7(e)(1) of this chapter, provided 
that the requirements applicable to the described monitoring and 
reporting (as added or changed, respectively) are already incorporated 
in such permit. This paragraph explicitly provides that the addition 
of, or change to, a unit's description as described in the prior 
sentence is eligible for minor permit modification procedures in 
accordance with Sec. Sec.  70.7(e)(2)(i)(B) and 71.7(e)(1)(i)(B) of 
this chapter.
    (e) Additional recordkeeping and reporting requirements. (1) Unless 
otherwise provided, the owners and operators of each TR SO2 
Group 1 source and each TR SO2 Group 1 unit at the source 
shall keep on site at the source each of the following documents (in 
hardcopy or electronic format) 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 Administrator.
    (i) The certificate of representation under Sec.  97.616 for the 
designated representative for the source and each TR SO2 
Group 1 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 certificate of representation and 
documents are superseded because of the submission of a new certificate 
of representation under Sec.  97.616 changing the designated 
representative.
    (ii) All emissions monitoring information, in accordance with this 
subpart.
    (iii) Copies of all reports, compliance certifications, and other 
submissions and all records made or required under, or to demonstrate 
compliance with the requirements of, the TR SO2 Group 1 
Trading Program.
    (2) The designated representative of a TR SO2 Group 1 
source and each TR SO2 Group 1 unit at the source shall make 
all submissions required under the TR SO2 Group 1 Trading 
Program, except as provided in Sec.  97.618. This requirement does not 
change, create an exemption from, or or otherwise affect the 
responsible official submission requirements under a title V operating 
permit program in parts 70 and 71 of this chapter.
    (f) Liability. (1) Any provision of the TR SO2 Group 1 
Trading Program that applies to a TR SO2 Group 1 source or 
the designated representative of a TR SO2 Group 1 source 
shall also apply to the owners and operators of such source and of the 
TR SO2 Group 1 units at the source.
    (2) Any provision of the TR SO2 Group 1 Trading Program 
that applies to a TR SO2 Group 1 unit or the designated 
representative of a TR SO2 Group 1 unit shall also apply to 
the owners and operators of such unit.
    (g) Effect on other authorities. No provision of the TR 
SO2 Group 1 Trading Program or exemption under Sec.  97.605 
shall be construed as exempting or excluding the owners and operators, 
and the designated representative, of a TR SO2 Group 1 
source or TR SO2 Group 1 unit from compliance with any other 
provision of the applicable, approved State implementation plan, a 
federally enforceable permit, or the Clean Air Act.

Sec.  97.607  Computation of time.

    (a) Unless otherwise stated, any time period scheduled, under the 
TR SO2 Group 1 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 
TR SO2 Group 1 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 TR SO2 Group 1 Trading Program, is not a business 
day, the time period shall be extended to the next business day.

Sec.  97.608  Administrative appeal procedures.

    The administrative appeal procedures for decisions of the 
Administrator under the TR SO2 Group 1 Trading Program are 
set forth in part 78 of this chapter.

Sec.  97.609  [Reserved]

Sec.  97.610  State SO2 Group 1 trading budgets, new unit set-asides, 
Indian country new unit set-aside, and variability limits.

    (a) The State SO2 Group 1 trading budgets, new unit set-
asides, and Indian country new unit set-asides for allocations of TR 
SO2 Group 1 allowances for the control periods in 2012 and 
thereafter are as follows:

----------------------------------------------------------------------------------------------------------------
                                                          SO2 Group 1                         Indian country new
                                                        trading budget    New unit set-aside    unit set-aside
                        State                          (tons) * for 2012    (tons) for 2012     (tons) for 2012
                                                           and 2013            and 2013            and 2013
----------------------------------------------------------------------------------------------------------------
Illinois............................................             234,889              11,744  ..................
Indiana.............................................             285,424               8,563  ..................
Iowa................................................             107,085               2,035                 107
Kentucky............................................             232,662              13,960  ..................
Maryland............................................              30,120                 602  ..................
Michigan............................................             229,303               4,357                 229
Missouri............................................             207,466               4,149  ..................
New Jersey..........................................               5,574                 111  ..................

[[Page 48441]]

 
New York............................................              27,325                 520                  27
North Carolina......................................             136,881              10,813                 137
Ohio................................................             310,230               6,205  ..................
Pennsylvania........................................             278,651               5,573  ..................
Tennessee...........................................             148,150               2,963  ..................
Virginia............................................              70,820               2,833  ..................
West Virginia.......................................             146,174              10,232  ..................
Wisconsin...........................................              79,480               3,894                  80
----------------------------------------------------------------------------------------------------------------

----------------------------------------------------------------------------------------------------------------
                                                          SO2 Group 1                         Indian country new
                                                        trading budget    New unit set-aside    unit set-aside
                        State                          (tons) * for 2014    (tons) for 2014     (tons) for 2014
                                                        and thereafter      and thereafter      and thereafter
----------------------------------------------------------------------------------------------------------------
Illinois............................................             124,123               6,206  ..................
Indiana.............................................             161,111               4,833  ..................
Iowa................................................              75,184               1,429                  75
Kentucky............................................             106,284               6,377  ..................
Maryland............................................              28,203                 564  ..................
Michigan............................................             143,995               2,736                 144
Missouri............................................             165,941               3,319  ..................
New Jersey..........................................               5,574                 111  ..................
New York............................................              18,585                 353                  19
North Carolina......................................              57,620               4,552                  58
Ohio................................................             137,077               2,742  ..................
Pennsylvania........................................             112,021               2,240  ..................
Tennessee...........................................              58,833               1,177  ..................
Virginia............................................              35,057               1,402  ..................
West Virginia.......................................              75,668               5,297  ..................
Wisconsin...........................................              40,126               1,966                  40
----------------------------------------------------------------------------------------------------------------
* Each trading budget includes the new unit set-aside and, where applicable, the Indian country new unit set-
  aside and does not include the variability limit.

    (b) The States' variability limits for the State SO2 
Group 1 trading budgets for the control periods in 2012 and thereafter 
are as follows:

------------------------------------------------------------------------
                                                      Variability limits
              State               Variability limits     for 2014 and
                                   for 2012 and 2013      thereafter
------------------------------------------------------------------------
Illinois........................              42,280              22,342
Indiana.........................              51,376              29,000
Iowa............................              19,275              13,533
Kentucky........................              41,879              19,131
Maryland........................               5,422               5,077
Michigan........................              41,275              25,919
Missouri........................              37,344              29,869
New Jersey......................               1,003               1,003
New York........................               4,919               3,345
North Carolina..................              24,639              10,372
Ohio............................              55,841              24,674
Pennsylvania....................              50,157              20,164
Tennessee.......................              26,667              10,590
Virginia........................              12,748               6,310
West Virginia...................              26,311              13,620
Wisconsin.......................              14,306               7,223
------------------------------------------------------------------------

Sec.  97.611  Timing requirements for TR SO2 Group 1 allowance 
allocations.

    (a) Existing units. (1) TR SO2 Group 1 allowances are 
allocated, for the control periods in 2012 and each year thereafter, as 
provided in a notice of data availability issued by the Administrator. 
Providing an allocation to a unit in such notice does not constitute a 
determination that the unit is a TR SO2 Group 1 unit, and 
not providing an allocation to a unit in such notice does not 
constitute a determination that the unit is not a TR SO2 
Group 1 unit.
    (2) Notwithstanding paragraph (a)(1) of this section, if a unit 
provided an allocation in the notice of data availability issued under 
paragraph (a)(1) of this section does not operate, starting after 2011, 
during the control period in two consecutive years, such unit will not 
be allocated the TR SO2 Group 1 allowances provided in such 
notice for the unit for the control periods in the fifth year after the 
first such year and in each year after that fifth year. All TR 
SO2 Group 1 allowances that would otherwise have been 
allocated to such unit will be

[[Page 48442]]

allocated to the new unit set-aside for the State where such unit is 
located and for the respective years involved. If such unit resumes 
operation, the Administrator will allocate TR SO2 Group 1 
allowances to the unit in accordance with paragraph (b) of this 
section.
    (b) New units. (1) New unit set-asides. (i) By June 1, 2012 and 
June 1 of each year thereafter, the Administrator will calculate the TR 
SO2 Group 1 allowance allocation to each TR SO2 
Group 1 unit in a State, in accordance with Sec.  97.612(a)(2) through 
(7) and (12), for the control period in the year of the applicable 
calculation deadline under this paragraph and will promulgate a notice 
of data availability of the results of the calculations.
    (ii) For each notice of data availability required in paragraph 
(b)(1)(i) of this section, the Administrator will provide an 
opportunity for submission of objections to the calculations referenced 
in such notice.
    (A) Objections shall be submitted by the deadline specified in each 
notice of data availability required in paragraph (b)(1)(i) of this 
section and shall be limited to addressing whether the calculations 
(including the identification of the TR SO2 Group 1 units) 
are in accordance with Sec.  97.612(a)(2) through (7) and (12) and 
Sec. Sec.  97.606(b)(2) and 97.630 through 97.635.
    (B) The Administrator will adjust the calculations to the extent 
necessary to ensure that they are in accordance with the provisions 
referenced in paragraph (b)(1)(ii)(A) of this section. By August 1 
immediately after the promulgation of each notice of data availability 
required in paragraph (b)(1)(i) of this section, the Administrator will 
promulgate a notice of data availability of any adjustments that the 
Administrator determines to be necessary with regard to allocations 
under Sec.  97.612(a)(2) through (7) and (12) and the reasons for 
accepting or rejecting any objections submitted in accordance with 
paragraph (b)(1)(ii)(A) of this section.
    (iii) If the new unit set-aside for such control period contains 
any TR SO2 Group 1 allowances that have not been allocated 
in the applicable notice of data availability required in paragraph 
(b)(1)(ii) of this section, the Administrator will promulgate, by 
December 15 immediately after such notice, a notice of data 
availability that identifies any TR SO2 Group 1 units that 
commenced commercial operation during the period starting January 1 of 
the year before the year of such control period and ending November 30 
of year of such control period.
    (iv) For each notice of data availability required in paragraph 
(b)(1)(iii) of this section, the Administrator will provide an 
opportunity for submission of objections to the identification of TR 
SO2 annual units in such notice.
    (A) Objections shall be submitted by the deadline specified in each 
notice of data availability required in paragraph (b)(1)(iii) of this 
section and shall be limited to addressing whether the identification 
of TR SO2 annual units in such notice is in accordance with 
paragraph (b)(1)(iii) of this section.
    (B) The Administrator will adjust the identification of TR 
SO2 Group 1 units in each notice of data availability 
required in paragraph (b)(1)(iii) of this section to the extent 
necessary to ensure that it is in accordance with paragraph (b)(1)(iii) 
of this section and will calculate the TR SO2 Group 1 
allowance allocation to each TR SO2 Group 1 unit in 
accordance with Sec.  97.612(a)(9), (10), and (12) and Sec. Sec.  
97.606(b)(2) and 97.630 through 97.635. By February 15 immediately 
after the promulgation of each notice of data availability required in 
paragraph (b)(1)(iii) of this section, the Administrator will 
promulgate a notice of data availability of any adjustments of the 
identification of TR SO2 Group 1 units that the 
Administrator determines to be necessary, the reasons for accepting or 
rejecting any objections submitted in accordance with paragraph 
(b)(1)(iv)(A) of this section, and the results of such calculations.
    (v) To the extent any TR SO2 Group 1 allowances are 
added to the new unit set-aside after promulgation of each notice of 
data availability required in paragraph (b)(1)(iv) of this section, the 
Administrator will promulgate additional notices of data availability, 
as deemed appropriate, of the allocation of such TR SO2 
Group 1 allowances in accordance with Sec.  97.612(a)(10).
    (2) Indian country new unit set-asides. (i) By June 1, 2012 and 
June 1 of each year thereafter, the Administrator will calculate the TR 
SO2 Group 1 allowance allocation to each TR SO2 
Group 1 unit in Indian country within the borders of a State, in 
accordance with Sec.  97.612(b)(2) through (7) and (12), for the 
control period in the year of the applicable calculation deadline under 
this paragraph and will promulgate a notice of data availability of the 
results of the calculations.
    (ii) For each notice of data availability required in paragraph 
(b)(2)(i) of this section, the Administrator will provide an 
opportunity for submission of objections to the calculations referenced 
in such notice.
    (A) Objections shall be submitted by the deadline specified in each 
notice of data availability required in paragraph (b)(2)(i) of this 
section and shall be limited to addressing whether the calculations 
(including the identification of the TR SO2 Group 1 units) 
are in accordance with Sec.  97.612(b)(2) through (7) and (12) and 
Sec. Sec.  97.606(b)(2) and 97.630 through 97.635.
    (B) The Administrator will adjust the calculations to the extent 
necessary to ensure that they are in accordance with the provisions 
referenced in paragraph (b)(2)(ii)(A) of this section. By August 1 
immediately after the promulgation of each notice of data availability 
required in paragraph (b)(2)(i) of this section, the Administrator will 
promulgate a notice of data availability of any adjustments that the 
Administrator determines to be necessary with regard to allocations 
under Sec.  97.612(b)(2) through (7) and (12) and the reasons for 
accepting or rejecting any objections submitted in accordance with 
paragraph (b)(2)(ii)(A) of this section.
    (iii) If the Indian country new unit set-aside for such control 
period contains any TR SO2 Group 1 allowances that have not 
been allocated in the applicable notice of data availability required 
in paragraph (b)(2)(ii) of this section, the Administrator will 
promulgate, by December 15 immediately after such notice, a notice of 
data availability that identifies any TR SO2 Group 1 units 
that commenced commercial operation during the period starting January 
1 of the year before the year of such control period and ending 
November 30 of year of such control period.
    (iv) For each notice of data availability required in paragraph 
(b)(2)(iii) of this section, the Administrator will provide an 
opportunity for submission of objections to the identification of TR 
SO2 annual units in such notice.
    (A) Objections shall be submitted by the deadline specified in each 
notice of data availability required in paragraph (b)(2)(iii) of this 
section and shall be limited to addressing whether the identification 
of TR SO2 annual units in such notice is in accordance with 
paragraph (b)(2)(iii) of this section.
    (B) The Administrator will adjust the identification of TR 
SO2 Group 1 units in each notice of data availability 
required in paragraph (b)(2)(iii) of this section to the extent 
necessary to ensure that it is in accordance with paragraph (b)(2)(iii) 
of this section and will calculate the TR SO2 Group 1 
allowance allocation to each TR SO2 Group 1 unit in 
accordance with Sec.  97.612(b)(9), (10),

[[Page 48443]]

and (12) and Sec. Sec.  97.606(b)(2) and 97.630 through 97.635. By 
February 15 immediately after the promulgation of each notice of data 
availability required in paragraph (b)(2)(iii) of this section, the 
Administrator will promulgate a notice of data availability of any 
adjustments of the identification of TR SO2 Group 1 units 
that the Administrator determines to be necessary, the reasons for 
accepting or rejecting any objections submitted in accordance with 
paragraph (b)(2)(iv)(A) of this section, and the results of such 
calculations.
    (v) To the extent any TR SO2 Group 1 allowances are 
added to the Indian country new unit set-aside after promulgation of 
each notice of data availability required in paragraph (b)(2)(iv) of 
this section, the Administrator will promulgate additional notices of 
data availability, as deemed appropriate, of the allocation of such TR 
NOX Annual allowances in accordance with Sec.  
97.612(b)(10).
    (c) Units incorrectly allocated TR SO2 Group 1 
allowances. (1) For each control period in 2012 and thereafter, if the 
Administrator determines that TR SO2 Group 1 allowances were 
allocated under paragraph (a) of this section, or under a provision of 
a SIP revision approved under Sec.  52.39(d), (e), or (f) of this 
chapter, where such control period and the recipient are covered by the 
provisions of paragraph (c)(1)(i) of this section or were allocated 
under Sec.  97.612(a)(2) through (7), (9), and (12) and (b)(2) through 
(7), (9), and (12), or under a provision of a SIP revision approved 
under Sec.  52.39(e) or (f) of this chapter, where such control period 
and the recipient are covered by the provisions of paragraph (c)(1)(ii) 
of this section, then the Administrator will notify the designated 
representative of the recipient and will act in accordance with the 
procedures set forth in paragraphs (c)(2) through (5) of this section:
    (i)(A) The recipient is not actually a TR SO2 Group 1 
unit under Sec.  97.604 as of January 1, 2012 and is allocated TR 
SO2 Group 1 allowances for such control period or, in the 
case of an allocation under a provision of a SIP revision approved 
under Sec.  52.39(d), (e), or (f) of this chapter, the recipient is not 
actually a TR SO2 Group 1 unit as of January 1, 2012 and is 
allocated TR SO2 Group 1 allowances for such control period 
that the SIP revision provides should be allocated only to recipients 
that are TR SO2 Group 1 units as of January 1, 2012; or
    (B) The recipient is not located as of January 1 of the control 
period in the State from whose SO2 Group 1 trading budget 
the TR SO2 Group 1 allowances allocated under paragraph (a) 
of this section, or under a provision of a SIP revision approved under 
Sec.  52.39(d), (e), or (f) of this chapter, were allocated for such 
control period.
    (ii) The recipient is not actually a TR SO2 Group 1 unit 
under Sec.  97.604 as of January 1 of such control period and is 
allocated TR SO2 Group 1 allowances for such control period 
or, in the case of an allocation under a provision of a SIP revision 
approved under Sec.  52.39(d), (e), or (f) of this chapter, the 
recipient is not actually a TR SO2 Group 1 unit as of 
January 1 of such control period and is allocated TR SO2 
Group 1 allowances for such control period that the SIP revision 
provides should be allocated only to recipients that are TR 
SO2 Group 1 units as of January 1 of such control period.
    (2) Except as provided in paragraph (c)(3) or (4) of this section, 
the Administrator will not record such TR SO2 Group 1 
allowances under Sec.  97.621.
    (3) If the Administrator already recorded such TR SO2 
Group 1 allowances under Sec.  97.621 and if the Administrator makes 
the determination under paragraph (c)(1) of this section before making 
deductions for the source that includes such recipient under Sec.  
97.624(b) for such control period, then the Administrator will deduct 
from the account in which such TR SO2 Group 1 allowances 
were recorded an amount of TR SO2 Group 1 allowances 
allocated for the same or a prior control period equal to the amount of 
such already recorded TR SO2 Group 1 allowances. The 
authorized account representative shall ensure that there are 
sufficient TR SO2 Group 1 allowances in such account for 
completion of the deduction.
    (4) If the Administrator already recorded such TR SO2 
Group 1 allowances under Sec.  97.621 and if the Administrator makes 
the determination under paragraph (c)(1) of this section after making 
deductions for the source that includes such recipient under Sec.  
97.624(b) for such control period, then the Administrator will not make 
any deduction to take account of such already recorded TR 
SO2 Group 1 allowances.
    (5)(i) With regard to the TR SO2 Group 1 allowances that 
are not recorded, or that are deducted as an incorrect allocation, in 
accordance with paragraphs (c)(2) and (3) of this section for a 
recipient under paragraph (c)(1)(i) of this section, the Administrator 
will:
    (A) Transfer such TR SO2 Group 1 allowances to the new 
unit set-aside for such control period for the State from whose 
SO2 Group 1 trading budget the TR SO2 Group 1 
allowances were allocated; or
    (B) If the State has a SIP revision approved under Sec.  52.39(e) 
or (f) covering such control period, include such TR SO2 
Group 1 allowances in the portion of the State SO2 Group 1 
trading budget that may be allocated for such control period in 
accordance with such SIP revision.
    (ii) With regard to the TR SO2 Group 1 allowances that 
were not allocated from the Indian country new unit set-aside for such 
control period and that are not recorded, or that are deducted as an 
incorrect allocation, in accordance with paragraphs (c)(2) and (3) of 
this section for a recipient under paragraph (c)(1)(ii) of this 
paragraph, the Administrator will:
    (A) Transfer such TR SO2 Group 1 allowances to the new 
unit set-aside for such control period; or
    (B) If the State has a SIP revision approved under Sec.  52.39(e) 
or (f) covering such control period, include such TR SO2 
Group 1 allowances in the portion of the State SO2 Group 1 
trading budget that may be allocated for such control period in 
accordance with such SIP revision.
    (iii) With regard to the TR SO2 Group 1 allowances that 
were allocated from the Indian country new unit set-aside for such 
control period and that are not recorded, or that are deducted as an 
incorrect allocation, in accordance with paragraphs (c)(2) and (3) of 
this section for a recipient under paragraph (c)(1)(ii) of this 
paragraph, the Administrator will transfer such TR SO2 Group 
1 allowances to the Indian country new unit set-aside for such control 
period.

Sec.  97.612  TR SO2 Group 1 allowance allocations to new units.

    (a) For each control period in 2012 and thereafter and for the TR 
SO2 Group 1 units in each State, the Administrator will 
allocate TR SO2 Group 1 allowances to the TR SO2 
Group 1 units as follows:
    (1) The TR SO2 Group 1 allowances will be allocated to 
the following TR SO2 Group 1 units, except as provided in 
paragraph (a)(10) of this section:
    (i) TR SO2 Group 1 units that are not allocated an 
amount of TR SO2 Group 1 allowances in the notice of data 
availability issued under Sec.  97.611(a)(1);
    (ii) TR SO2 Group 1 units whose allocation of an amount 
of TR SO2 Group 1 allowances for such control period in the 
notice of data availability issued under Sec.  97.611(a)(1) is covered 
by Sec.  97.611(c)(2) or (3);
    (iii) TR SO2 Group 1 units that are allocated an amount 
of TR SO2 Group 1 allowances for such control period in

[[Page 48444]]

the notice of data availability issued under Sec.  97.611(a)(1), which 
allocation is terminated for such control period pursuant to Sec.  
97.611(a)(2), and that operate during the control period immediately 
preceding such control period; or
    (iv) For purposes of paragraph (a)(9) of this section, TR 
SO2 Group 1 units under Sec.  97.611(c)(1)(ii) whose 
allocation of an amount of TR SO2 Group 1 allowances for 
such control period in the notice of data availability issued under 
Sec.  97.611(b)(1)(ii)(B) is covered by Sec.  97.611(c)(2) or (3).
    (2) The Administrator will establish a separate new unit set-aside 
for the State for each such control period. Each such new unit set-
aside will be allocated TR SO2 Group 1 allowances in an 
amount equal to the applicable amount of tons of SO2 
emissions as set forth in Sec.  97.610(a) and will be allocated 
additional TR SO2 Group 1 allowances (if any) in accordance 
with Sec. Sec.  97.611(a)(2) and (c)(5) and paragraph (b)(10) of this 
section.
    (3) The Administrator will determine, for each TR SO2 
Group 1 unit described in paragraph (a)(1) of this section, an 
allocation of TR SO2 Group 1 allowances for the later of the 
following control periods and for each subsequent control period:
    (i) The control period in 2012;
    (ii) The first control period after the control period in which the 
TR SO2 Group 1 unit commences commercial operation;
    (iii) For a unit described in paragraph (a)(1)(ii) of this section, 
the first control period in which the TR SO2 Group 1 unit 
operates in the State after operating in another jurisdiction and for 
which the unit is not already allocated one or more TR SO2 
Group 1 allowances; and
    (iv) For a unit described in paragraph (a)(1)(iii) of this section, 
the first control period after the control period in which the unit 
resumes operation.
    (4)(i) The allocation to each TR SO2 annual unit 
described in paragraph (a)(1)(i) through (iii) of this section and for 
each control period described in paragraph (a)(3) of this section will 
be an amount equal to the unit's total tons of SO2 emissions 
during the immediately preceding control period.
    (ii) The Administrator will adjust the allocation amount in 
paragraph (a)(4)(i) in accordance with paragraphs (a)(5) through (7) 
and (12) of this section.
    (5) The Administrator will calculate the sum of the TR 
SO2 Group 1 allowances determined for all such TR 
SO2 Group 1 units under paragraph (a)(4)(i) of this section 
in the State for such control period.
    (6) If the amount of TR SO2 Group 1 allowances in the 
new unit set-aside for the State for such control period is greater 
than or equal to the sum under paragraph (a)(5) of this section, then 
the Administrator will allocate the amount of TR SO2 Group 1 
allowances determined for each such TR SO2 Group 1 unit 
under paragraph (a)(4)(i) of this section.
    (7) If the amount of TR SO2 Group 1 allowances in the 
new unit set-aside for the State for such control period is less than 
the sum under paragraph (a)(5) of this section, then the Administrator 
will allocate to each such TR SO2 Group 1 unit the amount of 
the TR SO2 Group 1 allowances determined under paragraph 
(a)(4)(i) of this section for the unit, multiplied by the amount of TR 
SO2 Group 1 allowances in the new unit set-aside for such 
control period, divided by the sum under paragraph (a)(5) of this 
section, and rounded to the nearest allowance.
    (8) The Administrator will notify the public, through the 
promulgation of the notices of data availability described in Sec.  
97.611(b)(1)(i) and (ii), of the amount of TR SO2 Group 1 
allowances allocated under paragraphs (a)(2) through (7) and (12) of 
this section for such control period to each TR SO2 Group 1 
unit eligible for such allocation.
    (9) If, after completion of the procedures under paragraphs (a)(5) 
through (8) of this section for such control period, any unallocated TR 
SO2 Group 1 allowances remain in the new unit set-aside for 
the State for such control period, the Administrator will allocate such 
TR SO2 Group 1 allowances as follows--
    (i) The Administrator will determine, for each unit described in 
paragraph (a)(1) of this section that commenced commercial operation 
during the period starting January 1 of the year before the year of 
such control period and ending November 30 of year of such control 
period, the positive difference (if any) between the unit's emissions 
during such control period and the amount of TR SO2 Group 1 
allowances referenced in the notice of data availability required under 
Sec.  97.611(b)(1)(ii) for the unit for such control period;
    (ii) The Administrator will determine the sum of the positive 
differences determined under paragraph (a)(9)(i) of this section;
    (iii) If the amount of unallocated TR SO2 Group 1 
allowances remaining in the new unit set-aside for the State for such 
control period is greater than or equal to the sum determined under 
paragraph (a)(9)(ii) of this section, then the Administrator will 
allocate the amount of TR SO2 Group 1 allowances determined 
for each such TR SO2 Group 1 unit under paragraph (a)(9)(i) 
of this section; and
    (iv) If the amount of unallocated TR SO2 Group 1 
allowances remaining in the new unit set-aside for the State for such 
control period is less than the sum under paragraph (a)(9)(ii) of this 
section, then the Administrator will allocate to each such TR 
SO2 Group 1 unit the amount of the TR SO2 Group 1 
allowances determined under paragraph (a)(9)(i) of this section for the 
unit, multiplied by the amount of unallocated TR SO2 Group 1 
allowances remaining in the new unit set-aside for such control period, 
divided by the sum under paragraph (a)(9)(ii) of this section, and 
rounded to the nearest allowance.
    (10) If, after completion of the procedures under paragraphs (a)(9) 
and (12) of this section for such control period, any unallocated TR 
SO2 Group 1 allowances remain in the new unit set-aside for 
the State for such control period, the Administrator will allocate to 
each TR SO2 Group 1 unit that is in the State, is allocated 
an amount of TR SO2 Group 1 allowances in the notice of data 
availability issued under Sec.  97.611(a)(1), and continues to be 
allocated TR SO2 Group 1 allowances for such control period 
in accordance with Sec.  97.611(a)(2), an amount of TR SO2 
Group 1 allowances equal to the following: The total amount of such 
remaining unallocated TR SO2 Group 1 allowances in such new 
unit set-aside, multiplied by the unit's allocation under Sec.  
97.611(a) for such control period, divided by the remainder of the 
amount of tons in the applicable State SO2 Group 1 trading 
budget minus the sum of the amounts of tons in such new unit set-aside 
and the Indian country new unit set-aside for the State for such 
control period, and rounded to the nearest allowance.
    (11) The Administrator will notify the public, through the 
promulgation of the notices of data availability described in Sec.  
97.611(b)(1)(iii), (iv), and (v), of the amount of TR SO2 
Group 1 allowances allocated under paragraphs (a)(9), (10), and (12) of 
this section for such control period to each TR SO2 Group 1 
unit eligible for such allocation.
    (12)(i) Notwithstanding the requirements of paragraphs (a)(2) 
through (11) of this section, if the calculations of allocations of a 
new unit set-aside for a control period in a given year under paragraph 
(a)(7) of this section, paragraphs (a)(6) and (9)(iv) of this section, 
or paragraphs (a)(6), (9)(iii), and (10) of this section would 
otherwise result in total allocations of such new unit set-aside 
exceeding the total amount of such new unit set-aside, then

[[Page 48445]]

the Administrator will adjust the results of the calculations under 
paragraph (a)(7), (9)(iv), or (10) of this section, as applicable, as 
follows. The Administrator will list the TR SO2 Group 1 
units in descending order based on the amount of such units' 
allocations under paragraph (a)(7), (9)(iv), or (10) of this section, 
as applicable, and, in cases of equal allocation amounts, in 
alphabetical order of the relevant source's name and numerical order of 
the relevant unit's identification number, and will reduce each unit's 
allocation under paragraph (a)(7), (9)(iv), or (10) of this section, as 
applicable, by one TR SO2 Group 1 allowance (but not below 
zero) in the order in which the units are listed and will repeat this 
reduction process as necessary, until the total allocations of such new 
unit set-aside equal the total amount of such new unit set-aside.
    (ii) Notwithstanding the requirements of paragraphs (a)(10) and 
(11) of this section, if the calculations of allocations of a new unit 
set-aside for a control period in a given year under paragraphs (a)(6), 
(9)(iii), and (10) of this section would otherwise result in a total 
allocations of such new unit set-aside less than the total amount of 
such new unit set-aside, then the Administrator will adjust the results 
of the calculations under paragraph (a)(10) of this section, as 
follows. The Administrator will list the TR SO2 Group 1 
units in descending order based on the amount of such units' 
allocations under paragraph (a)(10) of this section and, in cases of 
equal allocation amounts, in alphabetical order of the relevant 
source's name and numerical order of the relevant unit's identification 
number, and will increase each unit's allocation under paragraph 
(a)(10) of this section by one TR SO2 Group 1 allowance in 
the order in which the units are listed and will repeat this increase 
process as necessary, until the total allocations of such new unit set-
aside equal the total amount of such new unit set-aside.
    (b) For each control period in 2012 and thereafter and for the TR 
SO2 Group 1 units located in Indian country within the 
borders of each State, the Administrator will allocate TR 
SO2 Group 1 allowances to the TR SO2 Group 1 
units as follows:
    (1) The TR SO2 Group 1 allowances will be allocated to 
the following TR SO2 Group 1 units, except as provided in 
paragraph (b)(10) of this section:
    (i) TR SO2 Group 1 units that are not allocated an 
amount of TR SO2 Group 1 allowances in the notice of data 
availability issued under Sec.  97.611(a)(1); or
    (ii) For purposes of paragraph (b)(9) of this section, TR 
SO2 Group 1 units under Sec.  97.611(c)(1)(ii) whose 
allocation of an amount of TR SO2 Group 1 allowances for 
such control period in the notice of data availability issued under 
Sec.  97.611(b)(2)(ii)(B) is covered by Sec.  97.611(c)(2) or (3).
    (2) The Administrator will establish a separate Indian country new 
unit set-aside for the State for each such control period. Each such 
Indian country new unit set-aside will be allocated TR SO2 
Group 1 allowances in an amount equal to the applicable amount of tons 
of SO2 emissions as set forth in Sec.  97.610(a) and will be 
allocated additional TR SO2 Group 1 allowances (if any) in 
accordance with Sec.  97.611(c)(5).
    (3) The Administrator will determine, for each TR SO2 
Group 1 unit described in paragraph (b)(1) of this section, an 
allocation of TR SO2 Group 1 allowances for the later of the 
following control periods and for each subsequent control period:
    (i) The control period in 2012; and
    (ii) The first control period after the control period in which the 
TR SO2 Group 1 unit commences commercial operation.
    (4)(i) The allocation to each TR SO2 annual unit 
described in paragraph (b)(1)(i) of this section and for each control 
period described in paragraph (b)(3) of this section will be an amount 
equal to the unit's total tons of SO2 emissions during the 
immediately preceding control period.
    (ii) The Administrator will adjust the allocation amount in 
paragraph (b)(4)(i) in accordance with paragraphs (b)(5) through (7) 
and (12) of this section.
    (5) The Administrator will calculate the sum of the TR 
SO2 Group 1 allowances determined for all such TR 
SO2 Group 1 units under paragraph (b)(4)(i) of this section 
in Indian country within the borders of the State for such control 
period.
    (6) If the amount of TR SO2 Group 1 allowances in the 
Indian country new unit set-aside for the State for such control period 
is greater than or equal to the sum under paragraph (b)(5) of this 
section, then the Administrator will allocate the amount of TR 
SO2 Group 1 allowances determined for each such TR 
SO2 Group 1 unit under paragraph (b)(4)(i) of this section.
    (7) If the amount of TR SO2 Group 1 allowances in the 
Indian country new unit set-aside for the State for such control period 
is less than the sum under paragraph (b)(5) of this section, then the 
Administrator will allocate to each such TR SO2 Group 1 unit 
the amount of the TR SO2 Group 1 allowances determined under 
paragraph (b)(4)(i) of this section for the unit, multiplied by the 
amount of TR SO2 Group 1 allowances in the Indian country 
new unit set-aside for such control period, divided by the sum under 
paragraph (b)(5) of this section, and rounded to the nearest allowance.
    (8) The Administrator will notify the public, through the 
promulgation of the notices of data availability described in Sec.  
97.611(b)(2)(i) and (ii), of the amount of TR SO2 Group 1 
allowances allocated under paragraphs (b)(2) through (7) and (12) of 
this section for such control period to each TR SO2 Group 1 
unit eligible for such allocation.
    (9) If, after completion of the procedures under paragraphs (b)(5) 
through (8) of this section for such control period, any unallocated TR 
SO2 Group 1 allowances remain in the Indian country new unit 
set-aside for the State for such control period, the Administrator will 
allocate such TR SO2 Group 1 allowances as follows--
    (i) The Administrator will determine, for each unit described in 
paragraph (b)(1) of this section that commenced commercial operation 
during the period starting January 1 of the year before the year of 
such control period and ending November 30 of year of such control 
period, the positive difference (if any) between the unit's emissions 
during such control period and the amount of TR SO2 Group 1 
allowances referenced in the notice of data availability required under 
Sec.  97.611(b)(2)(ii) for the unit for such control period;
    (ii) The Administrator will determine the sum of the positive 
differences determined under paragraph (b)(9)(i) of this section;
    (iii) If the amount of unallocated TR SO2 Group 1 
allowances remaining in the Indian country new unit set-aside for the 
State for such control period is greater than or equal to the sum 
determined under paragraph (b)(9)(ii) of this section, then the 
Administrator will allocate the amount of TR SO2 Group 1 
allowances determined for each such TR SO2 Group 1 unit 
under paragraph (b)(9)(i) of this section; and
    (iv) If the amount of unallocated TR SO2 Group 1 
allowances remaining in the Indian country new unit set-aside for the 
State for such control period is less than the sum under paragraph 
(b)(9)(ii) of this section, then the Administrator will allocate to 
each such TR SO2 Group 1 unit the amount of the TR 
SO2 Group 1 allowances determined under paragraph (b)(9)(i) 
of this section for the unit, multiplied by the amount of unallocated 
TR SO2 Group 1 allowances remaining in the Indian country 
new unit set-aside for such control period, divided by the sum

[[Page 48446]]

under paragraph (b)(9)(ii) of this section, and rounded to the nearest 
allowance.
    (10) If, after completion of the procedures under paragraphs (b)(9) 
and (12) of this section for such control period, any unallocated TR 
SO2 Group 1 allowances remain in the Indian country new unit 
set-aside for the State for such control period, the Administrator 
will:
    (i) Transfer such unallocated TR SO2 Group 1 allowances 
to the new unit set-aside for the State for such control period; or
    (ii) If the State has a SIP revision approved under Sec.  52.39(d), 
(e), or (f) of this chapter covering such control period, include such 
unallocated TR SO2 Group 1 allowances in the portion of the 
State SO2 Group 1 trading budget that may be allocated for 
such control period in accordance with such SIP revision.
    (11) The Administrator will notify the public, through the 
promulgation of the notices of data availability described in Sec.  
97.611(b)(2)(iii), (iv), and (v), of the amount of TR SO2 
Group 1 allowances allocated under paragraphs (b)(9), (10), and (12) 
for such control period to each TR SO2 Group 1 unit eligible 
for such allocation.
    (12)(i) Notwithstanding the requirements of paragraphs (b)(2) 
through (11) of this section, if the calculations of allocations of an 
Indian country new unit set-aside for a control period in a given year 
under paragraph (b)(7) of this section, paragraphs (b)(6) and (9)(iv) 
of this section, or paragraphs (b)(6), (9)(iii), and (10) of this 
section would otherwise result in total allocations of such Indian 
country new unit set-aside exceeding the total amount of such Indian 
country new unit set-aside, then the Administrator will adjust the 
results of the calculations under paragraph (b)(7), (9)(iv), or (10) of 
this section, as applicable, as follows. The Administrator will list 
the TR SO2 Group 1 units in descending order based on the 
amount of such units' allocations under paragraph (b)(7), (9)(iv), or 
(10) of this section, as applicable, and, in cases of equal allocation 
amounts, in alphabetical order of the relevant source's name and 
numerical order of the relevant unit's identification number, and will 
reduce each unit's allocation under paragraph (b)(7), (9)(iv), or (10) 
of this section, as applicable, by one TR SO2 Group 1 
allowance (but not below zero) in the order in which the units are 
listed and will repeat this reduction process as necessary, until the 
total allocations of such Indian country new unit set-aside equal the 
total amount of such Indian country new unit set-aside.
    (ii) Notwithstanding the requirements of paragraphs (b)(10) and 
(11) of this section, if the calculations of allocations of an Indian 
country new unit set-aside for a control period in a given year under 
paragraphs (b)(6), (9)(iii), and (10) of this section would otherwise 
result in a total allocations of such Indian country new unit set-aside 
less than the total amount of such Indian country new unit set-aside, 
then the Administrator will adjust the results of the calculations 
under paragraph (b)(10) of this section, as follows. The Administrator 
will list the TR SO2 Group 1 units in descending order based 
on the amount of such units' allocations under paragraph (b)(10) of 
this section and, in cases of equal allocation amounts, in alphabetical 
order of the relevant source's name and numerical order of the relevant 
unit's identification number, and will increase each unit's allocation 
under paragraph (b)(10) of this section by one TR SO2 Group 
1 allowance in the order in which the units are listed and will repeat 
this increase process as necessary, until the total allocations of such 
Indian country new unit set-aside equal the total amount of such Indian 
country new unit set-aside.

Sec.  97.613  Authorization of designated representative and alternate 
designated representative.

    (a) Except as provided under Sec.  97.615, each TR SO2 
Group 1 source, including all TR SO2 Group 1 units at the 
source, shall have one and only one designated representative, with 
regard to all matters under the TR SO2 Group 1 Trading 
Program.
    (1) The designated representative shall be selected by an agreement 
binding on the owners and operators of the source and all TR 
SO2 Group 1 units at the source and shall act in accordance 
with the certification statement in Sec.  97.616(a)(4)(iii).
    (2) Upon and after receipt by the Administrator of a complete 
certificate of representation under Sec.  97.616:
    (i) The designated representative shall be authorized and shall 
represent and, by his or her representations, actions, inactions, or 
submissions, legally bind each owner and operator of the source and 
each TR SO2 Group 1 unit at the source in all matters 
pertaining to the TR SO2 Group 1 Trading Program, 
notwithstanding any agreement between the designated representative and 
such owners and operators; and
    (ii) The owners and operators of the source and each TR 
SO2 Group 1 unit at the source shall be bound by any 
decision or order issued to the designated representative by the 
Administrator regarding the source or any such unit.
    (b) Except as provided under Sec.  97.615, each TR SO2 
Group 1 source may have one and only one alternate designated 
representative, who may act on behalf of the designated representative. 
The agreement by which the alternate designated representative is 
selected shall include a procedure for authorizing the alternate 
designated representative to act in lieu of the designated 
representative.
    (1) The alternate designated representative shall be selected by an 
agreement binding on the owners and operators of the source and all TR 
SO2 Group 1 units at the source and shall act in accordance 
with the certification statement in Sec.  97.616(a)(4)(iii).
    (2) Upon and after receipt by the Administrator of a complete 
certificate of representation under Sec.  97.616,
    (i) The alternate designated representative shall be authorized;
    (ii) Any representation, action, inaction, or submission by the 
alternate designated representative shall be deemed to be a 
representation, action, inaction, or submission by the designated 
representative; and
    (iii) The owners and operators of the source and each TR 
SO2 Group 1 unit at the source shall be bound by any 
decision or order issued to the alternate designated representative by 
the Administrator regarding the source or any such unit.
    (c) Except in this section, Sec.  97.602, and Sec. Sec.  97.614 
through 97.618, whenever the term ``designated representative'' (as 
distinguished from the term ``common designated representative'') is 
used in this subpart, the term shall be construed to include the 
designated representative or any alternate designated representative.

Sec.  97.614  Responsibilities of designated representative and 
alternate designated representative.

    (a) Except as provided under Sec.  97.618 concerning delegation of 
authority to make submissions, each submission under the TR 
SO2 Group 1 Trading Program shall be made, signed, and 
certified by the designated representative or alternate designated 
representative for each TR SO2 Group 1 source and TR 
SO2 Group 1 unit for which the submission is made. Each such 
submission shall include the following certification statement by the 
designated representative or alternate 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

[[Page 48447]]

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.''
    (b) The Administrator will accept or act on a submission made for a 
TR SO2 Group 1 source or a TR SO2 Group 1 unit 
only if the submission has been made, signed, and certified in 
accordance with paragraph (a) of this section and Sec.  97.618.

Sec.  97.615  Changing designated representative and alternate 
designated representative; changes in owners and operators; changes in 
units at the source.

    (a) Changing designated representative. The designated 
representative may be changed at any time upon receipt by the 
Administrator of a superseding complete certificate of representation 
under Sec.  97.616. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
designated representative before the time and date when the 
Administrator receives the superseding certificate of representation 
shall be binding on the new designated representative and the owners 
and operators of the TR SO2 Group 1 source and the TR 
SO2 Group 1 units at the source.
    (b) Changing alternate designated representative. The alternate 
designated representative may be changed at any time upon receipt by 
the Administrator of a superseding complete certificate of 
representation under Sec.  97.616. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
alternate designated representative before the time and date when the 
Administrator receives the superseding certificate of representation 
shall be binding on the new alternate designated representative, the 
designated representative, and the owners and operators of the TR 
SO2 Group 1 source and the TR SO2 Group 1 units 
at the source.
    (c) Changes in owners and operators. (1) In the event an owner or 
operator of a TR SO2 Group 1 source or a TR SO2 
Group 1 unit at the source is not included in the list of owners and 
operators in the certificate of representation under Sec.  97.616, such 
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 designated representative and any alternate 
designated representative of the source or unit, and the decisions and 
orders of the Administrator, as if the owner or operator were included 
in such list.
    (2) Within 30 days after any change in the owners and operators of 
a TR SO2 Group 1 source or a TR SO2 Group 1 unit 
at the source, including the addition or removal of an owner or 
operator, the designated representative or any alternate designated 
representative shall submit a revision to the certificate of 
representation under Sec.  97.616 amending the list of owners and 
operators to reflect the change.
    (d) Changes in units at the source. Within 30 days of any change in 
which units are located at a TR SO2 Group 1 source 
(including the addition or removal of a unit), the designated 
representative or any alternate designated representative shall submit 
a certificate of representation under Sec.  97.616 amending the list of 
units to reflect the change.
    (1) If the change is the addition of a unit that operated (other 
than for purposes of testing by the manufacturer before initial 
installation) before being located at the source, then the certificate 
of representation shall identify, in a format prescribed by the 
Administrator, the entity from whom the unit was purchased or otherwise 
obtained (including name, address, telephone number, and facsimile 
number (if any)), the date on which the unit was purchased or otherwise 
obtained, and the date on which the unit became located at the source.
    (2) If the change is the removal of a unit, then the certificate of 
representation shall identify, in a format prescribed by the 
Administrator, the entity to which the unit was sold or that otherwise 
obtained the unit (including name, address, telephone number, and 
facsimile number (if any)), the date on which the unit was sold or 
otherwise obtained, and the date on which the unit became no longer 
located at the source.

Sec.  97.616  Certificate of representation.

    (a) A complete certificate of representation for a designated 
representative or an alternate designated representative shall include 
the following elements in a format prescribed by the Administrator:
    (1) Identification of the TR SO2 Group 1 source, and 
each TR SO2 Group 1 unit at the source, for which the 
certificate of representation is submitted, including source name, 
source category and NAICS code (or, in the absence of a NAICS code, an 
equivalent code), State, plant code, county, latitude and longitude, 
unit identification number and type, identification number and 
nameplate capacity (in MWe, rounded to the nearest tenth) of each 
generator served by each such unit, actual or projected date of 
commencement of commercial operation, and a statement of whether such 
source is located in Indian Country. If a projected date of 
commencement of commercial operation is provided, the actual date of 
commencement of commercial operation shall be provided when such 
information becomes available.
    (2) The name, address, e-mail address (if any), telephone number, 
and facsimile transmission number (if any) of the designated 
representative and any alternate designated representative.
    (3) A list of the owners and operators of the TR SO2 
Group 1 source and of each TR SO2 Group 1 unit at the 
source.
    (4) The following certification statements by the designated 
representative and any alternate designated representative--
    (i) ``I certify that I was selected as the designated 
representative or alternate designated representative, as applicable, 
by an agreement binding on the owners and operators of the source and 
each TR SO2 Group 1 unit at the source.''
    (ii) ``I certify that I have all the necessary authority to carry 
out my duties and responsibilities under the TR SO2 Group 1 
Trading Program on behalf of the owners and operators of the source and 
of each TR SO2 Group 1 unit at the source and that each such 
owner and operator shall be fully bound by my representations, actions, 
inactions, or submissions and by any decision or order issued to me by 
the Administrator regarding the source or unit.''
    (iii) ``Where there are multiple holders of a legal or equitable 
title to, or a leasehold interest in, a TR SO2 Group 1 unit, 
or where a utility or industrial customer purchases power from a TR 
SO2 Group 1 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 `designated representative' or `alternate 
designated representative', as applicable, and of the agreement by 
which I was selected to each owner and operator of the source and of 
each TR SO2 Group 1 unit at the source; and TR 
SO2 Group 1 allowances and proceeds of transactions 
involving TR SO2 Group 1 allowances will be deemed to be 
held or distributed in proportion to each

[[Page 48448]]

holder's legal, equitable, leasehold, or contractual reservation or 
entitlement, except that, if such multiple holders have expressly 
provided for a different distribution of TR SO2 Group 1 
allowances by contract, TR SO2 Group 1 allowances and 
proceeds of transactions involving TR SO2 Group 1 allowances 
will be deemed to be held or distributed in accordance with the 
contract.''
    (5) The signature of the designated representative and any 
alternate designated representative and the dates signed.
    (b) Unless otherwise required by the Administrator, documents of 
agreement referred to in the certificate of representation shall not be 
submitted to the Administrator. The Administrator shall not be under 
any obligation to review or evaluate the sufficiency of such documents, 
if submitted.

Sec.  97.617  Objections concerning designated representative and 
alternate designated representative.

    (a) Once a complete certificate of representation under Sec.  
97.616 has been submitted and received, the Administrator will rely on 
the certificate of representation unless and until a superseding 
complete certificate of representation under Sec.  97.616 is received 
by the Administrator.
    (b) Except as provided in paragraph (a) of this section, no 
objection or other communication submitted to the Administrator 
concerning the authorization, or any representation, action, inaction, 
or submission, of a designated representative or alternate designated 
representative shall affect any representation, action, inaction, or 
submission of the designated representative or alternate designated 
representative or the finality of any decision or order by the 
Administrator under the TR SO2 Group 1 Trading Program.
    (c) The Administrator will not adjudicate any private legal dispute 
concerning the authorization or any representation, action, inaction, 
or submission of any designated representative or alternate designated 
representative, including private legal disputes concerning the 
proceeds of TR SO2 Group 1 allowance transfers.

Sec.  97.618  Delegation by designated representative and alternate 
designated representative.

    (a) A designated representative may delegate, to one or more 
natural persons, his or her authority to make an electronic submission 
to the Administrator provided for or required under this subpart.
    (b) An alternate designated representative may delegate, to one or 
more natural persons, his or her authority to make an electronic 
submission to the Administrator provided for or required under this 
subpart.
    (c) In order to delegate authority to a natural person to make an 
electronic submission to the Administrator in accordance with paragraph 
(a) or (b) of this section, the designated representative or alternate 
designated representative, as appropriate, must submit to the 
Administrator a notice of delegation, in a format prescribed by the 
Administrator, that includes the following elements:
    (1) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of such designated 
representative or alternate designated representative;
    (2) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of each such natural person 
(referred to in this section as an ``agent'');
    (3) For each such natural person, a list of the type or types of 
electronic submissions under paragraph (a) or (b) of this section for 
which authority is delegated to him or her; and
    (4) The following certification statements by such designated 
representative or alternate designated representative:
    (i) ``I agree that any electronic submission to the Administrator 
that is made by an agent identified in this notice of delegation and of 
a type listed for such agent in this notice of delegation and that is 
made when I am a designated representative or alternate designated 
representative, as appropriate, and before this notice of delegation is 
superseded by another notice of delegation under 40 CFR 97.618(d) shall 
be deemed to be an electronic submission by me.''
    (ii) ``Until this notice of delegation is superseded by another 
notice of delegation under 40 CFR 97.618(d), I agree to maintain an e-
mail account and to notify the Administrator immediately of any change 
in my e-mail address unless all delegation of authority by me under 40 
CFR 97.618 is terminated.''.
    (d) A notice of delegation submitted under paragraph (c) of this 
section shall be effective, with regard to the designated 
representative or alternate designated representative identified in 
such notice, upon receipt of such notice by the Administrator and until 
receipt by the Administrator of a superseding notice of delegation 
submitted by such designated representative or alternate designated 
representative, as appropriate. The superseding notice of delegation 
may replace any previously identified agent, add a new agent, or 
eliminate entirely any delegation of authority.
    (e) Any electronic submission covered by the certification in 
paragraph (c)(4)(i) of this section and made in accordance with a 
notice of delegation effective under paragraph (d) of this section 
shall be deemed to be an electronic submission by the designated 
representative or alternate designated representative submitting such 
notice of delegation.

Sec.  97.619  [Reserved]

Sec.  97.620  Establishment of compliance accounts, assurance accounts, 
and general accounts.

    (a) Compliance accounts. Upon receipt of a complete certificate of 
representation under Sec.  97.616, the Administrator will establish a 
compliance account for the TR SO2 Group 1 source for which 
the certificate of representation was submitted, unless the source 
already has a compliance account. The designated representative and any 
alternate designated representative of the source shall be the 
authorized account representative and the alternate authorized account 
representative respectively of the compliance account.
    (b) Assurance accounts. The Administrator will establish assurance 
accounts for certain owners and operators and States in accordance with 
Sec.  97.625(b)(3).
    (c) General accounts. (1) Application for general account. (i) Any 
person may apply to open a general account, for the purpose of holding 
and transferring TR SO2 Group 1 allowances, by submitting to 
the Administrator a complete application for a general account. Such 
application shall designate one and only one authorized account 
representative and may designate one and only one alternate authorized 
account representative who may act on behalf of the authorized account 
representative.
    (A) The authorized account representative and alternate authorized 
account representative shall be selected by an agreement binding on the 
persons who have an ownership interest with respect to TR 
SO2 Group 1 allowances held in the general account.
    (B) The agreement by which the alternate authorized account 
representative is selected shall include a procedure for authorizing 
the alternate authorized account representative to act in lieu of the 
authorized account representative.
    (ii) A complete application for a general account shall include the

[[Page 48449]]

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 authorized 
account representative and any alternate authorized account 
representative;
    (B) An identifying name for the general account;
    (C) A list of all persons subject to a binding agreement for the 
authorized account representative and any alternate authorized account 
representative to represent their ownership interest with respect to 
the TR SO2 Group 1 allowances held in the general account;
    (D) The following certification statement by the authorized account 
representative and any alternate authorized account representative: ``I 
certify that I was selected as the authorized account representative or 
the alternate authorized account representative, as applicable, by an 
agreement that is binding on all persons who have an ownership interest 
with respect to TR SO2 Group 1 allowances held in the 
general account. I certify that I have all the necessary authority to 
carry out my duties and responsibilities under the TR SO2 
Group 1 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 decision or order issued to me by the 
Administrator regarding the general account.''
    (E) The signature of the authorized account representative and any 
alternate authorized account representative and the dates signed.
    (iii) Unless otherwise required by the Administrator, documents of 
agreement referred to in the application for a general account shall 
not be submitted to the Administrator. The Administrator shall not be 
under any obligation to review or evaluate the sufficiency of such 
documents, if submitted.
    (2) Authorization of authorized account representative and 
alternate authorized account representative. (i) Upon receipt by the 
Administrator of a complete application for a general account under 
paragraph (b)(1) of this section, the Administrator will establish a 
general account for the person or persons for whom the application is 
submitted, and upon and after such receipt by the Administrator:
    (A) The authorized account representative of the general account 
shall be authorized and shall represent and, by his or her 
representations, actions, inactions, or submissions, legally bind each 
person who has an ownership interest with respect to TR SO2 
Group 1 allowances held in the general account in all matters 
pertaining to the TR SO2 Group 1 Trading Program, 
notwithstanding any agreement between the authorized account 
representative and such person.
    (B) Any alternate authorized account representative shall be 
authorized, and any representation, action, inaction, or submission by 
any alternate authorized account representative shall be deemed to be a 
representation, action, inaction, or submission by the authorized 
account representative.
    (C) Each person who has an ownership interest with respect to TR 
SO2 Group 1 allowances held in the general account shall be 
bound by any decision or order issued to the authorized account 
representative or alternate authorized account representative by the 
Administrator regarding the general account.
    (ii) Except as provided in paragraph (c)(5) of this section 
concerning delegation of authority to make submissions, each submission 
concerning the general account shall be made, signed, and certified by 
the authorized account representative or any alternate authorized 
account representative for the persons having an ownership interest 
with respect to TR SO2 Group 1 allowances held in the 
general account. Each such submission shall include the following 
certification statement by the authorized account representative or any 
alternate authorized account representative: ``I am authorized to make 
this submission on behalf of the persons having an ownership interest 
with respect to the TR SO2 Group 1 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) Except in this section, whenever the term ``authorized 
account representative'' is used in this subpart, the term shall be 
construed to include the authorized account representative or any 
alternate authorized account representative.
    (3) Changing authorized account representative and alternate 
authorized account representative; changes in persons with ownership 
interest. (i) The authorized account representative of 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 (c)(1) of this section. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
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 authorized account representative 
and the persons with an ownership interest with respect to the TR 
SO2 Group 1 allowances in the general account.
    (ii) The alternate authorized account representative of 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 (c)(1) of this section. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
alternate 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 authorized 
account representative, the authorized account representative, and the 
persons with an ownership interest with respect to the TR 
SO2 Group 1 allowances in the general account.
    (iii)(A) In the event a person having an ownership interest with 
respect to TR SO2 Group 1 allowances in the general account 
is not included in the list of such persons in the application for a 
general account, such 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 authorized account representative and 
any alternate authorized account representative of the account, and the 
decisions and orders of the Administrator, as if the person were 
included in such list.
    (B) Within 30 days after any change in the persons having an 
ownership interest with respect to SO2 Group 1 allowances in 
the general account, including the addition or removal of a person, the 
authorized account representative or any alternate 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 TR SO2 Group 1 allowances in the general 
account to include the change.
    (4) Objections concerning authorized account representative and 
alternate

[[Page 48450]]

authorized account representative. (i) Once a complete application for 
a general account under paragraph (c)(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 (c)(4)(i) of this section, no 
objection or other communication submitted to the Administrator 
concerning the authorization, or any representation, action, inaction, 
or submission of the authorized account representative or any alternate 
authorized account representative of a general account shall affect any 
representation, action, inaction, or submission of the authorized 
account representative or any alternate authorized account 
representative or the finality of any decision or order by the 
Administrator under the TR SO2 Group 1 Trading Program.
    (iii) The Administrator will not adjudicate any private legal 
dispute concerning the authorization or any representation, action, 
inaction, or submission of the authorized account representative or any 
alternate authorized account representative of a general account, 
including private legal disputes concerning the proceeds of TR 
SO2 Group 1 allowance transfers.
    (5) Delegation by authorized account representative and alternate 
authorized account representative. (i) An authorized account 
representative of a general account may delegate, to one or more 
natural persons, his or her authority to make an electronic submission 
to the Administrator provided for or required under this subpart.
    (ii) An alternate authorized account representative of a general 
account may delegate, to one or more natural persons, his or her 
authority to make an electronic submission to the Administrator 
provided for or required under this subpart.
    (iii) In order to delegate authority to a natural person to make an 
electronic submission to the Administrator in accordance with paragraph 
(c)(5)(i) or (ii) of this section, the authorized account 
representative or alternate authorized account representative, as 
appropriate, must submit to the Administrator a notice of delegation, 
in a format prescribed by the Administrator, that includes the 
following elements:
    (A) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of such authorized account 
representative or alternate authorized account representative;
    (B) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of each such natural person 
(referred to in this section as an ``agent'');
    (C) For each such natural person, a list of the type or types of 
electronic submissions under paragraph (c)(5)(i) or (ii) of this 
section for which authority is delegated to him or her;
    (D) The following certification statement by such authorized 
account representative or alternate authorized account representative: 
``I agree that any electronic submission to the Administrator that is 
made by an agent identified in this notice of delegation and of a type 
listed for such agent in this notice of delegation and that is made 
when I am an authorized account representative or alternate authorized 
representative, as appropriate, and before this notice of delegation is 
superseded by another notice of delegation under 40 CFR 
97.620(c)(5)(iv) shall be deemed to be an electronic submission by 
me.''; and
    (E) The following certification statement by such authorized 
account representative or alternate authorized account representative: 
``Until this notice of delegation is superseded by another notice of 
delegation under 40 CFR 97.620(c)(5)(iv), I agree to maintain an e-mail 
account and to notify the Administrator immediately of any change in my 
e-mail address unless all delegation of authority by me under 40 CFR 
97.620(c)(5) is terminated.''.
    (iv) A notice of delegation submitted under paragraph (c)(5)(iii) 
of this section shall be effective, with regard to the authorized 
account representative or alternate authorized account representative 
identified in such notice, upon receipt of such notice by the 
Administrator and until receipt by the Administrator of a superseding 
notice of delegation submitted by such authorized account 
representative or alternate authorized account representative, as 
appropriate. The superseding notice of delegation may replace any 
previously identified agent, add a new agent, or eliminate entirely any 
delegation of authority.
    (v) Any electronic submission covered by the certification in 
paragraph (c)(5)(iii)(D) of this section and made in accordance with a 
notice of delegation effective under paragraph (c)(5)(iv) of this 
section shall be deemed to be an electronic submission by the 
designated representative or alternate designated representative 
submitting such notice of delegation.
    (6) Closing a general account. (i) The authorized account 
representative or alternate authorized account representative of a 
general account may submit to the Administrator a request to close the 
account. Such request shall include a correctly submitted TR 
SO2 Group 1 allowance transfer under Sec.  97.622 for any TR 
SO2 Group 1 allowances in the account to one or more other 
Allowance Management System accounts.
    (ii) If a general account has no TR SO2 Group 1 
allowance transfers to or from the account for a 12-month period or 
longer and does not contain any TR SO2 Group 1 allowances, 
the Administrator may notify the authorized account representative for 
the account that the account will be closed after 30 days after the 
notice is sent. The account will be closed after the 30-day period 
unless, before the end of the 30-day period, the Administrator receives 
a correctly submitted TR SO2 Group 1 allowance transfer 
under Sec.  97.622 to the account or a statement submitted by the 
authorized account representative or alternate authorized account 
representative demonstrating to the satisfaction of the Administrator 
good cause as to why the account should not be closed.
    (d) Account identification. The Administrator will assign a unique 
identifying number to each account established under paragraph (a), 
(b), or (c) of this section.
    (e) Responsibilities of authorized account representative and 
alternate authorized account representative. After the establishment of 
a compliance account or general account, the Administrator will accept 
or act on a submission pertaining to the account, including, but not 
limited to, submissions concerning the deduction or transfer of TR 
SO2 Group 1 allowances in the account, only if the 
submission has been made, signed, and certified in accordance with 
Sec. Sec.  97.614(a) and 97.618 or paragraphs (c)(2)(ii) and (c)(5) of 
this section.

Sec.  97.621  Recordation of TR SO2 Group 1 allowance allocations and 
auction results.

    (a) By November 7, 2011, the Administrator will record in each TR 
SO2 Group 1 source's compliance account the TR 
SO2 Group 1 allowances allocated to the TR SO2 
Group 1 units at the source in accordance with Sec.  97.611(a) for the 
control period in 2012.
    (b) By November 7, 2011, the Administrator will record in each TR 
SO2 Group 1 source's compliance account the TR 
SO2 Group 1 allowances allocated to the TR SO2 
Group 1 units at the source in accordance with

[[Page 48451]]

Sec.  97.611(a) for the control period in 2013, unless the State in 
which the source is located notifies the Administrator in writing by 
October 17, 2011 of the State's intent to submit to the Administrator a 
complete SIP revision by April 1, 2012 meeting the requirements of 
Sec.  52.39(d)(1) through (4) of this chapter.
    (1) If, by April 1, 2012, the State does not submit to the 
Administrator such complete SIP revision, the Administrator will record 
by April 15, 2012 in each TR SO2 Group 1 source's compliance 
account the TR SO2 Group 1 allowances allocated to the TR 
SO2 Group 1 units at the source in accordance with Sec.  
97.611(a) for the control period in 2013.
    (2) If the State submits to the Administrator by April 1, 2012, and 
the Administrator approves by October 1, 2012, such complete SIP 
revision, the Administrator will record by October 1, 2012 in each TR 
SO2 Group 1 source's compliance account the TR 
SO2 Group 1 allowances allocated to the TR SO2 
Group 1 units at the source as provided in such approved, complete SIP 
revision for the control period in 2013.
    (3) If the State submits to the Administrator by April 1, 2012, and 
the Administrator does not approve by October 1, 2012, such complete 
SIP revision, the Administrator will record by October 1, 2012 in each 
TR SO2 Group 1 source's compliance account the TR 
SO2 Group 1 allowances allocated to the TR SO2 
Group 1 units at the source in accordance with Sec.  97.611(a) for the 
control period in 2013.
    (c) By July 1, 2013, the Administrator will record in each TR 
SO2 Group 1 source's compliance account the TR 
SO2 Group 1 allowances allocated to the TR SO2 
Group 1 units at the source, or in each appropriate Allowance 
Management System account the TR SO2 Group 1 allowances 
auctioned to TR SO2 Group 1 units, in accordance with Sec.  
97.611(a), or with a SIP revision approved under Sec.  52.39(e) or (f) 
of this chapter, for the control period in 2014 and 2015.
    (d) By July 1, 2014, the Administrator will record in each TR 
SO2 Group 1 source's compliance account the TR 
SO2 Group 1 allowances allocated to the TR SO2 
Group 1 units at the source, or in each appropriate Allowance 
Management System account the TR SO2 Group 1 allowances 
auctioned to TR SO2 Group 1 units, in accordance with Sec.  
97.611(a), or with a SIP revision approved under Sec.  52.39(e) or (f) 
of this chapter, for the control period in 2016 and 2017.
    (e) By July 1, 2015, the Administrator will record in each TR 
SO2 Group 1 source's compliance account the TR 
SO2 Group 1 allowances allocated to the TR SO2 
Group 1 units at the source, or in each appropriate Allowance 
Management System account the TR SO2 Group 1 allowances 
auctioned to TR SO2 Group 1 units, in accordance with Sec.  
97.611(a), or with a SIP revision approved under Sec.  52.39(e) or (f) 
of this chapter, for the control period in 2018 and 2019.
    (f) By July 1, 2016 and July 1 of each year thereafter, the 
Administrator will record in each TR SO2 Group 1 source's 
compliance account the TR SO2 Group 1 allowances allocated 
to the TR SO2 Group 1 units at the source, or in each 
appropriate Allowance Management System account the TR SO2 
Group 1 allowances auctioned to TR SO2 Group 1 units, in 
accordance with Sec.  97.611(a), or with a SIP revision approved under 
Sec.  52.39(e) and (f) of this chapter, for the control period in the 
fourth year after the year of the applicable recordation deadline under 
this paragraph.
    (g) By August 1, 2012 and August 1 of each year thereafter, the 
Administrator will record in each TR SO2 Group 1 source's 
compliance account the TR SO2 Group 1 allowances allocated 
to the TR SO2 Group 1 units at the source, or in each 
appropriate Allowance Management System account the TR SO2 
Group 1 allowances auctioned to TR SO2 Group 1 units, in 
accordance with Sec.  97.612(a)(2) through (8) and (12), or with a SIP 
revision approved under Sec.  52.39(e) and (f) of this chapter, for the 
control period in the year of the applicable recordation deadline under 
this paragraph.
    (h) By August 1, 2012 and August 1 of each year thereafter, the 
Administrator will record in each TR SO2 Group 1 source's 
compliance account the TR SO2 Group 1 allowances allocated 
to the TR SO2 Group 1 units at the source in accordance with 
Sec.  97.612(b)(2) through (8) and (12) for the control period in the 
year of the applicable recordation deadline under this paragraph.
    (i) By February 15, 2013 and February 15 of each year thereafter, 
the Administrator will record in each TR SO2 Group 1 
source's compliance account the TR SO2 Group 1 allowances 
allocated to the TR SO2 Group 1 units at the source in 
accordance with Sec.  97.612(a)(9) through (12), for the control period 
in the year before the year of the applicable recordation deadline 
under this paragraph.
    (j) By the date on which any allocation or auction results, other 
than an allocation or auction results described in paragraphs (a) 
through (i) of this section, of TR SO2 Group 1 allowances to 
a recipient is made by or are submitted to the Administrator in 
accordance with Sec.  97.611 or Sec.  97.612 or with a SIP revision 
approved under Sec.  52.39(e) or (f) of this chapter, the Administrator 
will record such allocation or auction results in the appropriate 
Allowance Management System account.
    (k) When recording the allocation or auction of TR SO2 
Group 1 allowances to a TR SO2 Group 1 unit or other entity 
in an Allowance Management System account, the Administrator will 
assign each TR SO2 Group 1 allowance a unique identification 
number that will include digits identifying the year of the control 
period for which the TR SO2 Group 1 allowance is allocated 
or auctioned.

Sec.  97.622  Submission of TR SO2 Group 1 allowance transfers.

    (a) An authorized account representative seeking recordation of a 
TR SO2 Group 1 allowance transfer shall submit the transfer 
to the Administrator.
    (b) A TR SO2 Group 1 allowance transfer shall be 
correctly submitted if:
    (1) The transfer includes the following elements, in a format 
prescribed by the Administrator:
    (i) The account numbers established by the Administrator for both 
the transferor and transferee accounts;
    (ii) The serial number of each TR SO2 Group 1 allowance 
that is in the transferor account and is to be transferred; and
    (iii) The name and signature of the authorized account 
representative of the transferor account and the date signed; and
    (2) When the Administrator attempts to record the transfer, the 
transferor account includes each TR SO2 Group 1 allowance 
identified by serial number in the transfer.

Sec.  97.623  Recordation of TR SO2 Group 1 allowance transfers.

    (a) Within 5 business days (except as provided in paragraph (b) of 
this section) of receiving a TR SO2 Group 1 allowance 
transfer that is correctly submitted under Sec.  97.622, the 
Administrator will record a TR SO2 Group 1 allowance 
transfer by moving each TR SO2 Group 1 allowance from the 
transferor account to the transferee account as specified in the 
transfer.
    (b) A TR SO2 Group 1 allowance transfer to or from a 
compliance account that is submitted for recordation after the 
allowance transfer deadline for a control period and that includes any 
TR SO2 Group 1 allowances allocated for

[[Page 48452]]

any control period before such allowance transfer deadline will not be 
recorded until after the Administrator completes the deductions from 
such compliance account under Sec.  97.624 for the control period 
immediately before such allowance transfer deadline.
    (c) Where a TR SO2 Group 1 allowance transfer is not 
correctly submitted under Sec.  97.622, the Administrator will not 
record such transfer.
    (d) Within 5 business days of recordation of a TR SO2 
Group 1 allowance transfer under paragraphs (a) and (b) of the section, 
the Administrator will notify the authorized account representatives of 
both the transferor and transferee accounts.
    (e) Within 10 business days of receipt of a TR SO2 Group 
1 allowance transfer that is not correctly submitted under Sec.  
97.622, the Administrator will notify the 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.

Sec.  97.624  Compliance with TR SO2 Group 1 emissions limitation.

    (a) Availability for deduction for compliance. TR SO2 
Group 1 allowances are available to be deducted for compliance with a 
source's TR SO2 Group 1 emissions limitation for a control 
period in a given year only if the TR SO2 Group 1 
allowances:
    (1) Were allocated for such control period or a control period in a 
prior year; and
    (2) Are held in the source's compliance account as of the allowance 
transfer deadline for such control period.
    (b) Deductions for compliance. After the recordation, in accordance 
with Sec.  97.623, of TR SO2 Group 1 allowance transfers 
submitted by the allowance transfer deadline for a control period in a 
given year, the Administrator will deduct from each source's compliance 
account TR SO2 Group 1 allowances available under paragraph 
(a) of this section in order to determine whether the source meets the 
TR SO2 Group 1 emissions limitation for such control period, 
as follows:
    (1) Until the amount of TR SO2 Group 1 allowances 
deducted equals the number of tons of total SO2 emissions 
from all TR SO2 Group 1 units at the source for such control 
period; or
    (2) If there are insufficient TR SO2 Group 1 allowances 
to complete the deductions in paragraph (b)(1) of this section, until 
no more TR SO2 Group 1 allowances available under paragraph 
(a) of this section remain in the compliance account.
    (c)(1) Identification of TR SO2 Group 1 allowances by serial 
number. The authorized account representative for a source's compliance 
account may request that specific TR SO2 Group 1 allowances, 
identified by serial number, in the compliance account be deducted for 
emissions or excess emissions for a control period in a given year in 
accordance with paragraph (b) or (d) of this section. In order to be 
complete, such request shall be submitted to the Administrator by the 
allowance transfer deadline for such control period and include, in a 
format prescribed by the Administrator, the identification of the TR 
SO2 Group 1 source and the appropriate serial numbers.
    (2) First-in, first-out. The Administrator will deduct TR 
SO2 Group 1 allowances under paragraph (b) or (d) of this 
section from the source's compliance account in accordance with a 
complete request under paragraph (c)(1) of this section or, in the 
absence of such request or in the case of identification of an 
insufficient amount of TR SO2 Group 1 allowances in such 
request, on a first-in, first-out accounting basis in the following 
order:
    (i) Any TR SO2 Group 1 allowances that were allocated to 
the units at the source and not transferred out of the compliance 
account, in the order of recordation; and then
    (ii) Any TR SO2 Group 1 allowances that were allocated 
to any unit and transferred to and recorded in the compliance account 
pursuant to this subpart, in the order of recordation.
    (d) Deductions for excess emissions. After making the deductions 
for compliance under paragraph (b) of this section for a control period 
in a year in which the TR SO2 Group 1 source has excess 
emissions, the Administrator will deduct from the source's compliance 
account an amount of TR SO2 Group 1 allowances, allocated 
for a control period in a prior year or the control period in the year 
of the excess emissions or in the immediately following year, equal to 
two times the number of tons of the source's excess emissions.
    (e) Recordation of deductions. The Administrator will record in the 
appropriate compliance account all deductions from such an account 
under paragraphs (b) and (d) of this section.

Sec.  97.625  Compliance with TR SO2 Group 1 assurance provisions.

    (a) Availability for deduction. TR SO2 Group 1 
allowances are available to be deducted for compliance with the TR 
SO2 Group 1 assurance provisions for a control period in a 
given year by the owners and operators of a group of one or more TR 
SO2 Group 1 sources and units in a State (and Indian country 
within the borders of such State) only if the TR SO2 Group 1 
allowances:
    (1) Were allocated for a control period in a prior year or the 
control period in the given year or in the immediately following year; 
and
    (2) Are held in the assurance account, established by the 
Administrator for such owners and operators of such group of TR 
SO2 Group 1 sources and units in such State (and Indian 
country within the borders of such State) under paragraph (b)(3) of 
this section, as of the deadline established in paragraph (b)(4) of 
this section.
    (b) Deductions for compliance. The Administrator will deduct TR 
SO2 Group 1 allowances available under paragraph (a) of this 
section for compliance with the TR SO2 Group 1 assurance 
provisions for a State for a control period in a given year in 
accordance with the following procedures:
    (1) By June 1, 2013 and June 1 of each year thereafter, the 
Administrator will:
    (i) Calculate, for each State (and Indian country within the 
borders of such State), the total SO2 emissions from all TR 
SO2 Group 1 units at TR SO2 Group 1 sources in 
the State (and Indian country within the borders of such State) during 
the control period in the year before the year of this calculation 
deadline and the amount, if any, by which such total SO2 
emissions exceed the State assurance level as described in Sec.  
97.606(c)(2)(iii); and
    (ii) Promulgate a notice of data availability of the results of the 
calculations required in paragraph (b)(1)(i) of this section, including 
separate calculations of the SO2 emissions from each TR 
SO2 Group 1 source.
    (2) For each notice of data availability required in paragraph 
(b)(1)(ii) of this section and for any State (and Indian country within 
the borders of such State) identified in such notice as having TR 
SO2 Group 1 units with total SO2 emissions 
exceeding the State assurance level for a control period in a given 
year, as described in Sec.  97.606(c)(2)(iii):
    (i) By July 1 immediately after the promulgation of such notice, 
the designated representative of each TR SO2 Group 1 source 
in each such State (and Indian country within the borders of such 
State) shall submit a statement, in a format prescribed by the 
Administrator, providing for each TR SO2 Group 1 unit (if 
any) at the source

[[Page 48453]]

that operates during, but is not allocated an amount of TR 
SO2 Group 1 allowances for, such control period, the unit's 
allowable SO2 emission rate for such control period and, if 
such rate is expressed in lb per mmBtu, the unit's heat rate.
    (ii) By August 1 immediately after the promulgation of such notice, 
the Administrator will calculate, for each such State (and Indian 
country within the borders of such State) and such control period and 
each common designated representative for such control period for a 
group of one or more TR SO2 Group 1 sources and units in the 
State (and Indian country within the borders of such State), the common 
designated representative's share of the total SO2 emissions 
from all TR SO2 Group 1 units at TR SO2 Group 1 
sources in the State (and Indian country within the borders of such 
State), the common designated representative's assurance level, and the 
amount (if any) of TR SO2 Group 1 allowances that the owners 
and operators of such group of sources and units must hold in 
accordance with the calculation formula in Sec.  97.606(c)(2)(i) and 
will promulgate a notice of data availability of the results of these 
calculations.
    (iii) The Administrator will provide an opportunity for submission 
of objections to the calculations referenced by the notice of data 
availability required in paragraph (b)(2)(ii) of this section and the 
calculations referenced by the relevant notice of data availability 
required in paragraph (b)(1)(i) of this section.
    (A) Objections shall be submitted by the deadline specified in such 
notice and shall be limited to addressing whether the calculations 
referenced in the relevant notice required under paragraph (b)(1)(ii) 
of this section and referenced in the notice required under paragraph 
(b)(2)(ii) of this section are in accordance with Sec.  
97.606(c)(2)(iii), Sec. Sec.  97.606(b) and 97.630 through 97.635, the 
definitions of ``common designated representative'', ``common 
designated representative's assurance level'', and ``common designated 
representative's share'' in Sec.  97.602, and the calculation formula 
in Sec.  97.606(c)(2)(i).
    (B) The Administrator will adjust the calculations to the extent 
necessary to ensure that they are in accordance with the provisions 
referenced in paragraph (b)(2)(iii)(A) of this section. By October 1 
immediately after the promulgation of such notice, the Administrator 
will promulgate a notice of data availability of any adjustments that 
the Administrator determines to be necessary and the reasons for 
accepting or rejecting any objections submitted in accordance with 
paragraph (b)(2)(iii)(A) of this section.
    (3) For any State (and Indian country within the borders of such 
State) referenced in each notice of data availability required in 
paragraph (b)(2)(iii)(B) of this section as having TR SO2 
Group 1 units with total SO2 emissions exceeding the State 
assurance level for a control period in a given year, the Administrator 
will establish one assurance account for each set of owners and 
operators referenced, in the notice of data availability required under 
paragraph (b)(2)(iii)(B) of this section, as all of the owners and 
operators of a group of TR SO2 Group 1 sources and units in 
the State (and Indian country within the borders of such State) having 
a common designated representative for such control period and as being 
required to hold TR SO2 Group 1 allowances.
    (4)(i) As of midnight of November 1 immediately after the 
promulgation of each notice of data availability required in paragraph 
(b)(2)(iii)(B) of this section, the owners and operators described in 
paragraph (b)(3) of this section shall hold in the assurance account 
established for them and for the appropriate TR SO2 Group 1 
sources, TR SO2 Group 1 units, and State (and Indian country 
within the borders of such State) under paragraph (b)(3) of this 
section a total amount of TR SO2 Group 1 allowances, 
available for deduction under paragraph (a) of this section, equal to 
the amount such owners and operators are required to hold with regard 
to such sources, units and State (and Indian country within the borders 
of such State) as calculated by the Administrator and referenced in 
such notice.
    (ii) Notwithstanding the allowance-holding deadline specified in 
paragraph (b)(4)(i) of this section, if November 1 is not a business 
day, then such allowance-holding deadline shall be midnight of the 
first business day thereafter.
    (5) After November 1 (or the date described in paragraph (b)(4)(ii) 
of this section) immediately after the promulgation of each notice of 
data availability required in paragraph (b)(2)(iii)(B) of this section 
and after the recordation, in accordance with Sec.  97.623, of TR 
SO2 Group 1 allowance transfers submitted by midnight of 
such date, the Administrator will determine whether the owners and 
operators described in paragraph (b)(3) of this section hold, in the 
assurance account for the appropriate TR SO2 Group 1 
sources, TR SO2 Group 1 units, and State (and Indian country 
within the borders of such State) established under paragraph (b)(3) of 
this section, the amount of TR SO2 Group 1 allowances 
available under paragraph (a) of this section that the owners and 
operators are required to hold with regard to such sources, units, and 
State (and Indian country within the borders of such State) as 
calculated by the Administrator and referenced in the notice required 
in paragraph (b)(2)(iii)(B) of this section.
    (6) Notwithstanding any other provision of this subpart and any 
revision, made by or submitted to the Administrator after the 
promulgation of the notice of data availability required in paragraph 
(b)(2)(iii)(B) of this section for a control period in a given year, of 
any data used in making the calculations referenced in such notice, the 
amounts of TR SO2 Group 1 allowances that the owners and 
operators are required to hold in accordance with Sec.  97.606(c)(2)(i) 
for such control period shall continue to be such amounts as calculated 
by the Administrator and referenced in such notice required in 
paragraph (b)(2)(iii)(B) of this section, except as follows:
    (i) If any such data are revised by the Administrator as a result 
of a decision in or settlement of litigation concerning such data on 
appeal under part 78 of this chapter of such notice, or on appeal under 
section 307 of the Clean Air Act of a decision rendered under part 78 
of this chapter on appeal of such notice, then the Administrator will 
use the data as so revised to recalculate the amounts of TR 
SO2 Group 1 allowances that owners and operators are 
required to hold in accordance with the calculation formula in Sec.  
97.606(c)(2)(i) for such control period with regard to the TR 
SO2 Group 1 sources, TR SO2 Group 1 units, and 
State (and Indian country within the borders of such State) involved, 
provided that such litigation under part 78 of this chapter, or the 
proceeding under part 78 of this chapter that resulted in the decision 
appealed in such litigation under section 307 of the Clean Air Act, was 
initiated no later than 30 days after promulgation of such notice 
required in paragraph (b)(2)(iii)(B) of this section.
    (ii) If any such data are revised by the owners and operators of a 
TR SO2 Group 1 source and TR SO2 Group 1 unit 
whose designated representative submitted such data under paragraph 
(b)(2)(i) of this section, as a result of a decision in or settlement 
of litigation concerning such submission, then the Administrator will 
use the data as so revised to recalculate the amounts of TR 
SO2 Group 1 allowances that owners and operators are 
required to hold in

[[Page 48454]]

accordance with the calculation formula in Sec.  97.606(c)(2)(i) for 
such control period with regard to the TR SO2 Group 1 
sources, TR SO2 Group 1 units, and State (and Indian country 
within the borders of such State) involved, provided that such 
litigation was initiated no later than 30 days after promulgation of 
such notice required in paragraph (b)(2)(iii)(B) of this section.
    (iii) If the revised data are used to recalculate, in accordance 
with paragraphs (b)(6)(i) and (ii) of this section, the amount of TR 
SO2 Group 1 allowances that the owners and operators are 
required to hold for such control period with regard to the TR 
SO2 Group 1 sources, TR SO2 Group 1 units, and 
State (and Indian country within the borders of such State) involved--
    (A) Where the amount of TR SO2 Group 1 allowances that 
the owners and operators are required to hold increases as a result of 
the use of all such revised data, the Administrator will establish a 
new, reasonable deadline on which the owners and operators shall hold 
the additional amount of TR SO2 Group 1 allowances in the 
assurance account established by the Administrator for the appropriate 
TR SO2 Group 1 sources, TR SO2 Group 1 units, and 
State (and Indian country within the borders of such State) under 
paragraph (b)(3) of this section. The owners' and operators' failure to 
hold such additional amount, as required, before the new deadline shall 
not be a violation of the Clean Air Act. The owners' and operators' 
failure to hold such additional amount, as required, as of the new 
deadline shall be a violation of the Clean Air Act. Each TR 
SO2 Group 1 allowance that the owners and operators fail to 
hold as required as of the new deadline, and each day in such control 
period, shall be a separate violation of the Clean Air Act.
    (B) For the owners and operators for which the amount of TR 
SO2 Group 1 allowances required to be held decreases as a 
result of the use of all such revised data, the Administrator will 
record, in all accounts from which TR SO2 Group 1 allowances 
were transferred by such owners and operators for such control period 
to the assurance account established by the Administrator for the 
appropriate TR SO2 Group 1 sources, TR SO2 Group 
1 units, and State (and Indian country within the borders of such 
State) under paragraph (b)(3) of this section, a total amount of the TR 
SO2 Group 1 allowances held in such assurance account equal 
to the amount of the decrease. If TR SO2 Group 1 allowances 
were transferred to such assurance account from more than one account, 
the amount of TR SO2 Group 1 allowances recorded in each 
such transferor account will be in proportion to the percentage of the 
total amount of TR SO2 Group 1 allowances transferred to 
such assurance account for such control period from such transferor 
account.
    (C) Each TR SO2 Group 1 allowance held under paragraph 
(b)(6)(iii)(A) of this section as a result of recalculation of 
requirements under the TR SO2 Group 1 assurance provisions 
for such control period must be a TR SO2 Group 1 allowance 
allocated for a control period in a year before or the year immediately 
following, or in the same year as, the year of such control period.

Sec.  97.626  Banking.

    (a) A TR SO2 Group 1 allowance 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 TR SO2 Group 1 allowance that is held in a 
compliance account or a general account will remain in such account 
unless and until the TR SO2 Group 1 allowance is deducted or 
transferred under Sec.  97.611(c), Sec.  97.623, Sec.  97.624, Sec.  
97.625, Sec.  97.627, or Sec.  97.628.

Sec.  97.627  Account error.

    The Administrator may, at his or her sole discretion and on his or 
her own motion, correct any error in any Allowance Management System 
account. Within 10 business days of making such correction, the 
Administrator will notify the authorized account representative for the 
account.

Sec.  97.628  Administrator's action on submissions.

    (a) The Administrator may review and conduct independent audits 
concerning any submission under the TR SO2 Group 1 Trading 
Program and make appropriate adjustments of the information in the 
submission.
    (b) The Administrator may deduct TR SO2 Group 1 
allowances from or transfer TR SO2 Group 1 allowances to a 
compliance account or an assurance account, based on the information in 
a submission, as adjusted under paragraph (a)(1) of this section, and 
record such deductions and transfers.

Sec.  97.629  [Reserved]

Sec.  97.630  General monitoring, recordkeeping, and reporting 
requirements.

    The owners and operators, and to the extent applicable, the 
designated representative, of a TR SO2 Group 1 unit, shall 
comply with the monitoring, recordkeeping, and reporting requirements 
as provided in this subpart and subparts F and G of part 75 of this 
chapter. For purposes of applying such requirements, the definitions in 
Sec.  97.602 and in Sec.  72.2 of this chapter shall apply, 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 ``TR SO2 Group 1 
unit,'' ``designated representative,'' and ``continuous emission 
monitoring system'' (or ``CEMS'') respectively as defined in Sec.  
97.602, and the term ``newly affected unit'' shall be deemed to mean 
``newly affected TR SO2 Group 1 unit''. The owner or 
operator of a unit that is not a TR SO2 Group 1 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 TR SO2 Group 1 unit.
    (a) Requirements for installation, certification, and data 
accounting. The owner or operator of each TR SO2 Group 1 
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.  97.631 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. Except as provided in paragraph (e) of 
this section, 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 and 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 TR SO2 Group 1 unit 
that commences commercial operation before July 1, 2011, January 1, 
2012.
    (2) For the owner or operator of a TR SO2 Group 1 unit 
that commences commercial operation on or after July 1, 2011, by the 
later of the following:
    (i) January 1, 2012; or
    (ii) 180 calendar days after the date on which the unit commences 
commercial operation.

[[Page 48455]]

    (3) The owner or operator of a TR SO2 Group 1 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) or (2) of this section shall meet the 
requirements of Sec. Sec.  75.4(e)(1) through (e)(4) of this chapter, 
except that:
    (i) Such requirements shall apply to the monitoring systems 
required under Sec.  97.630 through Sec.  97.635, rather than the 
monitoring systems required under part 75 of this chapter;
    (ii) SO2 concentration, stack gas moisture content, 
stack gas volumetric flow rate, and O2 or CO2 
concentration data shall be determined and reported, rather than the 
data listed in Sec.  75.4(e)(2) of this chapter; and
    (iii) Any petition for another procedure under Sec.  75.4(e)(2) of 
this chapter shall be submitted under Sec.  97.635, rather than Sec.  
75.66.
    (c) Reporting data. The owner or operator of a TR SO2 
Group 1 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, 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.
    (d) Prohibitions. (1) No owner or operator of a TR SO2 
Group 1 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.  97.635.
    (2) No owner or operator of a TR SO2 Group 1 unit shall 
operate the unit so as to discharge, or allow to be discharged, 
SO2 to the atmosphere without accounting for all such 
SO2 in accordance with the applicable provisions of this 
subpart and part 75 of this chapter.
    (3) No owner or operator of a TR SO2 Group 1 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 discharged into the 
atmosphere or heat input, 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 TR SO2 Group 1 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.  97.605 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 Administrator 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 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.  
97.631(d)(3)(i).
    (e) Long-term cold storage. The owner or operator of a TR 
SO2 Group 1 unit is subject to the applicable provisions of 
Sec.  75.4(d) of this chapter concerning units in long-term cold 
storage.

Sec.  97.631  Initial monitoring system certification and 
recertification procedures.

    (a) The owner or operator of a TR SO2 Group 1 unit shall 
be exempt from the initial certification requirements of this section 
for a monitoring system under Sec.  97.630(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 appendices B and 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.  97.630(a)(1) that is exempt from initial 
certification requirements under paragraph (a) of this section.
    (c) [Reserved]
    (d) Except as provided in paragraph (a) of this section, the owner 
or operator of a TR SO2 Group 1 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.  97.630(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.  
97.630(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.  97.630(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.  97.630(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.  97.630(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. 
For initial certification of a continuous monitoring system under Sec.  
97.630(a)(1), paragraphs (d)(3)(i) through (v) of this

[[Page 48456]]

section apply. For recertifications of such monitoring systems, 
paragraphs (d)(3)(i) through (iv) of this section and 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) apply, provided that 
in applying paragraphs (d)(3)(i) through (iv) of this section, the 
words ``certification'' and ``initial certification'' are replaced by 
the word ``recertification'' and the word ``certified'' is replaced by 
the word ``recertified''.
    (i) Notification of certification. The designated representative 
shall submit to the appropriate EPA Regional Office and the 
Administrator written notice of the dates of certification testing, in 
accordance with Sec.  97.633.
    (ii) Certification application. The designated representative shall 
submit to the Administrator 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 TR SO2 Group 1 Trading Program 
for a period not to exceed 120 days after receipt by the Administrator 
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 Administrator 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 Administrator.
    (iv) Certification application approval process. The Administrator 
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 Administrator 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 TR SO2 Group 1 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 Administrator 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 Administrator will issue a written notice of 
incompleteness that sets a reasonable date by which the designated 
representative must submit the additional information required to 
complete the certification application. If the designated 
representative does not comply with the notice of incompleteness by the 
specified date, then the Administrator may issue a notice of 
disapproval under paragraph (d)(3)(iv)(C) of this section.
    (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 Administrator 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 Administrator 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).
    (D) Audit decertification. The Administrator may issue a notice of 
disapproval of the certification status of a monitor in accordance with 
Sec.  97.632(b).
    (v) Procedures for loss of certification. If 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 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 Administrator's notice of disapproval, no later than 
30 unit operating days after the date of issuance of the notice of 
disapproval.
    (e) 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) The designated representative of each unit for which the owner 
or operator intends to use an alternative monitoring system approved by 
the Administrator 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.  97.632  Monitoring system out-of-control periods.

    (a) General provisions. 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 appendix D to part 75 of this chapter.
    (b) Audit decertification. Whenever both an audit of a monitoring 
system

[[Page 48457]]

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.  97.631 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 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 Administrator or any 
State or permitting authority. By issuing the notice of disapproval, 
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.  
97.631 for each disapproved monitoring system.

Sec.  97.633  Notifications concerning monitoring.

    The designated representative of a TR SO2 Group 1 unit 
shall submit written notice to the Administrator in accordance with 
Sec.  75.61 of this chapter.

Sec.  97.634  Recordkeeping and reporting.

    (a) General provisions. The designated representative shall comply 
with all recordkeeping and reporting requirements in paragraphs (b) 
through (e) of this section, the applicable recordkeeping and reporting 
requirements in subparts F and G of part 75 of this chapter, and the 
requirements of Sec.  97.614(a).
    (b) Monitoring plans. The owner or operator of a TR SO2 
Group 1 unit shall comply with requirements of Sec.  75.62 of this 
chapter.
    (c) Certification applications. The designated representative shall 
submit an application to the Administrator within 45 days after 
completing all initial certification or recertification tests required 
under Sec.  97.631, including the information required under Sec.  
75.63 of this chapter.
    (d) Quarterly reports. The designated representative shall submit 
quarterly reports, as follows:
    (1) The designated representative shall report the SO2 
mass emissions data and heat input data for the TR SO2 Group 
1 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, 
2011, the calendar quarter covering January 1, 2012 through March 31, 
2012; or
    (ii) For a unit that commences commercial operation on or after 
July 1, 2011, the calendar quarter corresponding to the earlier of the 
date of provisional certification or the applicable deadline for 
initial certification under Sec.  97.630(b), unless that quarter is the 
third or fourth quarter of 2011, in which case reporting shall commence 
in the quarter covering January 1, 2012 through March 31, 2012.
    (2) The designated representative shall submit each quarterly 
report to the Administrator within 30 days after 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 TR SO2 Group 1 units that are also subject to 
the Acid Rain Program, TR NOX Annual Trading Program, or TR 
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.
    (4) The Administrator may review and conduct independent audits of 
any quarterly report in order to determine whether the quarterly report 
meets the requirements of this subpart and part 75 of this chapter, 
including the requirement to use substitute data.
    (i) The Administrator will notify the designated representative of 
any determination that the quarterly report fails to meet any such 
requirements and specify in such notification any corrections that the 
Administrator believes are necessary to make through resubmission of 
the quarterly report and a reasonable time period within which the 
designated representative must respond. Upon request by the designated 
representative, the Administrator may specify reasonable extensions of 
such time period. Within the time period (including any such 
extensions) specified by the Administrator, the designated 
representative shall resubmit the quarterly report with the corrections 
specified by the Administrator, except to the extent the designated 
representative provides information demonstrating that a specified 
correction is not necessary because the quarterly report already meets 
the requirements of this subpart and part 75 of this chapter that are 
relevant to the specified correction.
    (ii) Any resubmission of a quarterly report shall meet the 
requirements applicable to the submission of a quarterly report under 
this subpart and part 75 of this chapter, except for the deadline set 
forth in paragraph (d)(2) of this section.
    (e) Compliance certification. The 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.  97.635  Petitions for alternatives to monitoring, recordkeeping, 
or reporting requirements.

    (a) The designated representative of a TR SO2 Group 1 
unit may submit a petition under Sec.  75.66 of this chapter to the 
Administrator, requesting approval to apply an alternative to any 
requirement of Sec. Sec.  97.630 through 97.634.
    (b) A petition submitted under paragraph (a) of this section shall 
include sufficient information for the evaluation of the petition, 
including, at a minimum, the following information:
    (i) Identification of each unit and source covered by the petition;
    (ii) A detailed explanation of why the proposed alternative is 
being suggested in lieu of the requirement;
    (iii) A description and diagram of any equipment and procedures 
used in the proposed alternative;
    (iv) A demonstration that the proposed alternative is consistent 
with

[[Page 48458]]

the purposes of the requirement for which the alternative is proposed 
and with the purposes of this subpart and part 75 of this chapter and 
that any adverse effect of approving the alternative will be de 
minimis; and
    (v) Any other relevant information that the Administrator may 
require.
    (c) Use of an alternative to any requirement referenced in 
paragraph (a) of this section is in accordance with this subpart only 
to the extent that the petition is approved in writing by the 
Administrator and that such use is in accordance with such approval.
    77. Part 97 is amended by adding subpart DDDDD to read as follows:
Subpart DDDDD--TR SO2 Group 2 Trading Program
Sec.
97.701 Purpose.
97.702 Definitions.
97.703 Measurements, abbreviations, and acronyms.
97.704 Applicability.
97.705 Retired unit exemption.
97.706 Standard requirements.
97.707 Computation of time.
97.708 Administrative appeal procedures.
97.709 [Reserved]
97.710 State SO2 Group 2 trading budgets, new unit set-
asides, Indian country new unit set-asides and variability limits.
97.711 Timing requirements for TR SO2 Group 2 allowance 
allocations.
97.712 TR SO2 Group 2 allowance allocations to new units.
97.713 Authorization of designated representative and alternate 
designated representative.
97.714 Responsibilities of designated representative and alternate 
designated representative.
97.715 Changing designated representative and alternate designated 
representative; changes in owners and operators.
97.716 Certificate of representation.
97.717 Objections concerning designated representative and alternate 
designated representative.
97.718 Delegation by designated representative and alternate 
designated representative.
97.719 [Reserved]
97.720 Establishment of compliance accounts and general accounts.
97.721 Recordation of TR SO2 Group 2 allowance 
allocations.
97.722 Submission of TR SO2 Group 2 allowance transfers.
97.723 Recordation of TR SO2 Group 2 allowance transfers.
97.724 Compliance with TR SO2 Group 2 emissions 
limitation.
97.725 Compliance with TR SO2 Group 2 assurance 
provisions.
97.726 Banking.
97.727 Account error.
97.728 Administrator's action on submissions.
97.729 [Reserved]
97.730 General monitoring, recordkeeping, and reporting 
requirements.
97.731 Initial monitoring system certification and recertification 
procedures.
97.732 Monitoring system out-of-control periods.
97.733 Notifications concerning monitoring.
97.734 Recordkeeping and reporting.
97.735 Petitions for alternatives to monitoring, recordkeeping, or 
reporting requirements.

Subpart DDDDD--TR SO2 Group 2 Trading Program

Sec.  97.701  Purpose.

    This subpart sets forth the general, designated representative, 
allowance, and monitoring provisions for the Transport Rule (TR) 
SO2 Group 2 Trading Program, under section 110 of the Clean 
Air Act and Sec.  52.39 of this chapter, as a means of mitigating 
interstate transport of fine particulates and sulfur dioxide.

Sec.  97.702  Definitions.

    The terms used in this subpart shall have the meanings set forth in 
this section as follows:
    Acid Rain Program means a multi-state SO2 and 
NOX air pollution control and emission reduction program 
established by the Administrator under title IV of the Clean Air Act 
and parts 72 through 78 of this chapter.
    Administrator means the Administrator of the United States 
Environmental Protection Agency or the Director of the Clean Air 
Markets Division (or its successor determined by the Administrator) of 
the United States Environmental Protection Agency, the Administrator's 
duly authorized representative under this subpart.
    Allocate or allocation means, with regard to TR SO2 
Group 2 allowances, the determination by the Administrator, State, or 
permitting authority, in accordance with this subpart and any SIP 
revision submitted by the State and approved by the Administrator under 
Sec.  52.39(g), (h), or (i) of this chapter, of the amount of such TR 
SO2 Group 2 allowances to be initially credited, at no cost 
to the recipient, to:
    (1) A TR SO2 Group 2 unit;
    (2) A new unit set-aside;
    (3) An Indian country new unit set-aside; or
    (4) An entity not listed in paragraphs (1) through (3) of this 
definition;
    (5) Provided that, if the Administrator, State, or permitting 
authority initially credits, to a TR SO2 Group 2 unit 
qualifying for an initial credit, a credit in the amount of zero TR 
SO2 Group 2 allowances, the TR SO2 Group 2 unit 
will be treated as being allocated an amount (i.e., zero) of TR 
SO2 Group 2 allowances.
    Allowable SO2 emission rate means, for a unit, the most stringent 
State or federal SO2 emission rate limit (in lb/MWhr or, if 
in lb/mmBtu, converted to lb/MWhr by multiplying it by the unit's heat 
rate in mmBtu/MWhr) that is applicable to the unit and covers the 
longest averaging period not exceeding one year.
    Allowance Management System means the system by which the 
Administrator records allocations, deductions, and transfers of TR 
SO2 Group 2 allowances under the TR SO2 Group 2 
Trading Program. Such allowances are allocated, recorded, held, 
deducted, or transferred only as whole allowances.
    Allowance Management System account means an account in the 
Allowance Management System established by the Administrator for 
purposes of recording the allocation, holding, transfer, or deduction 
of TR SO2 Group 2 allowances.
    Allowance transfer deadline means, for a control period in a given 
year, midnight of March 1 (if it is a business day), or midnight of the 
first business day thereafter (if March 1 is not a business day), 
immediately after such control period and is the deadline by which a TR 
SO2 Group 2 allowance transfer must be submitted for 
recordation in a TR SO2 Group 2 source's compliance account 
in order to be available for use in complying with the source's TR 
SO2 Group 2 emissions limitation for such control period in 
accordance with Sec. Sec.  97.706 and 97.724.
    Alternate designated representative means, for a TR SO2 
Group 2 source and each TR SO2 Group 2 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 this 
subpart, to act on behalf of the designated representative in matters 
pertaining to the TR SO2 Group 2 Trading Program. If the TR 
SO2 Group 2 source is also subject to the Acid Rain Program, 
TR NOX Annual Trading Program, or TR NOX Ozone 
Season Trading Program, then this natural person shall be the same 
natural person as the alternate designated representative, as defined 
in the respective program.
    Assurance account means an Allowance Management System account, 
established by the Administrator under Sec.  97.725(b)(3) for certain 
owners and operators of a group of one or more TR SO2 Group 
2 sources and units in a given State (and Indian country within the 
borders of such State), in which are held TR SO2 Group 2 
allowances available for use for a control period in a given year in

[[Page 48459]]

complying with the TR SO2 Group 2 assurance provisions in 
accordance with Sec. Sec.  97.706 and 97.725.
    Authorized account representative means, for a general account, the 
natural person who is authorized, in accordance with this subpart, to 
transfer and otherwise dispose of TR SO2 Group 2 allowances 
held in the general account and, for a TR SO2 Group 2 
source's compliance account, the designated representative of the 
source.
    Automated data acquisition and handling system or DAHS means the 
component of the continuous emission monitoring system, or other 
emissions monitoring system approved for use under this subpart, 
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 this subpart.
    Biomass means--
    (1) Any organic material grown for the purpose of being converted 
to energy;
    (2) Any organic byproduct of agriculture that can be converted into 
energy; or
    (3) Any material that can be converted into energy and is 
nonmerchantable for other purposes, that is segregated from other 
material that is nonmerchantable for other purposes, and that is;
    (i) A forest-related organic resource, including mill residues, 
precommercial thinnings, slash, brush, or byproduct from conversion of 
trees to merchantable material; or
    (ii) A wood material, including pallets, crates, dunnage, 
manufacturing and construction materials (other than pressure-treated, 
chemically-treated, or painted wood products), and landscape or right-
of-way tree trimmings.
    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 unit means a unit in which the energy input to the 
unit is first used to produce useful thermal energy, where at least 
some of the reject heat from the useful thermal energy application or 
process is then used for electricity production.
    Business day means a day that does not fall on a weekend or a 
federal holiday.
    Certifying official means a natural person who is:
    (1) For a corporation, a president, secretary, treasurer, or vice-
president of the corporation in charge of a principal business function 
or any other person who performs similar policy- or decision-making 
functions for the corporation;
    (2) For a partnership or sole proprietorship, a general partner or 
the proprietor respectively; or
    (3) For a local government entity or State, federal, or other 
public agency, a principal executive officer or ranking elected 
official.
    Clean Air Act means the Clean Air Act, 42 U.S.C. 7401, et seq.
    Coal means ``coal'' as defined in Sec.  72.2 of this chapter.
    Coal-derived fuel means any fuel (whether in a solid, liquid, or 
gaseous state) produced by the mechanical, thermal, or chemical 
processing of coal.
    Cogeneration system means an integrated group, at a source, of 
equipment (including a boiler, or combustion turbine, and a steam 
turbine generator) designed to produce useful thermal energy for 
industrial, commercial, heating, or cooling purposes and electricity 
through the sequential use of energy.
    Cogeneration unit means a stationary, fossil-fuel-fired boiler or 
stationary, fossil-fuel-fired combustion turbine that is a topping-
cycle unit or a bottoming-cycle unit:
    (1) Operating as part of a cogeneration system; and
    (2) Producing on an annual average basis--
    (i) For a topping-cycle 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 than 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 unit, useful power not less than 45 
percent of total energy input;
    (3) Provided that the requirements in paragraph (2) of this 
definition shall not apply to a calendar year referenced in paragraph 
(2) of this definition during which the unit did not operate at all;
    (4) Provided that the total energy input under paragraphs (2)(i)(B) 
and (2)(ii) of this definition shall equal the unit's total energy 
input from all fuel, except biomass if the unit is a boiler; and
    (5) Provided that, if, throughout its operation during the 12-month 
period or a calendar year referenced in paragraph (2) of this 
definition, a unit is operated as part of a cogeneration system and the 
cogeneration system meets on a system-wide basis the requirement in 
paragraph (2)(i)(B) or (2)(ii) of this definition, the unit shall be 
deemed to meet such requirement during that 12-month period or calendar 
year.
    Combustion turbine means an enclosed device comprising:
    (1) If the device is simple cycle, 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 device is combined cycle, the equipment described in 
paragraph (1) of this definition and any associated duct burner, heat 
recovery steam generator, and steam turbine.
    Commence commercial operation means, with regard to a unit:
    (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.  97.705.
    (i) For a unit that is a TR SO2 Group 2 unit under Sec.  
97.704 on the later of January 1, 2005 or the date the unit commences 
commercial operation as defined in the introductory text of paragraph 
(1) of this definition and that subsequently undergoes a physical 
change or is moved to a new location or source, such date shall remain 
the date of commencement of commercial operation of the unit, which 
shall continue to be treated as the same unit.
    (ii) For a unit that is a TR SO2 Group 2 unit under 
Sec.  97.704 on the later of January 1, 2005 or the date the unit 
commences commercial operation as defined in the introductory text of 
paragraph (1) of this definition and that is subsequently replaced by a 
unit at the same or a different source, such date shall remain the 
replaced unit's date of commencement of commercial operation, and the 
replacement unit shall be treated as a separate unit with a separate 
date for commencement of commercial operation as defined in paragraph 
(1) or (2) of this definition as appropriate.
    (2) Notwithstanding paragraph (1) of this definition and except as 
provided in Sec.  97.705, for a unit that is not a TR SO2 
Group 2 unit under Sec.  97.704 on the later of January 1, 2005 or the 
date the unit commences commercial operation as defined in introductory 
text of paragraph (1) of this definition, the unit's date for 
commencement of commercial operation shall be the date on which the 
unit becomes a TR SO2 Group 2 unit under Sec.  97.704.
    (i) For a unit with a date for commencement of commercial operation 
as defined in the introductory text of paragraph (2) of this definition

[[Page 48460]]

and that subsequently undergoes a physical change or is moved to a 
different location or source, such date shall remain the date of 
commencement of commercial operation of the unit, which shall continue 
to be treated as the same unit.
    (ii) For a unit with a date for commencement of commercial 
operation as defined in the introductory text of paragraph (2) of this 
definition and that is subsequently replaced by a unit at the same or a 
different source, such date shall remain the replaced unit's date of 
commencement of commercial operation, and the replacement unit shall be 
treated as a separate unit with a separate date for commencement of 
commercial operation as defined in paragraph (1) or (2) of this 
definition as appropriate.
    Common designated representative means, with regard to a control 
period in a given year, a designated representative where, as of April 
1 immediately after the allowance transfer deadline for such control 
period, the same natural person is authorized under Sec. Sec.  
97.713(a) and 97.715(a) as the designated representative for a group of 
one or more TR SO2 Group 2 sources and units located in a 
State (and Indian country within the borders of such State).
    Common designated representative's assurance level means, with 
regard to a specific common designated representative and a State (and 
Indian country within the borders of such State) and control period in 
a given year for which the State assurance level is exceeded as 
described in Sec.  97.706(c)(2)(iii), the common designated 
representative's share of the State SO2 Group 2 trading 
budget with the variability limit for the State for such control 
period.
    Common designated representative's share means, with regard to a 
specific common designated representative for a control period in a 
given year:
    (1) With regard to a total amount of SO2 emissions from 
all TR SO2 Group 2 units in a State (and Indian country 
within the borders of such State) during such control period, the total 
tonnage of SO2 emissions during such control period from a 
group of one or more TR SO2 Group 2 units located in such 
State (and such Indian country) and having the common designated 
representative for such control period;
    (2) With regard to a State SO2 Group 2 trading budget 
with the variability limit for such control period, the amount (rounded 
to the nearest allowance) equal to the sum of the total amount of TR 
SO2 Group 2 allowances allocated for such control period to 
a group of one or more TR SO2 Group 2 units located in the 
State (and Indian country within the borders of such State) and having 
the common designated representative for such control period and of the 
total amount of TR SO2 Group 2 allowances purchased by an 
owner or operator of such TR SO2 Group 2 units in an auction 
for such control period and submitted by the State or the permitting 
authority to the Administrator for recordation in the compliance 
accounts for such TR SO2 Group 2 units in accordance with 
the TR SO2 Group 2 allowance auction provisions in a SIP 
revision approved by the Administrator under Sec.  52.39(h) or (i) of 
this chapter, multiplied by the sum of the State SO2 Group 2 
trading budget under Sec.  97.710(a) and the State's variability limit 
under Sec.  97.710(b) for such control period and divided by such State 
SO2 Group 2 trading budget;
    (3) Provided that, in the case of a unit that operates during, but 
has no amount of TR SO2 Group 2 allowances allocated under 
Sec. Sec.  97.711 and 97.712 for, such control period, the unit shall 
be treated, solely for purposes of this definition, as being allocated 
an amount (rounded to the nearest allowance) of TR SO2 Group 
2 allowances for such control period equal to the unit's allowable 
SO2 emission rate applicable to such control period, 
multiplied by a capacity factor of 0.85 (if the unit is a boiler 
combusting any amount of coal or coal-derived fuel during such control 
period), 0.24 (if the unit is a simple combustion turbine during such 
control period), 0.67 (if the unit is a combined cycle turbine during 
such control period), 0.74 (if the unit is an integrated coal 
gasification combined cycle unit during such control period), or 0.36 
(for any other unit), multiplied by the unit's maximum hourly load as 
reported in accordance with this subpart and by 8,760 hours/control 
period, and divided by 2,000 lb/ton.
    Common stack means a single flue through which emissions from 2 or 
more units are exhausted.
    Compliance account means an Allowance Management System account, 
established by the Administrator for a TR SO2 Group 2 source 
under this subpart, in which any TR SO2 Group 2 allowance 
allocations to the TR SO2 Group 2 units at the source are 
recorded and in which are held any TR SO2 Group 2 allowances 
available for use for a control period in a given year in complying 
with the source's TR SO2 Group 2 emissions limitation in 
accordance with Sec. Sec.  97.706 and 97.724.
    Continuous emission monitoring system or CEMS means the equipment 
required under this subpart to sample, analyze, measure, and provide, 
by means of readings recorded at least once every 15 minutes and using 
an automated data acquisition and handling system (DAHS), a permanent 
record of SO2 emissions, stack gas volumetric flow rate, 
stack gas moisture content, and O2 or CO2 
concentration (as applicable), in a manner consistent with part 75 of 
this chapter and Sec. Sec.  97.730 through 97.735. The following 
systems are the principal types of continuous emission monitoring 
systems:
    (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 SO2 monitoring system, consisting of a 
SO2 pollutant concentration monitor and an automated data 
acquisition and 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 CO2 monitoring system, consisting of a 
CO2 pollutant concentration monitor (or an O2 
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 O2 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 starting January 1 of a calendar 
year, except as provided in Sec.  97.706(c)(3), and ending on December 
31 of the same year, inclusive.
    Designated representative means, for a TR SO2 Group 2 
source and each TR SO2 Group 2 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 this 
subpart, to represent and legally bind each owner and operator in 
matters pertaining to the TR SO2 Group 2 Trading Program. If 
the TR SO2 Group 2 source is also subject to the Acid Rain 
Program, TR NOX Annual Trading Program, or TR NOX 
Ozone Season Trading Program, then this natural person shall be the 
same

[[Page 48461]]

natural person as the designated representative, as defined in the 
respective program.
    Emissions means air pollutants exhausted from a unit or source into 
the atmosphere, as measured, recorded, and reported to the 
Administrator by the designated representative, and as modified by the 
Administrator:
    (1) In accordance with this subpart; and
    (2) With regard to a period before the unit or source is required 
to measure, record, and report such air pollutants in accordance with 
this subpart, in accordance with part 75 of this chapter.
    Excess emissions means any ton of emissions from the TR 
SO2 Group 2 units at a TR SO2 Group 2 source 
during a control period in a given year that exceeds the TR 
SO2 Group 2 emissions limitation for the source for such 
control period.
    Fossil fuel means--
    (1) Natural gas, petroleum, coal, or any form of solid, liquid, or 
gaseous fuel derived from such material; or
    (2) For purposes of applying the limitation on ``average annual 
fuel consumption of fossil fuel'' in Sec. Sec.  97.704(b)(2)(i)(B) and 
(ii), natural gas, petroleum, coal, or any form of solid, liquid, or 
gaseous fuel derived from such material for the purpose of creating 
useful heat.
    Fossil-fuel-fired means, with regard to a unit, combusting any 
amount of fossil fuel in 2005 or any calendar year thereafter.
    General account means an Allowance Management System account, 
established under this subpart, that is not a compliance account or an 
assurance account.
    Generator means a device that produces electricity.
    Gross electrical output means, for a 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, for a unit for a specified period of time, the 
product (in mmBtu/time) of the gross calorific value of the fuel (in 
mmBtu/lb) fed into the unit multiplied by the fuel feed rate (in lb of 
fuel/time), as measured, recorded, and reported to the Administrator by 
the designated representative and as modified by the Administrator in 
accordance with this subpart and excluding the heat derived from 
preheated combustion air, recirculated flue gases, or exhaust.
    Heat input rate means, for a unit, the amount of heat input (in 
mmBtu) divided by unit operating time (in hr) or, for a unit and 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.
    Heat rate means, for a unit, the unit's maximum design heat input 
(in Btu/hr), divided by the product of 1,000,000 Btu/mmBtu and the 
unit's maximum hourly load.
    Indian country means ``Indian country'' as defined in 18 U.S.C. 
1151.
    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, for a unit, the maximum amount of 
fuel per hour (in Btu/hr) that the unit is capable of combusting on a 
steady state basis as of the initial installation of the unit as 
specified by the manufacturer of the unit.
    Monitoring system means any monitoring system that meets the 
requirements of this subpart, including a continuous emission 
monitoring system, an alternative monitoring system, or an excepted 
monitoring system under part 75 of this chapter.
    Nameplate capacity means, starting from the initial installation of 
a generator, the maximum electrical generating output (in MWe, rounded 
to the nearest tenth) 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 of such installation 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 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 (in MWe, rounded to the nearest tenth) as of 
such completion as specified by the person conducting the physical 
change.
    Natural gas means ``natural gas'' as defined in Sec.  72.2 of this 
chapter.
    Newly affected TR SO2 Group 2 unit means a unit that was 
not a TR SO2 Group 2 unit when it began operating but that 
thereafter becomes a TR SO2 Group 2 unit.
    Operate or operation means, with regard to a unit, to combust fuel.
    Operator means, for a TR SO2 Group 2 source or a TR 
SO2 Group 2 unit at a source respectively, any person who 
operates, controls, or supervises a TR SO2 Group 2 unit at 
the source or the TR SO2 Group 2 unit and shall include, but 
not be limited to, any holding company, utility system, or plant 
manager of such source or unit.
    Owner means, for a TR SO2 Group 2 source or a TR 
SO2 Group 2 unit at a source respectively, any of the 
following persons:
    (1) Any holder of any portion of the legal or equitable title in a 
TR SO2 Group 2 unit at the source or the TR SO2 
Group 2 unit;
    (2) Any holder of a leasehold interest in a TR SO2 Group 
2 unit at the source or the TR SO2 Group 2 unit, 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 TR 
SO2 Group 2 unit; and
    (3) Any purchaser of power from a TR SO2 Group 2 unit at 
the source or the TR SO2 Group 2 unit under a life-of-the-
unit, firm power contractual arrangement.
    Permanently retired means, with regard to a unit, a unit that is 
unavailable for service and that the unit's owners and operators do not 
expect to return to service in the future.
    Permitting authority means ``permitting authority'' as defined in 
Sec. Sec.  70.2 and 71.2 of this chapter.
    Potential electrical output capacity means, for a unit, 33 percent 
of the 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 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 log, or by a notation made on the document,

[[Page 48462]]

information, or correspondence, by the Administrator in the regular 
course of business.
    Recordation, record, or recorded means, with regard to TR 
SO2 Group 2 allowances, the moving of TR SO2 
Group 2 allowances by the Administrator into, out of, or between 
Allowance Management System accounts, for purposes of allocation, 
auction, 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.
    Replacement, replace, or replaced means, with regard to a unit, the 
demolishing of a unit, or the permanent retirement and permanent 
disabling of a unit, and the construction of another unit (the 
replacement unit) to be used instead of the demolished or retired unit 
(the replaced unit).
    Sequential use of energy means:
    (1) The use of reject heat from electricity production in a useful 
thermal energy application or process; or
    (2) The use of reject heat from useful thermal energy application 
or process in electricity production.
    Serial number means, for a TR SO2 Group 2 allowance, the 
unique identification number assigned to each TR SO2 Group 2 
allowance by the Administrator.
    Solid waste incineration unit means a stationary, fossil-fuel-fired 
boiler or stationary, fossil-fuel-fired combustion turbine that is a 
``solid waste incineration unit'' as defined in section 129(g)(1) of 
the Clean Air Act.
    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. This definition does not change or 
otherwise affect the definition of ``major source'', ``stationary 
source'', or ``source'' as set forth and implemented in a title V 
operating permit program or any other program under the Clean Air Act.
    State means one of the States that is subject to the TR 
SO2 Group 2 Trading Program pursuant to Sec.  52.39(a), (c), 
(g), (h), and (i) 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;
    (4) Provided that compliance with any ``submission'' or ``service'' 
deadline shall be determined by the date of dispatch, transmission, or 
mailing and not the date of receipt.
    Topping-cycle unit means a unit in which the energy input to the 
unit is first used to produce useful power, including electricity, 
where at least some of the reject heat from the electricity production 
is then used to provide useful thermal energy.
    Total energy input means, for a unit, total energy of all forms 
supplied to the unit, excluding energy produced by the unit. Each form 
of energy supplied shall be measured by the lower heating value of that 
form of energy calculated as follows:

LHV = HHV - 10.55(W + 9H)

Where:

LHV = lower heating value of the form of energy in Btu/lb,
HHV = higher heating value of the form of energy in Btu/lb,
W = weight % of moisture in the form of energy, and
H = weight % of hydrogen in the form of energy.

    Total energy output means, for a unit, the sum of useful power and 
useful thermal energy produced by the unit.
    TR NOX Annual Trading Program means a multi-state NOX 
air pollution control and emission reduction program established in 
accordance with subpart AAAAA of this part and Sec.  52.38(a) of this 
chapter (including such a program that is revised in a SIP revision 
approved by the Administrator under Sec.  52.38(a)(3) or (4) of this 
chapter or that is established in a SIP revision approved by the 
Administrator under Sec.  52.38(a)(5) of this chapter), as a means of 
mitigating interstate transport of fine particulates and 
NOX.
    TR NOX Ozone Season Trading Program means a multi-state 
NOX air pollution control and emission reduction program 
established in accordance with subpart BBBBB of this part and Sec.  
52.38(b) of this chapter (including such a program that is revised in a 
SIP revision approved by the Administrator under Sec.  52.38(b)(3) or 
(4) of this chapter or that is established in a SIP revision approved 
by the Administrator under Sec.  52.38(b)(5) of this chapter), as a 
means of mitigating interstate transport of ozone and NOX.
    TR SO2 Group 2 allowance means a limited authorization issued and 
allocated or auctioned by the Administrator under this subpart, or by a 
State or permitting authority under a SIP revision approved by the 
Administrator under Sec.  52.39(g), (h), or (i) of this chapter, to 
emit one ton of SO2 during a control period of the specified 
calendar year for which the authorization is allocated or auctioned or 
of any calendar year thereafter under the TR SO2 Group 2 
Trading Program.
    TR SO2 Group 2 allowance deduction or deduct TR SO2 Group 2 
allowances means the permanent withdrawal of TR SO2 Group 2 
allowances by the Administrator from a compliance account (e.g., in 
order to account for compliance with the TR SO2 Group 2 
emissions limitation) or from an assurance account (e.g., in order to 
account for compliance with the assurance provisions under Sec. Sec.  
97.706 and 97.725).
    TR SO2 Group 2 allowances held or hold TR SO2 Group 2 allowances 
means the TR SO2 Group 2 allowances treated as included in 
an Allowance Management System account as of a specified point in time 
because at that time they:
    (1) Have been recorded by the Administrator in the account or 
transferred into the account by a correctly submitted, but not yet 
recorded, TR SO2 Group 2 allowance transfer in accordance 
with this subpart; and
    (2) Have not been transferred out of the account by a correctly 
submitted, but not yet recorded, TR SO2 Group 2 allowance 
transfer in accordance with this subpart.
    TR SO2 Group 2 emissions limitation means, for a TR SO2 
Group 2 source, the tonnage of SO2 emissions authorized in a 
control period by the TR SO2 Group 2 allowances available for deduction 
for the source under Sec.  97.724(a) for such control period.
    TR SO2 Group 2 source means a source that includes one or more TR 
SO2 Group 2 units.
    TR SO2 Group 2 Trading Program means a multi-state SO2 
air pollution control and emission reduction program established in 
accordance with this subpart and Sec.  52.39(a), (c), and (g) through 
(k) of this chapter (including such a program that is revised in a SIP 
revision approved by the Administrator under Sec.  52.39(g) or (h) of 
this chapter or that is established in a SIP revision approved by the 
Administrator under Sec.  52.39(i) of this chapter), as a means of 
mitigating interstate transport of fine particulates and 
SO2.
    TR SO2 Group 2 unit means a unit that is subject to the TR 
SO2 Group 2 Trading Program under Sec.  97.704.
    Unit means a stationary, fossil-fuel-fired boiler, stationary, 
fossil-fuel-fired combustion turbine, or other stationary, fossil-fuel-
fired combustion device. A unit that undergoes a physical change or is 
moved to a different location or source shall continue to be treated as 
the same unit. A unit (the replaced unit) that is replaced by another 
unit (the

[[Page 48463]]

replacement unit) at the same or a different source shall continue to 
be treated as the same unit, and the replacement unit shall be treated 
as a separate unit.
    Unit operating day means, with regard to a unit, a calendar day in 
which the unit combusts any fuel.
    Unit operating hour or hour of unit operation means, with regard to 
a unit, an hour in which the unit combusts any fuel.
    Useful power means, with regard to a unit, electricity or 
mechanical energy that the unit makes 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 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., in 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.  97.703  Measurements, abbreviations, and acronyms.

    Measurements, abbreviations, and acronyms used in this subpart are 
defined as follows:

Btu--British thermal unit
CO2--carbon dioxide
H2O--water
hr--hour
kW--kilowatt electrical
kWh--kilowatt hour
lb--pound
mmBtu--million Btu
MWe--megawatt electrical
MWh--megawatt hour
NOX--nitrogen oxides
O2--oxygen
ppm--parts per million
scfh--standard cubic feet per hour
SO2--sulfur dioxide
yr--year

Sec.  97.704  Applicability.

    (a) Except as provided in paragraph (b) of this section:
    (1) The following units in a State (and Indian country within the 
borders of such State) shall be TR SO2 Group 2 units, and 
any source that includes one or more such units shall be a TR 
SO2 Group 2 source, subject to the requirements of this 
subpart: Any stationary, fossil-fuel-fired boiler or stationary, 
fossil-fuel-fired combustion turbine serving at any time, on or after 
January 1, 2005, a generator with nameplate capacity of more than 25 
MWe producing electricity for sale.
    (2) If a stationary boiler or stationary combustion turbine that, 
under paragraph (a)(1) of this section, is not a TR SO2 
Group 2 unit begins to combust fossil fuel or to serve a generator with 
nameplate capacity of more than 25 MWe producing electricity for sale, 
the unit shall become a TR SO2 Group 2 unit as provided in 
paragraph (a)(1) of this section on the first date on which it both 
combusts fossil fuel and serves such generator.
    (b) Any unit in a State (and Indian country within the borders of 
such State) that otherwise is a TR SO2 Group 2 unit under 
paragraph (a) of this section and that meets the requirements set forth 
in paragraph (b)(1)(i) or (2)(i) of this section shall not be a TR 
SO2 Group 2 unit:
    (1)(i) Any unit:
    (A) Qualifying as a cogeneration unit throughout the later of 2005 
or the 12-month period starting on the date the unit first produces 
electricity and continuing to qualify as a cogeneration unit throughout 
each calendar year ending after the later of 2005 or such 12-month 
period; and
    (B) Not supplying in 2005 or any calendar year thereafter 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.
    (ii) If, after qualifying under paragraph (b)(1)(i) of this section 
as not being a TR SO2 Group 2 unit, a unit subsequently no 
longer meets all the requirements of paragraph (b)(1)(i) of this 
section, the unit shall become a TR SO2 Group 2 unit 
starting on the earlier of January 1 after the first calendar year 
during which the unit first no longer qualifies as a cogeneration unit 
or January 1 after the first calendar year during which the unit no 
longer meets the requirements of paragraph (b)(1)(i)(B) of this 
section. The unit shall thereafter continue to be a TR SO2 
Group 2 unit.
    (2)(i) Any unit:
    (A) Qualifying as a solid waste incineration unit throughout the 
later of 2005 or the 12-month period starting on the date the unit 
first produces electricity and continuing to qualify as a solid waste 
incineration unit throughout each calendar year ending after the later 
of 2005 or such 12-month period; and
    (B) With an average annual fuel consumption of fossil fuel for the 
first 3 consecutive calendar years of operation starting no earlier 
than 2005 of less than 20 percent (on a Btu basis) and an average 
annual fuel consumption of fossil fuel for any 3 consecutive calendar 
years thereafter of less than 20 percent (on a Btu basis).
    (ii) If, after qualifying under paragraph (b)(2)(i) of this section 
as not being a TR SO2 Group 2 unit, a unit subsequently no 
longer meets all the requirements of paragraph (b)(1)(i) of this 
section, the unit shall become a TR SO2 Group 2 unit 
starting on the earlier of January 1 after the first calendar year 
during which the unit first no longer qualifies as a solid waste 
incineration unit or January 1 after the first 3 consecutive calendar 
years after 2005 for which the unit has an average annual fuel 
consumption of fossil fuel of 20 percent or more. The unit shall 
thereafter continue to be a TR SO2 Group 2 unit.
    (c) A certifying official of an owner or operator of any unit or 
other equipment may submit a petition (including any supporting 
documents) to the Administrator at any time for a determination 
concerning the applicability, under paragraphs (a) and (b) of this 
section or a SIP revision approved under Sec.  52.39(h) or (i) of this 
chapter, of the TR SO2 Group 2 Trading Program to the unit 
or other equipment.
    (1) Petition content. The petition shall be in writing and include 
the identification of the unit or other equipment and the relevant 
facts about the unit or other equipment. The petition and any other 
documents provided to the Administrator in connection with the petition 
shall include the following certification statement, signed by the 
certifying official: ``I am authorized to make this submission on 
behalf of the owners and operators of the unit or other equipment 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) Response. The Administrator will issue a written response to 
the petition

[[Page 48464]]

and may request supplemental information determined by the 
Administrator to be relevant to such petition. The Administrator's 
determination concerning the applicability, under paragraphs (a) and 
(b) of this section, of the TR SO2 Group 2 Trading Program 
to the unit or other equipment shall be binding on any State or 
permitting authority unless the Administrator determines that the 
petition or other documents or information provided in connection with 
the petition contained significant, relevant errors or omissions.

Sec.  97.705  Retired unit exemption.

    (a)(1) Any TR SO2 Group 2 unit that is permanently 
retired shall be exempt from Sec.  97.706(b) and (c)(1), Sec.  97.724, 
and Sec. Sec.  97.730 through 97.735.
    (2) The exemption under paragraph (a)(1) of this section shall 
become effective the day on which the TR SO2 Group 2 unit is 
permanently retired. Within 30 days of the unit's permanent retirement, 
the designated representative shall submit a statement to the 
Administrator. The statement shall state, in a format prescribed by the 
Administrator, that the unit was permanently retired on a specified 
date and will comply with the requirements of paragraph (b) of this 
section.
    (b) Special provisions. (1) A unit exempt under paragraph (a) of 
this section shall not emit any SO2, 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 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 
designated representative of a unit exempt under paragraph (a) of this 
section shall comply with the requirements of the TR SO2 
Group 2 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 shall lose 
its exemption on the first date on which the unit resumes operation. 
Such unit shall be treated, for purposes of applying allocation, 
monitoring, reporting, and recordkeeping requirements under this 
subpart, as a unit that commences commercial operation on the first 
date on which the unit resumes operation.

Sec.  97.706  Standard requirements.

    (a) Designated representative requirements. The owners and 
operators shall comply with the requirement to have a designated 
representative, and may have an alternate designated representative, in 
accordance with Sec. Sec.  97.713 through 97.718.
    (b) Emissions monitoring, reporting, and recordkeeping 
requirements. (1) The owners and operators, and the designated 
representative, of each TR SO2 Group 2 source and each TR 
SO2 Group 2 unit at the source shall comply with the 
monitoring, reporting, and recordkeeping requirements of Sec. Sec.  
97.730 through 97.735.
    (2) The emissions data determined in accordance with Sec. Sec.  
97.730 through 97.735 shall be used to calculate allocations of TR 
SO2 Group 2 allowances under Sec. Sec.  97.711(a)(2) and (b) 
and 97.712 and to determine compliance with the TR SO2 Group 
2 emissions limitation and assurance provisions under paragraph (c) of 
this section, provided that, for each monitoring location from which 
mass emissions are reported, the mass emissions amount used in 
calculating such allocations and determining such compliance shall be 
the mass emissions amount for the monitoring location determined in 
accordance with Sec. Sec.  97.730 through 97.735 and rounded to the 
nearest ton, with any fraction of a ton less than 0.50 being deemed to 
be zero.
    (c) SO2 emissions requirements. (1) TR SO2 Group 2 
emissions limitation. (i) As of the allowance transfer deadline for a 
control period in a given year, the owners and operators of each TR 
SO2 Group 2 source and each TR SO2 Group 2 unit 
at the source shall hold, in the source's compliance account, TR 
SO2 Group 2 allowances available for deduction for such 
control period under Sec.  97.724(a) in an amount not less than the 
tons of total SO2 emissions for such control period from all 
TR SO2 Group 2 units at the source.
    (ii) If total SO2 emissions during a control period in a 
given year from the TR SO2 Group 2 units at a TR 
SO2 Group 2 source are in excess of the TR SO2 
Group 2 emissions limitation set forth in paragraph (c)(1)(i) of this 
section, then:
    (A) The owners and operators of the source and each TR 
SO2 Group 2 unit at the source shall hold the TR 
SO2 Group 2 allowances required for deduction under Sec.  
97.724(d); and
    (B) The owners and operators of the source and each TR 
SO2 Group 2 unit at the source shall pay any fine, penalty, 
or assessment or comply with any other remedy imposed, for the same 
violations, under the Clean Air Act, and each ton of such excess 
emissions and each day of such control period shall constitute a 
separate violation of this subpart and the Clean Air Act.
    (2) TR SO2 Group 2 assurance provisions. (i) If total 
SO2 emissions during a control period in a given year from 
all TR SO2 Group 2 units at TR SO2 Group 2 
sources in a State (and Indian country within the borders of such 
State) exceed the State assurance level, then the owners and operators 
of such sources and units in each group of one or more sources and 
units having a common designated representative for such control 
period, where the common designated representative's share of such 
SO2 emissions during such control period exceeds the common 
designated representative's assurance level for the State and such 
control period, shall hold (in the assurance account established for 
the owners and operators of such group) TR SO2 Group 2 
allowances available for deduction for such control period under Sec.  
97.725(a) in an amount equal to two times the product (rounded to the 
nearest whole number), as determined by the Administrator in accordance 
with Sec.  97.725(b), of multiplying--
    (A) The quotient of the amount by which the common designated 
representative's share of such SO2 emissions exceeds the 
common designated representative's assurance level divided by the sum 
of the amounts, determined for all common designated representatives 
for such sources and units in the State (and Indian country within the 
borders of such State) for such control period, by which each common 
designated representative's share of such SO2 emissions 
exceeds the respective common designated representative's assurance 
level; and
    (B) The amount by which total SO2 emissions from all TR 
SO2 Group 2 units at TR SO2 Group 2 sources in 
the State (and Indian country within the borders of such State) for 
such control period exceed the State assurance level.
    (ii) The owners and operators shall hold the TR SO2 
Group 2 allowances required under paragraph (c)(2)(i) of this section, 
as of midnight of November 1 (if it is a business day), or midnight of 
the first business day thereafter (if November 1 is not a business 
day), immediately after such control period.
    (iii) Total SO2 emissions from all TR SO2 
Group 2 units at TR SO2 Group 2

[[Page 48465]]

sources in a State (and Indian country within the borders of such 
State) during a control period in a given year exceed the State 
assurance level if such total SO2 emissions exceed the sum, 
for such control period, of the State SO2 Group 2 trading 
budget under Sec.  97.710(a) and the State's variability limit under 
Sec.  97.710(b).
    (iv) It shall not be a violation of this subpart or of the Clean 
Air Act if total SO2 emissions from all TR SO2 
Group 2 units at TR SO2 Group 2 sources in a State (and 
Indian country within the borders of such State) during a control 
period exceed the State assurance level or if a common designated 
representative's share of total SO2 emissions from the TR 
SO2 Group 2 units at TR SO2 Group 2 sources in a 
State (and Indian country within the borders of such State) during a 
control period exceeds the common designated representative's assurance 
level.
    (v) To the extent the owners and operators fail to hold TR 
SO2 Group 2 allowances for a control period in a given year 
in accordance with paragraphs (c)(2)(i) through (iii) of this section,
    (A) The owners and operators shall pay any fine, penalty, or 
assessment or comply with any other remedy imposed under the Clean Air 
Act; and
    (B) Each TR SO2 Group 2 allowance that the owners and 
operators fail to hold for such control period in accordance with 
paragraphs (c)(2)(i) through (iii) of this section and each day of such 
control period shall constitute a separate violation of this subpart 
and the Clean Air Act.
    (3) Compliance periods. A TR SO2 Group 2 unit shall be 
subject to the requirements under paragraphs (c)(1) and (c)(2) of this 
section for the control period starting on the later of January 1, 2012 
or the deadline for meeting the unit's monitor certification 
requirements under Sec.  97.730(b) and for each control period 
thereafter.
    (4) Vintage of allowances held for compliance. (i) A TR 
SO2 Group 2 allowance held for compliance with the 
requirements under paragraph (c)(1)(i) of this section for a control 
period in a given year must be a TR SO2 Group 2 allowance 
that was allocated for such control period or a control period in a 
prior year.
    (ii) A TR SO2 Group 2 allowance held for compliance with 
the requirements under paragraphs (c)(1)(ii)(A) and (2)(i) through 
(iii) of this section for a control period in a given year must be a TR 
SO2 Group 2 allowance that was allocated for a control 
period in a prior year or the control period in the given year or in 
the immediately following year.
    (5) Allowance Management System requirements. Each TR 
SO2 Group 2 allowance shall be held in, deducted from, or 
transferred into, out of, or between Allowance Management System 
accounts in accordance with this subpart.
    (6) Limited authorization. A TR SO2 Group 2 allowance is 
a limited authorization to emit one ton of SO2 during the 
control period in one year. Such authorization is limited in its use 
and duration as follows:
    (i) Such authorization shall only be used in accordance with the TR 
SO2 Group 2 Trading Program; and
    (ii) Notwithstanding any other provision of this subpart, the 
Administrator has the authority to terminate or limit the use and 
duration of such authorization to the extent the Administrator 
determines is necessary or appropriate to implement any provision of 
the Clean Air Act.
    (7) Property right. A TR SO2 Group 2 allowance does not 
constitute a property right.
    (d) Title V permit requirements. (1) No title V permit revision 
shall be required for any allocation, holding, deduction, or transfer 
of TR SO2 Group 2 allowances in accordance with this 
subpart.
    (2) A description of whether a unit is required to monitor and 
report SO2 emissions using a continuous emission monitoring 
system (under subpart H of part 75 of this chapter), an excepted 
monitoring system (under appendices D and E to part 75 of this 
chapter), a low mass emissions excepted monitoring methodology (under 
Sec.  75.19 of this chapter), or an alternative monitoring system 
(under subpart E of part 75 of this chapter) in accordance with 
Sec. Sec.  97.730 through 97.735 may be added to, or changed in, a 
title V permit using minor permit modification procedures in accordance 
with Sec. Sec.  70.7(e)(2) and 71.7(e)(1) of this chapter, provided 
that the requirements applicable to the described monitoring and 
reporting (as added or changed, respectively) are already incorporated 
in such permit. This paragraph explicitly provides that the addition 
of, or change to, a unit's description as described in the prior 
sentence is eligible for minor permit modification procedures in 
accordance with Sec. Sec.  70.7(e)(2)(i)(B) and 71.7(e)(1)(i)(B) of 
this chapter.
    (e) Additional recordkeeping and reporting requirements. (1) Unless 
otherwise provided, the owners and operators of each TR SO2 
Group 2 source and each TR SO2 Group 2 unit at the source 
shall keep on site at the source each of the following documents (in 
hardcopy or electronic format) 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 Administrator.
    (i) The certificate of representation under Sec.  97.716 for the 
designated representative for the source and each TR SO2 
Group 2 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 certificate of representation and 
documents are superseded because of the submission of a new certificate 
of representation under Sec.  97.716 changing the designated 
representative.
    (ii) All emissions monitoring information, in accordance with this 
subpart.
    (iii) Copies of all reports, compliance certifications, and other 
submissions and all records made or required under, or to demonstrate 
compliance with the requirements of, the TR SO2 Group 2 
Trading Program.
    (2) The designated representative of a TR SO2 Group 2 
source and each TR SO2 Group 2 unit at the source shall make 
all submissions required under the TR SO2 Group 2 Trading 
Program, except as provided in Sec.  97.718. This requirement does not 
change, create an exemption from, or or otherwise affect the 
responsible official submission requirements under a title V operating 
permit program in parts 70 and 71 of this chapter.
    (f) Liability. (1) Any provision of the TR SO2 Group 2 
Trading Program that applies to a TR SO2 Group 2 source or 
the designated representative of a TR SO2 Group 2 source 
shall also apply to the owners and operators of such source and of the 
TR SO2 Group 2 units at the source.
    (2) Any provision of the TR SO2 Group 2 Trading Program 
that applies to a TR SO2 Group 2 unit or the designated 
representative of a TR SO2 Group 2 unit shall also apply to 
the owners and operators of such unit.
    (g) Effect on other authorities. No provision of the TR 
SO2 Group 2 Trading Program or exemption under Sec.  97.705 
shall be construed as exempting or excluding the owners and operators, 
and the designated representative, of a TR SO2 Group 2 
source or TR SO2 Group 2 unit from compliance with any other 
provision of the applicable, approved State implementation plan, a 
federally enforceable permit, or the Clean Air Act.

[[Page 48466]]

Sec.  97.707  Computation of time.

    (a) Unless otherwise stated, any time period scheduled, under the 
TR SO2 Group 2 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 
TR SO2 Group 2 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 TR SO2 Group 2 Trading Program, is not a business 
day, the time period shall be extended to the next business day.

Sec.  97.708  Administrative appeal procedures.

    The administrative appeal procedures for decisions of the 
Administrator under the TR SO2 Group 2 Trading Program are 
set forth in part 78 of this chapter.

Sec.  97.709  [Reserved]

Sec.  97.710  State SO2 Group 2 trading budgets, new unit set-asides, 
Indian country new unit set-aside, and variability limits.

    (a) The State SO2 Group 2 trading budgets, new unit set-
asides, and Indian country new unit set-asides for allocations of TR 
SO2 Group 2 allowances for the control periods in 2012 and 
thereafter are as follows:

----------------------------------------------------------------------------------------------------------------
                                                          SO2 Group 2                         Indian country new
                                                        trading budget    New unit set-aside    unit set-aside
                        State                          (tons) * for 2012    (tons) for 2012     (tons) for 2012
                                                           and 2013            and 2013            and 2013
----------------------------------------------------------------------------------------------------------------
Alabama.............................................             216,033               4,321  ..................
Georgia.............................................             158,527               3,171  ..................
Kansas..............................................              41,528                 789                  42
Minnesota...........................................              41,981                 798                  42
Nebraska............................................              65,052               2,537                  65
South Carolina......................................              88,620               1,683                  89
Texas...............................................             243,954              11,954                 244
----------------------------------------------------------------------------------------------------------------

----------------------------------------------------------------------------------------------------------------
                                                          SO2 Group 2                         Indian country new
                                                        trading budget    New unit set-aside    unit set-aside
                        State                          (tons) * for 2014    (tons) for 2014     (tons) for 2014
                                                        and thereafter      and thereafter      and thereafter
----------------------------------------------------------------------------------------------------------------
Alabama.............................................             213,258               4,265  ..................
Georgia.............................................              95,231               1,905  ..................
Kansas..............................................              41,528                 789                  42
Minnesota...........................................              41,981                 798                  42
Nebraska............................................              65,052               2,537                  65
South Carolina......................................              88,620               1,683                  89
Texas...............................................             243,954              11,954                 244
----------------------------------------------------------------------------------------------------------------
* Each trading budget includes the new unit set-aside and, where applicable, the Indian country new unit set-
  aside and does not include the variability limit.

    (b) The States' variability limits for the State SO2 
Group 2 trading budgets for the control periods in 2012 and thereafter 
are as follows:

------------------------------------------------------------------------
                                                     Variability limits
            State              Variability limits       for 2014 and
                                for 2012 and 2013        thereafter
------------------------------------------------------------------------
Alabama.....................                38,886                38,386
Georgia.....................                28,535                17,142
Kansas......................                 7,475                 7,475
Minnesota...................                 7,557                 7,557
Nebraska....................                11,709                11,709
South Carolina..............                15,952                15,952
Texas.......................                43,912                43,912
------------------------------------------------------------------------

Sec.  97.711  Timing requirements for TR SO2 Group 2 allowance 
allocations.

    (a) Existing units. (1) TR SO2 Group 2 allowances are 
allocated, for the control periods in 2012 and each year thereafter, as 
provided in a notice of data availability issued by the Administrator. 
Providing an allocation to a unit in such notice does not constitute a 
determination that the unit is a TR SO2 Group 2 unit, and 
not providing an allocation to a unit in such notice does not 
constitute a determination that the unit is not a TR SO2 
Group 2 unit.
    (2) Notwithstanding paragraph (a)(1) of this section, if a unit 
provided an allocation in the notice of data availability issued under 
paragraph (a)(1) of this section does not operate, starting after 2011, 
during the control period in two consecutive years, such unit will not 
be allocated the TR SO2 Group 2 allowances provided in such 
notice for the unit for the control periods in the fifth year after the 
first such year and in each year after that fifth year. All TR 
SO2 Group 2 allowances that would otherwise have been 
allocated to such unit will be allocated to the new unit set-aside for 
the State where such unit is located and for the respective years 
involved. If such unit resumes operation, the Administrator will 
allocate TR SO2 Group 2 allowances to the unit in accordance 
with paragraph (b) of this section.

[[Page 48467]]

    (b) New units. (1) New unit set-asides. (i) By June 1, 2012 and 
June 1 of each year thereafter, the Administrator will calculate the TR 
SO2 Group 2 allowance allocation to each TR SO2 
Group 2 unit in a State, in accordance with Sec.  97.712(a)(2) through 
(7) and (12), for the control period in the year of the applicable 
calculation deadline under this paragraph and will promulgate a notice 
of data availability of the results of the calculations.
    (ii) For each notice of data availability required in paragraph 
(b)(1)(i) of this section, the Administrator will provide an 
opportunity for submission of objections to the calculations referenced 
in such notice.
    (A) Objections shall be submitted by the deadline specified in each 
notice of data availability required in paragraph (b)(1)(i) of this 
section and shall be limited to addressing whether the calculations 
(including the identification of the TR SO2 Group 2 units) 
are in accordance with Sec.  97.712(a)(2) through (7) and (12) and 
Sec. Sec.  97.706(b)(2) and 97.730 through 97.735.
    (B) The Administrator will adjust the calculations to the extent 
necessary to ensure that they are in accordance with the provisions 
referenced in paragraph (b)(1)(ii)(A) of this section. By August 1 
immediately after the promulgation of each notice of data availability 
required in paragraph (b)(1)(i) of this section, the Administrator will 
promulgate a notice of data availability of any adjustments that the 
Administrator determines to be necessary with regard to allocations 
under Sec.  97.712(a)(2) through (7) and (12) and the reasons for 
accepting or rejecting any objections submitted in accordance with 
paragraph (b)(1)(ii)(A) of this section.
    (iii) If the new unit set-aside for such control period contains 
any TR SO2 Group 2 allowances that have not been allocated 
in the applicable notice of data availability required in paragraph 
(b)(1)(ii) of this section, the Administrator will promulgate, by 
December 15 immediately after such notice, a notice of data 
availability that identifies any TR SO2 Group 2 units that 
commenced commercial operation during the period starting January 1 of 
the year before the year of such control period and ending November 30 
of year of such control period.
    (iv) For each notice of data availability required in paragraph 
(b)(1)(iii) of this section, the Administrator will provide an 
opportunity for submission of objections to the identification of TR 
SO2 annual units in such notice.
    (A) Objections shall be submitted by the deadline specified in each 
notice of data availability required in paragraph (b)(1)(iii) of this 
section and shall be limited to addressing whether the identification 
of TR SO2 annual units in such notice is in accordance with 
paragraph (b)(1)(iii) of this section.
    (B) The Administrator will adjust the identification of TR 
SO2 Group 2 units in the each notice of data availability 
required in paragraph (b)(1)(iii) of this section to the extent 
necessary to ensure that it is in accordance with paragraph (b)(1)(iii) 
of this section and will calculate the TR SO2 Group 2 
allowance allocation to each TR SO2 Group 2 unit in 
accordance with Sec.  97.712(a)(9), (10), and (12) and Sec. Sec.  
97.706(b)(2) and 97.730 through 97.735. By February 15 immediately 
after the promulgation of each notice of data availability required in 
paragraph (b)(1)(iii) of this section, the Administrator will 
promulgate a notice of data availability of any adjustments of the 
identification of TR SO2 Group 2 units that the 
Administrator determines to be necessary, the reasons for accepting or 
rejecting any objections submitted in accordance with paragraph 
(b)(1)(iv)(A) of this section, and the results of such calculations.
    (v) To the extent any TR SO2 Group 2 allowances are 
added to the new unit set-aside after promulgation of each notice of 
data availability required in paragraph (b)(1)(iv) of this section, the 
Administrator will promulgate additional notices of data availability, 
as deemed appropriate, of the allocation of such TR SO2 
Group 2 allowances in accordance with Sec.  97.712(a)(10).
    (2) Indian country new unit set-asides. (i) By June 1, 2012 and 
June 1 of each year thereafter, the Administrator will calculate the TR 
SO2 Group 2 allowance allocation to each TR SO2 
Group 2 unit in Indian country within the borders of a State, in 
accordance with Sec.  97.712(b)(2) through (7) and (12), for the 
control period in the year of the applicable calculation deadline under 
this paragraph and will promulgate a notice of data availability of the 
results of the calculations.
    (ii) For each notice of data availability required in paragraph 
(b)(2)(i) of this section, the Administrator will provide an 
opportunity for submission of objections to the calculations referenced 
in such notice.
    (A) Objections shall be submitted by the deadline specified in each 
notice of data availability required in paragraph (b)(2)(i) of this 
section and shall be limited to addressing whether the calculations 
(including the identification of the TR SO2 Group 2 units) 
are in accordance with Sec.  97.712(b)(2) through (7) and (12) and 
Sec. Sec.  97.706(b)(2) and 97.730 through 97.735.
    (B) The Administrator will adjust the calculations to the extent 
necessary to ensure that they are in accordance with the provisions 
referenced in paragraph (b)(2)(ii)(A) of this section. By August 1 
immediately after the promulgation of each notice of data availability 
required in paragraph (b)(2)(i) of this section, the Administrator will 
promulgate a notice of data availability of any adjustments that the 
Administrator determines to be necessary with regard to allocations 
under Sec.  97.712(b)(2) through (7) and (12) and the reasons for 
accepting or rejecting any objections submitted in accordance with 
paragraph (b)(2)(ii)(A) of this section.
    (iii) If the Indian country new unit set-aside for such control 
period contains any TR SO2 Group 2 allowances that have not 
been allocated in the applicable notice of data availability required 
in paragraph (b)(2)(ii) of this section, the Administrator will 
promulgate, by December 15 immediately after such notice, a notice of 
data availability that identifies any TR SO2 Group 2 units 
that commenced commercial operation during the period starting January 
1 of the year before the year of such control period and ending 
November 30 of year of such control period.
    (iv) For each notice of data availability required in paragraph 
(b)(2)(iii) of this section, the Administrator will provide an 
opportunity for submission of objections to the identification of TR 
SO2 annual units in such notice.
    (A) Objections shall be submitted by the deadline specified in each 
notice of data availability required in paragraph (b)(2)(iii) of this 
section and shall be limited to addressing whether the identification 
of TR SO2 annual units in such notice is in accordance with 
paragraph (b)(2)(iii) of this section.
    (B) The Administrator will adjust the identification of TR 
SO2 Group 2 units in the each notice of data availability 
required in paragraph (b)(2)(iii) of this section to the extent 
necessary to ensure that it is in accordance with paragraph (b)(2)(iii) 
of this section and will calculate the TR SO2 Group 2 
allowance allocation to each TR SO2 Group 2 unit in 
accordance with Sec.  97.712(b)(9), (10), and (12) and Sec. Sec.  
97.706(b)(2) and 97.730 through 97.735. By February 15 immediately 
after the promulgation of each notice of data availability required in 
paragraph (b)(2)(iii) of this section, the Administrator will 
promulgate a notice of data availability of any

[[Page 48468]]

adjustments of the identification of TR SO2 Group 2 units 
that the Administrator determines to be necessary, the reasons for 
accepting or rejecting any objections submitted in accordance with 
paragraph (b)(2)(iv)(A) of this section, and the results of such 
calculations.
    (v) To the extent any TR SO2 Group 2 allowances are 
added to the Indian country new unit set-aside after promulgation of 
each notice of data availability required in paragraph (b)(2)(iv) of 
this section, the Administrator will promulgate additional notices of 
data availability, as deemed appropriate, of the allocation of such TR 
SO2 Group 2 allowances in accordance with Sec.  
97.712(b)(10).
    (c) Units incorrectly allocated TR SO2 Group 2 allowances. (1) For 
each control period in 2012 and thereafter, if the Administrator 
determines that TR SO2 Group 2 allowances were allocated 
under paragraph (a) of this section, or under a provision of a SIP 
revision approved Sec.  52.39(g), (h), or (i) of this chapter, where 
such control period and the recipient are covered by the provisions of 
paragraph (c)(1)(i) of this section or were allocated under Sec.  
97.712(a)(2) through (7), (9), and (12) and (b)(2) through (7), (9), 
and (12), or under a provision of a SIP revision approved Sec.  
52.39(h) or (i) of this chapter, where such control period and the 
recipient are covered by the provisions of paragraph (c)(1)(ii) of this 
section, then the Administrator will notify the designated 
representative of the recipient and will act in accordance with the 
procedures set forth in paragraphs (c)(2) through (5) of this section:
    (i)(A) The recipient is not actually a TR SO2 Group 2 
unit under Sec.  97.704 as of January 1, 2012 and is allocated TR 
SO2 Group 2 allowances for such control period or, in the 
case of an allocation under a provision of a SIP revision approved 
under Sec.  52.39(g), (h), or (i) of this chapter, the recipient is not 
actually a TR SO2 Group 2 unit as of January 1, 2012 and is 
allocated TR SO2 Group 2 allowances for such control period 
that the SIP revision provides should be allocated only to recipients 
that are TR SO2 Group 2 units as of January 1, 2012; or
    (B) The recipient is not located as of January 1 of the control 
period in the State from whose SO2 Group 2 trading budget 
the TR SO2 Group 2 allowances allocated under paragraph (a) 
of this section, or under a provision of a SIP revision approved under 
Sec.  52.39(g), (h), or (i) of this chapter, were allocated for such 
control period.
    (ii) The recipient is not actually a TR SO2 Group 2 unit 
under Sec.  97.704 as of January 1 of such control period and is 
allocated TR SO2 Group 2 allowances for such control period 
or, in the case of an allocation under a provision of a SIP revision 
approved under Sec.  52.39(g), (h), or (i) of this chapter, the 
recipient is not actually a TR SO2 Group 2 unit as of 
January 1 of such control period and is allocated TR SO2 
Group 2 allowances for such control period that the SIP revision 
provides should be allocated only to recipients that are TR 
SO2 Group 2 units as of January 1 of such control period.
    (2) Except as provided in paragraph (c)(3) or (4) of this section, 
the Administrator will not record such TR SO2 Group 2 
allowances under Sec.  97.721.
    (3) If the Administrator already recorded such TR SO2 
Group 2 allowances under Sec.  97.721 and if the Administrator makes 
the determination under paragraph (c)(1) of this section before making 
deductions for the source that includes such recipient under Sec.  
97.724(b) for such control period, then the Administrator will deduct 
from the account in which such TR SO2 Group 2 allowances 
were recorded an amount of TR SO2 Group 2 allowances 
allocated for the same or a prior control period equal to the amount of 
such already recorded TR SO2 Group 2 allowances. The 
authorized account representative shall ensure that there are 
sufficient TR SO2 Group 2 allowances in such account for 
completion of the deduction.
    (4) If the Administrator already recorded such TR SO2 
Group 2 allowances under Sec.  97.721 and if the Administrator makes 
the determination under paragraph (c)(1) of this section after making 
deductions for the source that includes such recipient under Sec.  
97.724(b) for such control period, then the Administrator will not make 
any deduction to take account of such already recorded TR 
SO2 Group 2 allowances.
    (5)(i) With regard to the TR SO2 Group 2 allowances that 
are not recorded, or that are deducted as an incorrect allocation, in 
accordance with paragraphs (c)(2) and (3) of this section for a 
recipient under paragraph (c)(1)(i) of this section, the Administrator 
will:
    (A) Transfer such TR SO2 Group 2 allowances to the new 
unit set-aside for such control period for the State from whose 
SO2 Group 2 trading budget the TR SO2 Group 2 
allowances were allocated; or
    (B) If the State has a SIP revision approved under Sec.  52.39(h) 
or (i) covering such control period, include such TR SO2 
Group 2 allowances in the portion of the State SO2 Group 2 
trading budget that may be allocated for such control period in 
accordance with such SIP revision.
    (ii) With regard to the TR SO2 Group 2 allowances that 
were not allocated from the Indian country new unit set-aside for such 
control period and that are not recorded, or that are deducted as an 
incorrect allocation, in accordance with paragraphs (c)(2) and (3) of 
this section for a recipient under paragraph (c)(1)(ii) of this 
paragraph, the Administrator will:
    (A) Transfer such TR SO2 Group 2 allowances to the new 
unit set-aside for such control period; or
    (B) If the State has a SIP revision approved under Sec.  52.39(h) 
or (i) covering such control period, include such TR SO2 
Group 2 allowances in the portion of the State SO2 Group 2 
trading budget that may be allocated for such control period in 
accordance with such SIP revision.
    (iii) With regard to the TR SO2 Group 2 allowances that 
were allocated from the Indian country new unit set-aside for such 
control period and that are not recorded, or that are deducted as an 
incorrect allocation, in accordance with paragraphs (c)(2) and (3) of 
this section for a recipient under paragraph (c)(1)(ii) of this 
paragraph, the Administrator will transfer such TR SO2 Group 
2 allowances to the Indian country new unit set-aside for such control 
period.

Sec.  97.712  TR SO2 Group 2 allowance allocations to new units.

    (a) For each control period in 2012 and thereafter and for the TR 
SO2 Group 2 units in each State, the Administrator will 
allocate TR SO2 Group 2 allowances to the TR SO2 
Group 2 units as follows:
    (1) The TR SO2 Group 2 allowances will be allocated to 
the following TR SO2 Group 2 units, except as provided in 
paragraph (a)(10) of this section:
    (i) TR SO2 Group 2 units that are not allocated an 
amount of TR SO2 Group 2 allowances in the notice of data 
availability issued under Sec.  97.711(a)(1);
    (ii) TR SO2 Group 2 units whose allocation of an amount 
of TR SO2 Group 2 allowances for such control period in the 
notice of data availability issued under Sec.  97.711(a)(1) is covered 
by Sec.  97.711(c)(2) or (3);
    (iii) TR SO2 Group 2 units that are allocated an amount 
of TR SO2 Group 2 allowances for such control period in the 
notice of data availability issued under Sec.  97.711(a)(1), which 
allocation is terminated for such control period pursuant to Sec.  
97.711(a)(2), and that operate during the control period

[[Page 48469]]

immediately preceding such control period; or
    (iv) For purposes of paragraph (a)(9) of this section, TR 
SO2 Group 2 units under Sec.  97.711(c)(1)(ii) whose 
allocation of an amount of TR SO2 Group 2 allowances for 
such control period in the notice of data availability issued under 
Sec.  97.711(b)(1)(ii)(B) is covered by Sec.  97.711(c)(2) or (3).
    (2) The Administrator will establish a separate new unit set-aside 
for the State for each such control period. Each such new unit set-
aside will be allocated TR SO2 Group 2 allowances in an 
amount equal to the applicable amount of tons of SO2 
emissions as set forth in Sec.  97.710(a) and will be allocated 
additional TR SO2 Group 2 allowances (if any) in accordance 
with Sec. Sec.  97.711(a)(2) and (c)(5) and paragraph (b)(10) of this 
section.
    (3) The Administrator will determine, for each TR SO2 
Group 2 unit described in paragraph (a)(1) of this section, an 
allocation of TR SO2 Group 2 allowances for the later of the 
following control periods and for each subsequent control period:
    (i) The control period in 2012;
    (ii) The first control period after the control period in which the 
TR SO2 Group 2 unit commences commercial operation;
    (iii) For a unit described in paragraph (a)(1)(ii) of this section, 
the first control period in which the TR SO2 Group 2 unit 
operates in the State after operating in another jurisdiction and for 
which the unit is not already allocated one or more TR SO2 
Group 2 allowances; and
    (iv) For a unit described in paragraph (a)(1)(iii) of this section, 
the first control period after the control period in which the unit 
resumes operation.
    (4)(i) The allocation to each TR SO2 annual unit 
described in paragraph (a)(1)(i) through (iii) of this section and for 
each control period described in paragraph (a)(3) of this section will 
be an amount equal to the unit's total tons of SO2 emissions 
during the immediately preceding control period.
    (ii) The Administrator will adjust the allocation amount in 
paragraph (a)(4)(i) in accordance with paragraphs (a)(5) through (7) 
and (12) of this section.
    (5) The Administrator will calculate the sum of the TR 
SO2 Group 2 allowances determined for all such TR 
SO2 Group 2 units under paragraph (a)(4)(i) of this section 
in the State for such control period.
    (6) If the amount of TR SO2 Group 2 allowances in the 
new unit set-aside for the State for such control period is greater 
than or equal to the sum under paragraph (a)(5) of this section, then 
the Administrator will allocate the amount of TR SO2 Group 2 
allowances determined for each such TR SO2 Group 2 unit 
under paragraph (a)(4)(i) of this section.
    (7) If the amount of TR SO2 Group 2 allowances in the 
new unit set-aside for the State for such control period is less than 
the sum under paragraph (a)(5) of this section, then the Administrator 
will allocate to each such TR SO2 Group 2 unit the amount of 
the TR SO2 Group 2 allowances determined under paragraph 
(a)(4)(i) of this section for the unit, multiplied by the amount of TR 
SO2 Group 2 allowances in the new unit set-aside for such 
control period, divided by the sum under paragraph (a)(5) of this 
section, and rounded to the nearest allowance.
    (8) The Administrator will notify the public, through the 
promulgation of the notices of data availability described in Sec.  
97.711(b)(1)(i) and (ii), of the amount of TR SO2 Group 2 
allowances allocated under paragraphs (a)(2) through (7) and (12) of 
this section for such control period to each TR SO2 Group 2 
unit eligible for such allocation.
    (9) If, after completion of the procedures under paragraphs (a)(5) 
through (8) of this section for such control period, any unallocated TR 
SO2 Group 2 allowances remain in the new unit set-aside for 
the State for such control period, the Administrator will allocate such 
TR SO2 Group 2 allowances as follows--
    (i) The Administrator will determine, for each unit described in 
paragraph (a)(1) of this section that commenced commercial operation 
during the period starting January 1 of the year before the year of 
such control period and ending November 30 of year of such control 
period, the positive difference (if any) between the unit's emissions 
during such control period and the amount of TR SO2 Group 2 
allowances referenced in the notice of data availability required under 
Sec.  97.711(b)(1)(ii) for the unit for such control period;
    (ii) The Administrator will determine the sum of the positive 
differences determined under paragraph (a)(9)(i) of this section;
    (iii) If the amount of unallocated TR SO2 Group 2 
allowances remaining in the new unit set-aside for the State for such 
control period is greater than or equal to the sum determined under 
paragraph (a)(9)(ii) of this section, then the Administrator will 
allocate the amount of TR SO2 Group 2 allowances determined 
for each such TR SO2 Group 2 unit under paragraph (a)(9)(i) 
of this section; and
    (iv) If the amount of unallocated TR SO2 Group 2 
allowances remaining in the new unit set-aside for the State for such 
control period is less than the sum under paragraph (a)(9)(ii) of this 
section, then the Administrator will allocate to each such TR 
SO2 Group 2 unit the amount of the TR SO2 Group 2 
allowances determined under paragraph (a)(9)(i) of this section for the 
unit, multiplied by the amount of unallocated TR SO2 Group 2 
allowances remaining in the new unit set-aside for such control period, 
divided by the sum under paragraph (a)(9)(ii) of this section, and 
rounded to the nearest allowance.
    (10) If, after completion of the procedures under paragraphs (a)(9) 
and (12) of this section for such control period, any unallocated TR 
SO2 Group 2 allowances remain in the new unit set-aside for 
the State for such control period, the Administrator will allocate to 
each TR SO2 Group 2 unit that is in the State, is allocated 
an amount of TR SO2 Group 2 allowances in the notice of data 
availability issued under Sec.  97.711(a)(1), and continues to be 
allocated TR SO2 Group 2 allowances for such control period 
in accordance with Sec.  97.711(a)(2), an amount of TR SO2 
Group 2 allowances equal to the following: The total amount of such 
remaining unallocated TR SO2 Group 2 allowances in such new 
unit set-aside, multiplied by the unit's allocation under Sec.  
97.711(a) for such control period, divided by the remainder of the 
amount of tons in the applicable State SO2 Group 2 trading 
budget minus the sum of the amounts of tons in such new unit set-aside 
and the Indian country new unit set-aside for the State for such 
control period, and rounded to the nearest allowance.
    (11) The Administrator will notify the public, through the 
promulgation of the notices of data availability described in Sec.  
97.711(b)(1)(iii), (iv), and (v), of the amount of TR SO2 
Group 2 allowances allocated under paragraphs (a)(9), (10), and (12) of 
this section for such control period to each TR SO2 Group 2 
unit eligible for such allocation.
    (12)(i) Notwithstanding the requirements of paragraphs (a)(2) 
through (11) of this section, if the calculations of allocations of a 
new unit set-aside for a control period in a given year under paragraph 
(a)(7) of this section, paragraphs (a)(6) and (9)(iv) of this section, 
or paragraphs (a)(6), (9)(iii), and (10) of this section would 
otherwise result in total allocations of such new unit set-aside 
exceeding the total amount of such new unit set-aside, then the 
Administrator will adjust the results of the calculations under 
paragraph (a)(7), (9)(iv), or (10) of this section, as applicable, as 
follows. The Administrator will list the TR SO2 Group 2 
units in descending order based

[[Page 48470]]

on the amount of such units' allocations under paragraph (a)(7), 
(9)(iv), or (10) of this section, as applicable, and, in cases of equal 
allocation amounts, in alphabetical order of the relevant source's name 
and numerical order of the relevant unit's identification number, and 
will reduce each unit's allocation under paragraph (a)(7), (9)(iv), or 
(10) of this section, as applicable, by one TR SO2 Group 2 
allowance (but not below zero) in the order in which the units are 
listed and will repeat this reduction process as necessary, until the 
total allocations of such new unit set-aside equal the total amount of 
such new unit set-aside.
    (ii) Notwithstanding the requirements of paragraphs (a)(10) and 
(11) of this section, if the calculations of allocations of a new unit 
set-aside for a control period in a given year under paragraphs (a)(6), 
(9)(iii), and (10) of this section would otherwise result in a total 
allocations of such new unit set-aside less than the total amount of 
such new unit set-aside, then the Administrator will adjust the results 
of the calculations under paragraph (a)(10) of this section, as 
follows. The Administrator will list the TR SO2 Group 2 
units in descending order based on the amount of such units' 
allocations under paragraph (a)(10) of this section and, in cases of 
equal allocation amounts, in alphabetical order of the relevant 
source's name and numerical order of the relevant unit's identification 
number, and will increase each unit's allocation under paragraph 
(a)(10) of this section by one TR SO2 Group 2 allowance in 
the order in which the units are listed and will repeat this increase 
process as necessary, until the total allocations of such new unit set-
aside equal the total amount of such new unit set-aside.
    (b) For each control period in 2012 and thereafter and for the TR 
SO2 Group 2 units located in Indian country within the 
borders of each State, the Administrator will allocate TR 
SO2 Group 2 allowances to the TR SO2 Group 2 
units as follows:
    (1) The TR SO2 Group 2 allowances will be allocated to 
the following TR SO2 Group 2 units, except as provided in 
paragraph (b)(10) of this section:
    (i) TR SO2 Group 2 units that are not allocated an 
amount of TR SO2 Group 2 allowances in the notice of data 
availability issued under Sec.  97.711(a)(1); or
    (ii) For purposes of paragraph (b)(9) of this section, TR 
SO2 Group 2 units under Sec.  97.711(c)(1)(ii) whose 
allocation of an amount of TR SO2 Group 2 allowances for 
such control period in the notice of data availability issued under 
Sec.  97.711(b)(2)(ii)(B) is covered by Sec.  97.711(c)(2) or (3).
    (2) The Administrator will establish a separate Indian country new 
unit set-aside for the State for each such control period. Each such 
Indian country new unit set-aside will be allocated TR SO2 
Group 2 allowances in an amount equal to the applicable amount of tons 
of SO2 emissions as set forth in Sec.  97.710(a) and will be 
allocated additional TR SO2 Group 2 allowances (if any) in 
accordance with Sec.  97.711(c)(5).
    (3) The Administrator will determine, for each TR SO2 
Group 2 unit described in paragraph (b)(1) of this section, an 
allocation of TR SO2 Group 2 allowances for the later of the 
following control periods and for each subsequent control period:
    (i) The control period in 2012; and
    (ii) The first control period after the control period in which the 
TR SO2 Group 2 unit commences commercial operation.
    (4)(i) The allocation to each TR SO2 annual unit 
described in paragraph (b)(1)(i) of this section and for each control 
period described in paragraph (b)(3) of this section will be an amount 
equal to the unit's total tons of SO2 emissions during the 
immediately preceding control period.
    (ii) The Administrator will adjust the allocation amount in 
paragraph (b)(4)(i) in accordance with paragraphs (b)(5) through (7) 
and (12) of this section.
    (5) The Administrator will calculate the sum of the TR 
SO2 Group 2 allowances determined for all such TR 
SO2 Group 2 units under paragraph (b)(4)(i) of this section 
in Indian country within the borders of the State for such control 
period.
    (6) If the amount of TR SO2 Group 2 allowances in the 
Indian country new unit set-aside for the State for such control period 
is greater than or equal to the sum under paragraph (b)(5) of this 
section, then the Administrator will allocate the amount of TR 
SO2 Group 2 allowances determined for each such TR 
SO2 Group 2 unit under paragraph (b)(4)(i) of this section.
    (7) If the amount of TR SO2 Group 2 allowances in the 
Indian country new unit set-aside for the State for such control period 
is less than the sum under paragraph (b)(5) of this section, then the 
Administrator will allocate to each such TR SO2 Group 2 unit 
the amount of the TR SO2 Group 2 allowances determined under 
paragraph (b)(4)(i) of this section for the unit, multiplied by the 
amount of TR SO2 Group 2 allowances in the Indian country 
new unit set-aside for such control period, divided by the sum under 
paragraph (b)(5) of this section, and rounded to the nearest allowance.
    (8) The Administrator will notify the public, through the 
promulgation of the notices of data availability described in Sec.  
97.711(b)(2)(i) and (ii), of the amount of TR SO2 Group 2 
allowances allocated under paragraphs (b)(2) through (7) and (12) of 
this section for such control period to each TR SO2 Group 2 
unit eligible for such allocation.
    (9) If, after completion of the procedures under paragraphs (b)(5) 
through (8) of this section for such control period, any unallocated TR 
SO2 Group 2 allowances remain in the Indian country new unit 
set-aside for the State for such control period, the Administrator will 
allocate such TR SO2 Group 2 allowances as follows--
    (i) The Administrator will determine, for each unit described in 
paragraph (b)(1) of this section that commenced commercial operation 
during the period starting January 1 of the year before the year of 
such control period and ending November 30 of year of such control 
period, the positive difference (if any) between the unit's emissions 
during such control period and the amount of TR SO2 Group 2 
allowances referenced in the notice of data availability required under 
Sec.  97.711(b)(2)(ii) for the unit for such control period;
    (ii) The Administrator will determine the sum of the positive 
differences determined under paragraph (b)(9)(i) of this section;
    (iii) If the amount of unallocated TR SO2 Group 2 
allowances remaining in the Indian country new unit set-aside for the 
State for such control period is greater than or equal to the sum 
determined under paragraph (b)(9)(ii) of this section, then the 
Administrator will allocate the amount of TR SO2 Group 2 
allowances determined for each such TR SO2 Group 2 unit 
under paragraph (b)(9)(i) of this section; and
    (iv) If the amount of unallocated TR SO2 Group 2 
allowances remaining in the Indian country new unit set-aside for the 
State for such control period is less than the sum under paragraph 
(b)(9)(ii) of this section, then the Administrator will allocate to 
each such TR SO2 Group 2 unit the amount of the TR 
SO2 Group 2 allowances determined under paragraph (b)(9)(i) 
of this section for the unit, multiplied by the amount of unallocated 
TR SO2 Group 2 allowances remaining in the Indian country 
new unit set-aside for such control period, divided by the sum under 
paragraph (b)(9)(ii) of this section, and rounded to the nearest 
allowance.
    (10) If, after completion of the procedures under paragraphs (b)(9) 
and (12) of this section for such control

[[Page 48471]]

period, any unallocated TR SO2 Group 2 allowances remain in 
the Indian country new unit set-aside for the State for such control 
period, the Administrator will:
    (i) Transfer such unallocated TR SO2 Group 2 allowances 
to the new unit set-aside for the State for such control period; or
    (ii) If the State has a SIP revision approved under Sec.  52.39(g), 
(h), or (i) of this chapter covering such control period, include such 
unallocated TR SO2 Group 2 allowances in the portion of the 
State SO2 Group 2 trading budget that may be allocated for 
such control period in accordance with such SIP revision.
    (11) The Administrator will notify the public, through the 
promulgation of the notices of data availability described in Sec.  
97.711(b)(2)(iii), (iv), and (v), of the amount of TR SO2 
Group 2 allowances allocated under paragraphs (b)(9), (10), and (12) of 
this section for such control period to each TR SO2 Group 2 
unit eligible for such allocation.
    (12)(i) Notwithstanding the requirements of paragraphs (b)(2) 
through (11) of this section, if the calculations of allocations of an 
Indian country new unit set-aside for a control period in a given year 
under paragraph (b)(7) of this section, paragraphs (b)(6) and (9)(iv) 
of this section, or paragraphs (b)(6), (9)(iii), and (10) of this 
section would otherwise result in total allocations of such Indian 
country new unit set-aside exceeding the total amount of such Indian 
country new unit set-aside, then the Administrator will adjust the 
results of the calculations under paragraph (b)(7), (9)(iv), or (10) of 
this section, as applicable, as follows. The Administrator will list 
the TR SO2 Group 2 units in descending order based on the 
amount of such units' allocations under paragraph (b)(7), (9)(iv), or 
(10) of this section, as applicable, and, in cases of equal allocation 
amounts, in alphabetical order of the relevant source's name and 
numerical order of the relevant unit's identification number, and will 
reduce each unit's allocation under paragraph (b)(7), (9)(iv), or (10) 
of this section, as applicable, by one TR SO2 Group 2 
allowance (but not below zero) in the order in which the units are 
listed and will repeat this reduction process as necessary, until the 
total allocations of such Indian country new unit set-aside equal the 
total amount of such Indian country new unit set-aside.
    (ii) Notwithstanding the requirements of paragraphs (b)(10) and 
(11) of this section, if the calculations of allocations of an Indian 
country new unit set-aside for a control period in a given year under 
paragraphs (b)(6), (9)(iii), and (10) of this section would otherwise 
result in a total allocations of such Indian country new unit set-aside 
less than the total amount of such Indian country new unit set-aside, 
then the Administrator will adjust the results of the calculations 
under paragraph (b)(10) of this section, as follows. The Administrator 
will list the TR SO2 Group 2 units in descending order based 
on the amount of such units' allocations under paragraph (b)(10) of 
this section and, in cases of equal allocation amounts, in alphabetical 
order of the relevant source's name and numerical order of the relevant 
unit's identification number, and will increase each unit's allocation 
under paragraph (b)(10) of this section by one TR SO2 Group 
2 allowance in the order in which the units are listed and will repeat 
this increase process as necessary, until the total allocations of such 
Indian country new unit set-aside equal the total amount of such Indian 
country new unit set-aside.

Sec.  97.713  Authorization of designated representative and alternate 
designated representative.

    (a) Except as provided under Sec.  97.715, each TR SO2 
Group 2 source, including all TR SO2 Group 2 units at the 
source, shall have one and only one designated representative, with 
regard to all matters under the TR SO2 Group 2 Trading 
Program.
    (1) The designated representative shall be selected by an agreement 
binding on the owners and operators of the source and all TR 
SO2 Group 2 units at the source and shall act in accordance 
with the certification statement in Sec.  97.716(a)(4)(iii).
    (2) Upon and after receipt by the Administrator of a complete 
certificate of representation under Sec.  97.716:
    (i) The designated representative shall be authorized and shall 
represent and, by his or her representations, actions, inactions, or 
submissions, legally bind each owner and operator of the source and 
each TR SO2 Group 2 unit at the source in all matters 
pertaining to the TR SO2 Group 2 Trading Program, 
notwithstanding any agreement between the designated representative and 
such owners and operators; and
    (ii) The owners and operators of the source and each TR 
SO2 Group 2 unit at the source shall be bound by any 
decision or order issued to the designated representative by the 
Administrator regarding the source or any such unit.
    (b) Except as provided under Sec.  97.715, each TR SO2 
Group 2 source may have one and only one alternate designated 
representative, who may act on behalf of the designated representative. 
The agreement by which the alternate designated representative is 
selected shall include a procedure for authorizing the alternate 
designated representative to act in lieu of the designated 
representative.
    (1) The alternate designated representative shall be selected by an 
agreement binding on the owners and operators of the source and all TR 
SO2 Group 2 units at the source and shall act in accordance 
with the certification statement in Sec.  97.716(a)(4)(iii).
    (2) Upon and after receipt by the Administrator of a complete 
certificate of representation under Sec.  97.716,
    (i) The alternate designated representative shall be authorized;
    (ii) Any representation, action, inaction, or submission by the 
alternate designated representative shall be deemed to be a 
representation, action, inaction, or submission by the designated 
representative; and
    (iii) The owners and operators of the source and each TR 
SO2 Group 2 unit at the source shall be bound by any 
decision or order issued to the alternate designated representative by 
the Administrator regarding the source or any such unit.
    (c) Except in this section, Sec.  97.702, and Sec. Sec.  97.714 
through 97.718, whenever the term ``designated representative'' (as 
distinguished from the term ``common designated representative'') is 
used in this subpart, the term shall be construed to include the 
designated representative or any alternate designated representative.

Sec.  97.714  Responsibilities of designated representative and 
alternate designated representative.

    (a) Except as provided under Sec.  97.718 concerning delegation of 
authority to make submissions, each submission under the TR 
SO2 Group 2 Trading Program shall be made, signed, and 
certified by the designated representative or alternate designated 
representative for each TR SO2 Group 2 source and TR 
SO2 Group 2 unit for which the submission is made. Each such 
submission shall include the following certification statement by the 
designated representative or alternate 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

[[Page 48472]]

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.''
    (b) The Administrator will accept or act on a submission made for a 
TR SO2 Group 2 source or a TR SO2 Group 2 unit 
only if the submission has been made, signed, and certified in 
accordance with paragraph (a) of this section and Sec.  97.718.

Sec.  97.715  Changing designated representative and alternate 
designated representative; changes in owners and operators; changes in 
units at the source.

    (a) Changing designated representative. The designated 
representative may be changed at any time upon receipt by the 
Administrator of a superseding complete certificate of representation 
under Sec.  97.716. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
designated representative before the time and date when the 
Administrator receives the superseding certificate of representation 
shall be binding on the new designated representative and the owners 
and operators of the TR SO2 Group 2 source and the TR 
SO2 Group 2 units at the source.
    (b) Changing alternate designated representative. The alternate 
designated representative may be changed at any time upon receipt by 
the Administrator of a superseding complete certificate of 
representation under Sec.  97.716. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
alternate designated representative before the time and date when the 
Administrator receives the superseding certificate of representation 
shall be binding on the new alternate designated representative, the 
designated representative, and the owners and operators of the TR 
SO2 Group 2 source and the TR SO2 Group 2 units 
at the source.
    (c) Changes in owners and operators. (1) In the event an owner or 
operator of a TR SO2 Group 2 source or a TR SO2 
Group 2 unit at the source is not included in the list of owners and 
operators in the certificate of representation under Sec.  97.716, such 
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 designated representative and any alternate 
designated representative of the source or unit, and the decisions and 
orders of the Administrator, as if the owner or operator were included 
in such list.
    (2) Within 30 days after any change in the owners and operators of 
a TR SO2 Group 2 source or a TR SO2 Group 2 unit 
at the source, including the addition or removal of an owner or 
operator, the designated representative or any alternate designated 
representative shall submit a revision to the certificate of 
representation under Sec.  97.716 amending the list of owners and 
operators to reflect the change.
    (d) Changes in units at the source. Within 30 days of any change in 
which units are located at a TR SO2 Group 2 source 
(including the addition or removal of a unit), the designated 
representative or any alternate designated representative shall submit 
a certificate of representation under Sec.  97.716 amending the list of 
units to reflect the change.
    (1) If the change is the addition of a unit that operated (other 
than for purposes of testing by the manufacturer before initial 
installation) before being located at the source, then the certificate 
of representation shall identify, in a format prescribed by the 
Administrator, the entity from whom the unit was purchased or otherwise 
obtained (including name, address, telephone number, and facsimile 
number (if any)), the date on which the unit was purchased or otherwise 
obtained, and the date on which the unit became located at the source.
    (2) If the change is the removal of a unit, then the certificate of 
representation shall identify, in a format prescribed by the 
Administrator, the entity to which the unit was sold or that otherwise 
obtained the unit (including name, address, telephone number, and 
facsimile number (if any)), the date on which the unit was sold or 
otherwise obtained, and the date on which the unit became no longer 
located at the source.

Sec.  97.716  Certificate of representation.

    (a) A complete certificate of representation for a designated 
representative or an alternate designated representative shall include 
the following elements in a format prescribed by the Administrator:
    (1) Identification of the TR SO2 Group 2 source, and 
each TR SO2 Group 2 unit at the source, for which the 
certificate of representation is submitted, including source name, 
source category and NAICS code (or, in the absence of a NAICS code, an 
equivalent code), State, plant code, county, latitude and longitude, 
unit identification number and type, identification number and 
nameplate capacity (in MWe, rounded to the nearest tenth) of each 
generator served by each such unit, actual or projected date of 
commencement of commercial operation, and a statement of whether such 
source is located in Indian Country. If a projected date of 
commencement of commercial operation is provided, the actual date of 
commencement of commercial operation shall be provided when such 
information becomes available.
    (2) The name, address, e-mail address (if any), telephone number, 
and facsimile transmission number (if any) of the designated 
representative and any alternate designated representative.
    (3) A list of the owners and operators of the TR SO2 
Group 2 source and of each TR SO2 Group 2 unit at the 
source.
    (4) The following certification statements by the designated 
representative and any alternate designated representative--
    (i) ``I certify that I was selected as the designated 
representative or alternate designated representative, as applicable, 
by an agreement binding on the owners and operators of the source and 
each TR SO2 Group 2 unit at the source.''
    (ii) ``I certify that I have all the necessary authority to carry 
out my duties and responsibilities under the TR SO2 Group 2 
Trading Program on behalf of the owners and operators of the source and 
of each TR SO2 Group 2 unit at the source and that each such 
owner and operator shall be fully bound by my representations, actions, 
inactions, or submissions and by any decision or order issued to me by 
the Administrator regarding the source or unit.''
    (iii) ``Where there are multiple holders of a legal or equitable 
title to, or a leasehold interest in, a TR SO2 Group 2 unit, 
or where a utility or industrial customer purchases power from a TR 
SO2 Group 2 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 `designated representative' or `alternate 
designated representative', as applicable, and of the agreement by 
which I was selected to each owner and operator of the source and of 
each TR SO2 Group 2 unit at the source; and TR 
SO2 Group 2 allowances and proceeds of transactions 
involving TR SO2 Group 2 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 TR SO2 Group 2

[[Page 48473]]

allowances by contract, TR SO2 Group 2 allowances and 
proceeds of transactions involving TR SO2 Group 2 allowances 
will be deemed to be held or distributed in accordance with the 
contract.''
    (5) The signature of the designated representative and any 
alternate designated representative and the dates signed.
    (b) Unless otherwise required by the Administrator, documents of 
agreement referred to in the certificate of representation shall not be 
submitted to the Administrator. The Administrator shall not be under 
any obligation to review or evaluate the sufficiency of such documents, 
if submitted.

Sec.  97.717  Objections concerning designated representative and 
alternate designated representative.

    (a) Once a complete certificate of representation under Sec.  
97.716 has been submitted and received, the Administrator will rely on 
the certificate of representation unless and until a superseding 
complete certificate of representation under Sec.  97.716 is received 
by the Administrator.
    (b) Except as provided in paragraph (a) of this section, no 
objection or other communication submitted to the Administrator 
concerning the authorization, or any representation, action, inaction, 
or submission, of a designated representative or alternate designated 
representative shall affect any representation, action, inaction, or 
submission of the designated representative or alternate designated 
representative or the finality of any decision or order by the 
Administrator under the TR SO2 Group 2 Trading Program.
    (c) The Administrator will not adjudicate any private legal dispute 
concerning the authorization or any representation, action, inaction, 
or submission of any designated representative or alternate designated 
representative, including private legal disputes concerning the 
proceeds of TR SO2 Group 2 allowance transfers.

Sec.  97.718  Delegation by designated representative and alternate 
designated representative.

    (a) A designated representative may delegate, to one or more 
natural persons, his or her authority to make an electronic submission 
to the Administrator provided for or required under this subpart.
    (b) An alternate designated representative may delegate, to one or 
more natural persons, his or her authority to make an electronic 
submission to the Administrator provided for or required under this 
subpart.
    (c) In order to delegate authority to a natural person to make an 
electronic submission to the Administrator in accordance with paragraph 
(a) or (b) of this section, the designated representative or alternate 
designated representative, as appropriate, must submit to the 
Administrator a notice of delegation, in a format prescribed by the 
Administrator, that includes the following elements:
    (1) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of such designated 
representative or alternate designated representative;
    (2) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of each such natural person 
(referred to in this section as an ``agent'');
    (3) For each such natural person, a list of the type or types of 
electronic submissions under paragraph (a) or (b) of this section for 
which authority is delegated to him or her; and
    (4) The following certification statements by such designated 
representative or alternate designated representative:
    (i) ``I agree that any electronic submission to the Administrator 
that is made by an agent identified in this notice of delegation and of 
a type listed for such agent in this notice of delegation and that is 
made when I am a designated representative or alternate designated 
representative, as appropriate, and before this notice of delegation is 
superseded by another notice of delegation under 40 CFR 97.718(d) shall 
be deemed to be an electronic submission by me.''
    (ii) ``Until this notice of delegation is superseded by another 
notice of delegation under 40 CFR 97.718(d), I agree to maintain an e-
mail account and to notify the Administrator immediately of any change 
in my e-mail address unless all delegation of authority by me under 40 
CFR 97.718 is terminated.''.
    (d) A notice of delegation submitted under paragraph (c) of this 
section shall be effective, with regard to the designated 
representative or alternate designated representative identified in 
such notice, upon receipt of such notice by the Administrator and until 
receipt by the Administrator of a superseding notice of delegation 
submitted by such designated representative or alternate designated 
representative, as appropriate. The superseding notice of delegation 
may replace any previously identified agent, add a new agent, or 
eliminate entirely any delegation of authority.
    (e) Any electronic submission covered by the certification in 
paragraph (c)(4)(i) of this section and made in accordance with a 
notice of delegation effective under paragraph (d) of this section 
shall be deemed to be an electronic submission by the designated 
representative or alternate designated representative submitting such 
notice of delegation.

Sec.  97.719  [Reserved]

Sec.  97.720  Establishment of compliance accounts, assurance accounts, 
and general accounts.

    (a) Compliance accounts. Upon receipt of a complete certificate of 
representation under Sec.  97.716, the Administrator will establish a 
compliance account for the TR SO2 Group 2 source for which 
the certificate of representation was submitted, unless the source 
already has a compliance account. The designated representative and any 
alternate designated representative of the source shall be the 
authorized account representative and the alternate authorized account 
representative respectively of the compliance account.
    (b) Assurance accounts. The Administrator will establish assurance 
accounts for certain owners and operators and States in accordance with 
Sec.  97.725(b)(3).
    (c) General accounts. (1) Application for general account. (i) Any 
person may apply to open a general account, for the purpose of holding 
and transferring TR SO2 Group 2 allowances, by submitting to 
the Administrator a complete application for a general account. Such 
application shall designate one and only one authorized account 
representative and may designate one and only one alternate authorized 
account representative who may act on behalf of the authorized account 
representative.
    (A) The authorized account representative and alternate authorized 
account representative shall be selected by an agreement binding on the 
persons who have an ownership interest with respect to TR 
SO2 Group 2 allowances held in the general account.
    (B) The agreement by which the alternate authorized account 
representative is selected shall include a procedure for authorizing 
the alternate authorized account representative to act in lieu of the 
authorized account representative.
    (ii) A complete application for a general account shall include the 
following elements in a format prescribed by the Administrator:
    (A) Name, mailing address, e-mail address (if any), telephone 
number, and

[[Page 48474]]

facsimile transmission number (if any) of the authorized account 
representative and any alternate authorized account representative;
    (B) An identifying name for the general account;
    (C) A list of all persons subject to a binding agreement for the 
authorized account representative and any alternate authorized account 
representative to represent their ownership interest with respect to 
the TR SO2 Group 2 allowances held in the general account;
    (D) The following certification statement by the authorized account 
representative and any alternate authorized account representative: ``I 
certify that I was selected as the authorized account representative or 
the alternate authorized account representative, as applicable, by an 
agreement that is binding on all persons who have an ownership interest 
with respect to TR SO2 Group 2 allowances held in the 
general account. I certify that I have all the necessary authority to 
carry out my duties and responsibilities under the TR SO2 
Group 2 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 decision or order issued to me by the 
Administrator regarding the general account.''
    (E) The signature of the authorized account representative and any 
alternate authorized account representative and the dates signed.
    (iii) Unless otherwise required by the Administrator, documents of 
agreement referred to in the application for a general account shall 
not be submitted to the Administrator. The Administrator shall not be 
under any obligation to review or evaluate the sufficiency of such 
documents, if submitted.
    (2) Authorization of authorized account representative and 
alternate authorized account representative. (i) Upon receipt by the 
Administrator of a complete application for a general account under 
paragraph (b)(1) of this section, the Administrator will establish a 
general account for the person or persons for whom the application is 
submitted, and upon and after such receipt by the Administrator:
    (A) The authorized account representative of the general account 
shall be authorized and shall represent and, by his or her 
representations, actions, inactions, or submissions, legally bind each 
person who has an ownership interest with respect to TR SO2 
Group 2 allowances held in the general account in all matters 
pertaining to the TR SO2 Group 2 Trading Program, 
notwithstanding any agreement between the authorized account 
representative and such person.
    (B) Any alternate authorized account representative shall be 
authorized, and any representation, action, inaction, or submission by 
any alternate authorized account representative shall be deemed to be a 
representation, action, inaction, or submission by the authorized 
account representative.
    (C) Each person who has an ownership interest with respect to TR 
SO2 Group 2 allowances held in the general account shall be 
bound by any decision or order issued to the authorized account 
representative or alternate authorized account representative by the 
Administrator regarding the general account.
    (ii) Except as provided in paragraph (c)(5) of this section 
concerning delegation of authority to make submissions, each submission 
concerning the general account shall be made, signed, and certified by 
the authorized account representative or any alternate authorized 
account representative for the persons having an ownership interest 
with respect to TR SO2 Group 2 allowances held in the 
general account. Each such submission shall include the following 
certification statement by the authorized account representative or any 
alternate authorized account representative: ``I am authorized to make 
this submission on behalf of the persons having an ownership interest 
with respect to the TR SO2 Group 2 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) Except in this section, whenever the term ``authorized 
account representative'' is used in this subpart, the term shall be 
construed to include the authorized account representative or any 
alternate authorized account representative.
    (3) Changing authorized account representative and alternate 
authorized account representative; changes in persons with ownership 
interest. (i) The authorized account representative of 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 (c)(1) of this section. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
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 authorized account representative 
and the persons with an ownership interest with respect to the TR 
SO2 Group 2 allowances in the general account.
    (ii) The alternate authorized account representative of 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 (c)(1) of this section. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
alternate 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 authorized 
account representative, the authorized account representative, and the 
persons with an ownership interest with respect to the TR 
SO2 Group 2 allowances in the general account.
    (iii)(A) In the event a person having an ownership interest with 
respect to TR SO2 Group 2 allowances in the general account 
is not included in the list of such persons in the application for a 
general account, such 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 authorized account representative and 
any alternate authorized account representative of the account, and the 
decisions and orders of the Administrator, as if the person were 
included in such list.
    (B) Within 30 days after any change in the persons having an 
ownership interest with respect to SO2 Group 2 allowances in 
the general account, including the addition or removal of a person, the 
authorized account representative or any alternate 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 TR SO2 Group 2 allowances in the general 
account to include the change.
    (4) Objections concerning authorized account representative and 
alternate authorized account representative. (i) Once a complete 
application for a general account under paragraph (c)(1) of this 
section has been submitted and

[[Page 48475]]

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 (c)(4)(i) of this section, no 
objection or other communication submitted to the Administrator 
concerning the authorization, or any representation, action, inaction, 
or submission of the authorized account representative or any alternate 
authorized account representative of a general account shall affect any 
representation, action, inaction, or submission of the authorized 
account representative or any alternate authorized account 
representative or the finality of any decision or order by the 
Administrator under the TR SO2 Group 2 Trading Program.
    (iii) The Administrator will not adjudicate any private legal 
dispute concerning the authorization or any representation, action, 
inaction, or submission of the authorized account representative or any 
alternate authorized account representative of a general account, 
including private legal disputes concerning the proceeds of TR 
SO2 Group 2 allowance transfers.
    (5) Delegation by authorized account representative and alternate 
authorized account representative. (i) An authorized account 
representative of a general account may delegate, to one or more 
natural persons, his or her authority to make an electronic submission 
to the Administrator provided for or required under this subpart.
    (ii) An alternate authorized account representative of a general 
account may delegate, to one or more natural persons, his or her 
authority to make an electronic submission to the Administrator 
provided for or required under this subpart.
    (iii) In order to delegate authority to a natural person to make an 
electronic submission to the Administrator in accordance with paragraph 
(c)(5)(i) or (ii) of this section, the authorized account 
representative or alternate authorized account representative, as 
appropriate, must submit to the Administrator a notice of delegation, 
in a format prescribed by the Administrator, that includes the 
following elements:
    (A) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of such authorized account 
representative or alternate authorized account representative;
    (B) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of each such natural person 
(referred to in this section as an ``agent'');
    (C) For each such natural person, a list of the type or types of 
electronic submissions under paragraph (c)(5)(i) or (ii) of this 
section for which authority is delegated to him or her;
    (D) The following certification statement by such authorized 
account representative or alternate authorized account representative: 
``I agree that any electronic submission to the Administrator that is 
made by an agent identified in this notice of delegation and of a type 
listed for such agent in this notice of delegation and that is made 
when I am an authorized account representative or alternate authorized 
representative, as appropriate, and before this notice of delegation is 
superseded by another notice of delegation under 40 CFR 
97.720(c)(5)(iv) shall be deemed to be an electronic submission by 
me.''; and
    (E) The following certification statement by such authorized 
account representative or alternate authorized account representative: 
``Until this notice of delegation is superseded by another notice of 
delegation under 40 CFR 97.720(c)(5)(iv), I agree to maintain an e-mail 
account and to notify the Administrator immediately of any change in my 
e-mail address unless all delegation of authority by me under 40 CFR 
97.720(c)(5) is terminated.''.
    (iv) A notice of delegation submitted under paragraph (c)(5)(iii) 
of this section shall be effective, with regard to the authorized 
account representative or alternate authorized account representative 
identified in such notice, upon receipt of such notice by the 
Administrator and until receipt by the Administrator of a superseding 
notice of delegation submitted by such authorized account 
representative or alternate authorized account representative, as 
appropriate. The superseding notice of delegation may replace any 
previously identified agent, add a new agent, or eliminate entirely any 
delegation of authority.
    (v) Any electronic submission covered by the certification in 
paragraph (c)(5)(iii)(D) of this section and made in accordance with a 
notice of delegation effective under paragraph (c)(5)(iv) of this 
section shall be deemed to be an electronic submission by the 
designated representative or alternate designated representative 
submitting such notice of delegation.
    (6) Closing a general account. (i) The authorized account 
representative or alternate authorized account representative of a 
general account may submit to the Administrator a request to close the 
account. Such request shall include a correctly submitted TR 
SO2 Group 2 allowance transfer under Sec.  97.722 for any TR 
SO2 Group 2 allowances in the account to one or more other 
Allowance Management System accounts.
    (ii) If a general account has no TR SO2 Group 2 
allowance transfers to or from the account for a 12-month period or 
longer and does not contain any TR SO2 Group 2 allowances, 
the Administrator may notify the authorized account representative for 
the account that the account will be closed after 30 days after the 
notice is sent. The account will be closed after the 30-day period 
unless, before the end of the 30-day period, the Administrator receives 
a correctly submitted TR SO2 Group 2 allowance transfer 
under Sec.  97.722 to the account or a statement submitted by the 
authorized account representative or alternate authorized account 
representative demonstrating to the satisfaction of the Administrator 
good cause as to why the account should not be closed.
    (d) Account identification. The Administrator will assign a unique 
identifying number to each account established under paragraph (a), 
(b), or (c) of this section.
    (e) Responsibilities of authorized account representative and 
alternate authorized account representative. After the establishment of 
a compliance account or general account, the Administrator will accept 
or act on a submission pertaining to the account, including, but not 
limited to, submissions concerning the deduction or transfer of TR 
SO2 Group 2 allowances in the account, only if the 
submission has been made, signed, and certified in accordance with 
Sec. Sec.  97.714(a) and 97.718 or paragraphs (c)(2)(ii) and (c)(5) of 
this section.

Sec.  97.721  Recordation of TR SO2 Group 2 allowance allocations and 
auction results.

    (a) By November 7, 2011, the Administrator will record in each TR 
SO2 Group 2 source's compliance account the TR 
SO2 Group 2 allowances allocated to the TR SO2 
Group 2 units at the source in accordance with Sec.  97.711(a) for the 
control period in 2012.
    (b) By November 7, 2011, the Administrator will record in each TR 
SO2 Group 2 source's compliance account the TR 
SO2 Group 2 allowances allocated to the TR SO2 
Group 2 units at the source in accordance with Sec.  97.711(a) for the 
control period in 2013, unless the State in which the source is located 
notifies the

[[Page 48476]]

Administrator in writing by October 17, 2011 of the State's intent to 
submit to the Administrator a complete SIP revision by April 1, 2012 
meeting the requirements of Sec.  52.39(g)(1) through (4) of this 
chapter.
    (1) If, by April 1, 2012, the State does not submit to the 
Administrator such complete SIP revision, the Administrator will record 
by April 15, 2012 in each TR SO2 Group 2 source's compliance 
account the TR SO2 Group 2 allowances allocated to the TR 
SO2 Group 2 units at the source in accordance with Sec.  
97.711(a) for the control period in 2013.
    (2) If the State submits to the Administrator by April 1, 2012, and 
the Administrator approves by October 1, 2012, such complete SIP 
revision, the Administrator will record by October 1, 2012 in each TR 
SO2 Group 2 source's compliance account the TR 
SO2 Group 2 allowances allocated to the TR SO2 
Group 2 units at the source as provided in such approved, complete SIP 
revision for the control period in 2013.
    (3) If the State submits to the Administrator by April 1, 2012, and 
the Administrator does not approve by October 1, 2012, such complete 
SIP revision, the Administrator will record by October 1, 2012 in each 
TR SO2 Group 2 source's compliance account the TR 
SO2 Group 2 allowances allocated to the TR SO2 
Group 2 units at the source in accordance with Sec.  97.711(a) for the 
control period in 2013.
    (c) By July 1, 2013, the Administrator will record in each TR 
SO2 Group 2 source's compliance account the TR 
SO2 Group 2 allowances allocated to the TR SO2 
Group 2 units at the source, or in each appropriate Allowance 
Management System account the TR SO2 Group 2 allowances 
auctioned to TR SO2 Group 2 units, in accordance with Sec.  
97.711(a), or with a SIP revision approved under Sec.  52.39(h) or (i) 
of this chapter, for the control period in 2014 and 2015.
    (d) By July 1, 2014, the Administrator will record in each TR 
SO2 Group 2 source's compliance account the TR 
SO2 Group 2 allowances allocated to the TR SO2 
Group 2 units at the source, or in each appropriate Allowance 
Management System account the TR SO2 Group 2 allowances 
auctioned to TR SO2 Group 2 units, in accordance with Sec.  
97.711(a), or with a SIP revision approved under Sec.  52.39(h) or (i) 
of this chapter, for the control period in 2016 and 2017.
    (e) By July 1, 2015, the Administrator will record in each TR 
SO2 Group 2 source's compliance account the TR 
SO2 Group 2 allowances allocated to the TR SO2 
Group 2 units at the source, or in each appropriate Allowance 
Management System account the TR SO2 Group 2 allowances 
auctioned to TR SO2 Group 2 units, in accordance with Sec.  
97.711(a), or with a SIP revision approved under Sec.  52.39(h) or (i) 
of this chapter, for the control period in 2018 and 2019.
    (f) By July 1, 2016 and July 1 of each year thereafter, the 
Administrator will record in each TR SO2 Group 2 source's 
compliance account the TR SO2 Group 2 allowances allocated 
to the TR SO2 Group 2 units at the source, or in each 
appropriate Allowance Management System account the TR SO2 
Group 2 allowances auctioned to TR SO2 Group 2 units, in 
accordance with Sec.  97.711(a), or with a SIP revision approved under 
Sec.  52.39(h) and (i) of this chapter, for the control period in the 
fourth year after the year of the applicable recordation deadline under 
this paragraph.
    (g) By August 1, 2012 and August 1 of each year thereafter, the 
Administrator will record in each TR SO2 Group 2 source's 
compliance account the TR SO2 Group 2 allowances allocated 
to the TR SO2 Group 2 units at the source, or in each 
appropriate Allowance Management System account the TR SO2 
Group 2 allowances auctioned to TR SO2 Group 2 units, in 
accordance with Sec.  97.712(a)(2) through (8) and (12), or with a SIP 
revision approved under Sec.  52.39(h) and (i) of this chapter, for the 
control period in the year of the applicable recordation deadline under 
this paragraph.
    (h) By August 1, 2012 and August 1 of each year thereafter, the 
Administrator will record in each TR SO2 Group 2 source's 
compliance account the TR SO2 Group 2 allowances allocated 
to the TR SO2 Group 2 units at the source in accordance with 
Sec.  97.712(b)(2) through (8) and (12) for the control period in the 
year of the applicable recordation deadline under this paragraph.
    (i) By February 15, 2013 and February 15 of each year thereafter, 
the Administrator will record in each TR SO2 Group 2 
source's compliance account the TR SO2 Group 2 allowances 
allocated to the TR SO2 Group 2 units at the source in 
accordance with Sec.  97.712(a)(9) through (12), for the control period 
in the year before the year of the applicable recordation deadline 
under this paragraph.
    (j) By the date on which any allocation or auction results, other 
than an allocation or auction results, described in paragraphs (a) 
through (i) of this section, of TR SO2 Group 2 allowances to 
a recipient is made by or are submitted to the Administrator in 
accordance with Sec.  97.711 or Sec.  97.712 or with a SIP revision 
approved under Sec.  52.39(h) or (i) of this chapter, the Administrator 
will record such allocation or auction results in the appropriate 
Allowance Management System account.
    (k) When recording the allocation or auction of TR SO2 
Group 2 allowances to a TR SO2 Group 2 unit or other entity 
in an Allowance Management System account, the Administrator will 
assign each TR SO2 Group 2 allowance a unique identification 
number that will include digits identifying the year of the control 
period for which the TR SO2 Group 2 allowance is allocated 
or auctioned.

Sec.  97.722  Submission of TR SO2 Group 2 allowance transfers.

    (a) An authorized account representative seeking recordation of a 
TR SO2 Group 2 allowance transfer shall submit the transfer 
to the Administrator.
    (b) A TR SO2 Group 2 allowance transfer shall be 
correctly submitted if:
    (1) The transfer includes the following elements, in a format 
prescribed by the Administrator:
    (i) The account numbers established by the Administrator for both 
the transferor and transferee accounts;
    (ii) The serial number of each TR SO2 Group 2 allowance 
that is in the transferor account and is to be transferred; and
    (iii) The name and signature of the authorized account 
representative of the transferor account and the date signed; and
    (2) When the Administrator attempts to record the transfer, the 
transferor account includes each TR SO2 Group 2 allowance 
identified by serial number in the transfer.

Sec.  97.723  Recordation of TR SO2 Group 2 allowance transfers.

    (a) Within 5 business days (except as provided in paragraph (b) of 
this section) of receiving a TR SO2 Group 2 allowance 
transfer that is correctly submitted under Sec.  97.722, the 
Administrator will record a TR SO2 Group 2 allowance 
transfer by moving each TR SO2 Group 2 allowance from the 
transferor account to the transferee account as specified in the 
transfer.
    (b) A TR SO2 Group 2 allowance transfer to or from a 
compliance account that is submitted for recordation after the 
allowance transfer deadline for a control period and that includes any 
TR SO2 Group 2 allowances allocated for any control period 
before such allowance transfer deadline will not be recorded until 
after the Administrator completes the deductions from such

[[Page 48477]]

compliance account under Sec.  97.724 for the control period 
immediately before such allowance transfer deadline.
    (c) Where a TR SO2 Group 2 allowance transfer is not 
correctly submitted under Sec.  97.722, the Administrator will not 
record such transfer.
    (d) Within 5 business days of recordation of a TR SO2 
Group 2 allowance transfer under paragraphs (a) and (b) of the section, 
the Administrator will notify the authorized account representatives of 
both the transferor and transferee accounts.
    (e) Within 10 business days of receipt of a TR SO2 Group 
2 allowance transfer that is not correctly submitted under Sec.  
97.722, the Administrator will notify the 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.

Sec.  97.724  Compliance with TR SO2 Group 2 emissions limitation.

    (a) Availability for deduction for compliance. TR SO2 
Group 2 allowances are available to be deducted for compliance with a 
source's TR SO2 Group 2 emissions limitation for a control 
period in a given year only if the TR SO2 Group 2 
allowances:
    (1) Were allocated for such control period or a control period in a 
prior year; and
    (2) Are held in the source's compliance account as of the allowance 
transfer deadline for such control period.
    (b) Deductions for compliance. After the recordation, in accordance 
with Sec.  97.723, of TR SO2 Group 2 allowance transfers 
submitted by the allowance transfer deadline for a control period in a 
given year, the Administrator will deduct from each source's compliance 
account TR SO2 Group 2 allowances available under paragraph 
(a) of this section in order to determine whether the source meets the 
TR SO2 Group 2 emissions limitation for such control period, 
as follows:
    (1) Until the amount of TR SO2 Group 2 allowances 
deducted equals the number of tons of total SO2 emissions 
from all TR SO2 Group 2 units at the source for such control 
period; or
    (2) If there are insufficient TR SO2 Group 2 allowances 
to complete the deductions in paragraph (b)(1) of this section, until 
no more TR SO2 Group 2 allowances available under paragraph 
(a) of this section remain in the compliance account.
    (c)(1) Identification of TR SO2 Group 2 allowances by serial 
number. The authorized account representative for a source's compliance 
account may request that specific TR SO2 Group 2 allowances, 
identified by serial number, in the compliance account be deducted for 
emissions or excess emissions for a control period in a given year in 
accordance with paragraph (b) or (d) of this section. In order to be 
complete, such request shall be submitted to the Administrator by the 
allowance transfer deadline for such control period and include, in a 
format prescribed by the Administrator, the identification of the TR 
SO2 Group 2 source and the appropriate serial numbers.
    (2) First-in, first-out. The Administrator will deduct TR 
SO2 Group 2 allowances under paragraph (b) or (d) of this 
section from the source's compliance account in accordance with a 
complete request under paragraph (c)(1) of this section or, in the 
absence of such request or in the case of identification of an 
insufficient amount of TR SO2 Group 2 allowances in such 
request, on a first-in, first-out accounting basis in the following 
order:
    (i) Any TR SO2 Group 2 allowances that were allocated to 
the units at the source and not transferred out of the compliance 
account, in the order of recordation; and then
    (ii) Any TR SO2 Group 2 allowances that were allocated 
to any unit and transferred to and recorded in the compliance account 
pursuant to this subpart, in the order of recordation.
    (d) Deductions for excess emissions. After making the deductions 
for compliance under paragraph (b) of this section for a control period 
in a year in which the TR SO2 Group 2 source has excess 
emissions, the Administrator will deduct from the source's compliance 
account an amount of TR SO2 Group 2 allowances, allocated 
for a control period in a prior year or the control period in the year 
of the excess emissions or in the immediately following year, equal to 
two times the number of tons of the source's excess emissions.
    (e) Recordation of deductions. The Administrator will record in the 
appropriate compliance account all deductions from such an account 
under paragraphs (b) and (d) of this section.

Sec.  97.725  Compliance with TR SO2 Group 2 assurance provisions.

    (a) Availability for deduction. TR SO2 Group 2 
allowances are available to be deducted for compliance with the TR 
SO2 Group 2 assurance provisions for a control period in a 
given year by the owners and operators of a group of one or more TR 
SO2 Group 2 sources and units in a State (and Indian country 
within the borders of such State) only if the TR SO2 Group 2 
allowances:
    (1) Were allocated for a control period in a prior year or the 
control period in the given year or in the immediately following year; 
and
    (2) Are held in the assurance account, established by the 
Administrator for such owners and operators of such group of TR 
SO2 Group 2 sources and units in such State (and Indian 
country within the borders of such State) under paragraph (b)(3) of 
this section, as of the deadline established in paragraph (b)(4) of 
this section.
    (b) Deductions for compliance. The Administrator will deduct TR 
SO2 Group 2 allowances available under paragraph (a) of this 
section for compliance with the TR SO2 Group 2 assurance 
provisions for a State for a control period in a given year in 
accordance with the following procedures:
    (1) By June 1, 2013 and June 1 of each year thereafter, the 
Administrator will:
    (i) Calculate, for each State (and Indian country within the 
borders of such State), the total SO2 emissions from all TR 
SO2 Group 2 units at TR SO2 Group 2 sources in 
the State (and Indian country within the borders of such State) during 
the control period in the year before the year of this calculation 
deadline and the amount, if any, by which such total SO2 
emissions exceed the State assurance level as described in Sec.  
97.706(c)(2)(iii); and
    (ii) Promulgate a notice of data availability of the results of the 
calculations required in paragraph (b)(1)(i) of this section, including 
separate calculations of the SO2 emissions from each TR 
SO2 Group 2 source.
    (2) For each notice of data availability required in paragraph 
(b)(1)(ii) of this section and for any State (and Indian country within 
the borders of such State) identified in such notice as having TR 
SO2 Group 2 units with total SO2 emissions 
exceeding the State assurance level for a control period in a given 
year, as described in Sec.  97.706(c)(2)(iii):
    (i) By July 1 immediately after the promulgation of such notice, 
the designated representative of each TR SO2 Group 2 source 
in each such State (and Indian country within the borders of such 
State) shall submit a statement, in a format prescribed by the 
Administrator, providing for each TR SO2 Group 2 unit (if 
any) at the source that operates during, but is not allocated an amount 
of TR SO2 Group 2 allowances for, such control period, the 
unit's allowable SO2 emission rate for such control period 
and, if such rate is

[[Page 48478]]

expressed in lb per mmBtu, the unit's heat rate.
    (ii) By August 1 immediately after the promulgation of such notice, 
the Administrator will calculate, for each such State (and Indian 
country within the borders of such State) and such control period and 
each common designated representative for such control period for a 
group of one or more TR SO2 Group 2 sources and units in the 
State (and Indian country within the borders of such State), the common 
designated representative's share of the total SO2 emissions 
from all TR SO2 Group 2 units at TR SO2 Group 2 
sources in the State (and Indian country within the borders of such 
State), the common designated representative's assurance level, and the 
amount (if any) of TR SO2 Group 2 allowances that the owners 
and operators of such group of sources and units must hold in 
accordance with the calculation formula in Sec.  97.706(c)(2)(i) and 
will promulgate a notice of data availability of the results of these 
calculations.
    (iii) The Administrator will provide an opportunity for submission 
of objections to the calculations referenced by the notice of data 
availability required in paragraph (b)(2)(ii) of this section and the 
calculations referenced by the relevant notice of data availability 
required in paragraph (b)(1)(i) of this section.
    (A) Objections shall be submitted by the deadline specified in such 
notice and shall be limited to addressing whether the calculations 
referenced in the relevant notice required under paragraph (b)(1)(ii) 
of this section and referenced in the notice required under paragraph 
(b)(2)(ii) of this section are in accordance with Sec.  
97.706(c)(2)(iii), Sec. Sec.  97.706(b) and 97.730 through 97.735, the 
definitions of ``common designated representative'', ``common 
designated representative's assurance level'', and ``common designated 
representative's share'' in Sec.  97.702, and the calculation formula 
in Sec.  97.706(c)(2)(i).
    (B) The Administrator will adjust the calculations to the extent 
necessary to ensure that they are in accordance with the provisions 
referenced in paragraph (b)(2)(iii)(A) of this section. By October 1 
immediately after the promulgation of such notice, the Administrator 
will promulgate a notice of data availability of any adjustments that 
the Administrator determines to be necessary and the reasons for 
accepting or rejecting any objections submitted in accordance with 
paragraph (b)(2)(iii)(A) of this section.
    (3) For any State (and Indian country within the borders of such 
State) referenced in each notice of data availability required in 
paragraph (b)(2)(iii)(B) of this section as having TR SO2 
Group 2 units with total SO2 emissions exceeding the State 
assurance level for a control period in a given year, the Administrator 
will establish one assurance account for each set of owners and 
operators referenced, in the notice of data availability required under 
paragraph (b)(2)(iii)(B) of this section, as all of the owners and 
operators of a group of TR SO2 Group 2 sources and units in 
the State (and Indian country within the borders of such State) having 
a common designated representative for such control period and as being 
required to hold TR SO2 Group 2 allowances.
    (4)(i) As of midnight of November 1 immediately after the 
promulgation of each notice of data availability required in paragraph 
(b)(2)(iii)(B) of this section, the owners and operators described in 
paragraph (b)(3) of this section shall hold in the assurance account 
established for them and for the appropriate TR SO2 Group 2 
sources, TR SO2 Group 2 units, and State (and Indian country 
within the borders of such State) under paragraph (b)(3) of this 
section a total amount of TR SO2 Group 2 allowances, 
available for deduction under paragraph (a) of this section, equal to 
the amount such owners and operators are required to hold with regard 
to such sources, units and State (and Indian country within the borders 
of such State) as calculated by the Administrator and referenced in 
such notice.
    (ii) Notwithstanding the allowance-holding deadline specified in 
paragraph (b)(4)(i) of this section, if November 1 is not a business 
day, then such allowance-holding deadline shall be midnight of the 
first business day thereafter.
    (5) After November 1 (or the date described in paragraph (b)(4)(ii) 
of this section) immediately after the promulgation of each notice of 
data availability required in paragraph (b)(2)(iii)(B) of this section 
and after the recordation, in accordance with Sec.  97.723, of TR 
SO2 Group 2 allowance transfers submitted by midnight of 
such date, the Administrator will determine whether the owners and 
operators described in paragraph (b)(3) of this section hold, in the 
assurance account for the appropriate TR SO2 Group 2 
sources, TR SO2 Group 2 units, and State (and Indian country 
within the borders of such State) established under paragraph (b)(3) of 
this section, the amount of TR SO2 Group 2 allowances 
available under paragraph (a) of this section that the owners and 
operators are required to hold with regard to such sources, units, and 
State (and Indian country within the borders of such State) as 
calculated by the Administrator and referenced in the notice required 
in paragraph (b)(2)(iii)(B) of this section.
    (6) Notwithstanding any other provision of this subpart and any 
revision, made by or submitted to the Administrator after the 
promulgation of the notice of data availability required in paragraph 
(b)(2)(iii)(B) of this section for a control period in a given year, of 
any data used in making the calculations referenced in such notice, the 
amounts of TR SO2 Group 2 allowances that the owners and 
operators are required to hold in accordance with Sec.  97.706(c)(2)(i) 
for such control period shall continue to be such amounts as calculated 
by the Administrator and referenced in such notice required in 
paragraph (b)(2)(iii)(B) of this section, except as follows:
    (i) If any such data are revised by the Administrator as a result 
of a decision in or settlement of litigation concerning such data on 
appeal under part 78 of this chapter of such notice, or on appeal under 
section 307 of the Clean Air Act of a decision rendered under part 78 
of this chapter on appeal of such notice, then the Administrator will 
use the data as so revised to recalculate the amounts of TR 
SO2 Group 2 allowances that owners and operators are 
required to hold in accordance with the calculation formula in Sec.  
97.706(c)(2)(i) for such control period with regard to the TR 
SO2 Group 2 sources, TR SO2 Group 2 units, and 
State (and Indian country within the borders of such State) involved, 
provided that such litigation under part 78 of this chapter, or the 
proceeding under part 78 of this chapter that resulted in the decision 
appealed in such litigation under section 307 of the Clean Air Act, was 
initiated no later than 30 days after promulgation of such notice 
required in paragraph (b)(2)(iii)(B) of this section.
    (ii) If any such data are revised by the owners and operators of a 
TR SO2 Group 2 source and TR SO2 Group 2 unit 
whose designated representative submitted such data under paragraph 
(b)(2)(i) of this section, as a result of a decision in or settlement 
of litigation concerning such submission, then the Administrator will 
use the data as so revised to recalculate the amounts of TR 
SO2 Group 2 allowances that owners and operators are 
required to hold in accordance with the calculation formula in Sec.  
97.706(c)(2)(i) for such control period with regard to the TR 
SO2 Group 2 sources, TR SO2 Group 2 units, and 
State (and Indian country within the

[[Page 48479]]

borders of such State) involved, provided that such litigation was 
initiated no later than 30 days after promulgation of such notice 
required in paragraph (b)(2)(iii)(B) of this section.
    (iii) If the revised data are used to recalculate, in accordance 
with paragraphs (b)(6)(i) and (ii) of this section, the amount of TR 
SO2 Group 2 allowances that the owners and operators are 
required to hold for such control period with regard to the TR 
SO2 Group 2 sources, TR SO2 Group 2 units, and 
State (and Indian country within the borders of such State) involved--
    (A) Where the amount of TR SO2 Group 2 allowances that 
the owners and operators are required to hold increases as a result of 
the use of all such revised data, the Administrator will establish a 
new, reasonable deadline on which the owners and operators shall hold 
the additional amount of TR SO2 Group 2 allowances in the 
assurance account established by the Administrator for the appropriate 
TR SO2 Group 2 sources, TR SO2 Group 2 units, and 
State (and Indian country within the borders of such State) under 
paragraph (b)(3) of this section. The owners' and operators' failure to 
hold such additional amount, as required, before the new deadline shall 
not be a violation of the Clean Air Act. The owners' and operators' 
failure to hold such additional amount, as required, as of the new 
deadline shall be a violation of the Clean Air Act. Each TR 
SO2 Group 2 allowance that the owners and operators fail to 
hold as required as of the new deadline, and each day in such control 
period, shall be a separate violation of the Clean Air Act.
    (B) For the owners and operators for which the amount of TR 
SO2 Group 2 allowances required to be held decreases as a 
result of the use of all such revised data, the Administrator will 
record, in all accounts from which TR SO2 Group 2 allowances 
were transferred by such owners and operators for such control period 
to the assurance account established by the Administrator for the 
appropriate at TR SO2 Group 2 sources, TR SO2 
Group 2 units, and State (and Indian country within the borders of such 
State) under paragraph (b)(3) of this section, a total amount of the TR 
SO2 Group 2 allowances held in such assurance account equal 
to the amount of the decrease. If TR SO2 Group 2 allowances 
were transferred to such assurance account from more than one account, 
the amount of TR SO2 Group 2 allowances recorded in each 
such transferor account will be in proportion to the percentage of the 
total amount of TR SO2 Group 2 allowances transferred to 
such assurance account for such control period from such transferor 
account.
    (C) Each TR SO2 Group 2 allowance held under paragraph 
(b)(6)(iii)(A) of this section as a result of recalculation of 
requirements under the TR SO2 Group 2 assurance provisions 
for such control period must be a TR SO2 Group 2 allowance 
allocated for a control period in a year before or the year immediately 
following, or in the same year as, the year of such control period.

Sec.  97.726  Banking.

    (a) A TR SO2 Group 2 allowance 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 TR SO2 Group 2 allowance that is held in a 
compliance account or a general account will remain in such account 
unless and until the TR SO2 Group 2 allowance is deducted or 
transferred under Sec.  97.711(c), Sec.  97.723, Sec.  97.724, Sec.  
97.725, Sec.  97.727, or Sec.  97.728.

Sec.  97.727  Account error.

    The Administrator may, at his or her sole discretion and on his or 
her own motion, correct any error in any Allowance Management System 
account. Within 10 business days of making such correction, the 
Administrator will notify the authorized account representative for the 
account.

Sec.  97.728  Administrator's action on submissions.

    (a) The Administrator may review and conduct independent audits 
concerning any submission under the TR SO2 Group 2 Trading 
Program and make appropriate adjustments of the information in the 
submission.
    (b) The Administrator may deduct TR SO2 Group 2 
allowances from or transfer TR SO2 Group 2 allowances to a 
compliance account or an assurance account, based on the information in 
a submission, as adjusted under paragraph (a)(1) of this section, and 
record such deductions and transfers.

Sec.  97.729  [Reserved]

Sec.  97.730  General monitoring, recordkeeping, and reporting 
requirements.

    The owners and operators, and to the extent applicable, the 
designated representative, of a TR SO2 Group 2 unit, shall 
comply with the monitoring, recordkeeping, and reporting requirements 
as provided in this subpart and subparts F and G of part 75 of this 
chapter. For purposes of applying such requirements, the definitions in 
Sec.  97.702 and in Sec.  72.2 of this chapter shall apply, 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 ``TR SO2 Group 2 
unit,'' ``designated representative,'' and ``continuous emission 
monitoring system'' (or ``CEMS'') respectively as defined in Sec.  
97.702, and the term ``newly affected unit'' shall be deemed to mean 
``newly affected TR SO2 Group 2 unit''. The owner or 
operator of a unit that is not a TR SO2 Group 2 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 TR SO2 Group 2 unit.
    (a) Requirements for installation, certification, and data 
accounting. The owner or operator of each TR SO2 Group 2 
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.  97.731 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. Except as provided in paragraph (e) of 
this section, 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 and 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 TR SO2 Group 2 unit 
that commences commercial operation before July 1, 2011, January 1, 
2012.
    (2) For the owner or operator of a TR SO2 Group 2 unit 
that commences commercial operation on or after July 1, 2011, by the 
later of the following:
    (i) January 1, 2012; or
    (ii) 180 calendar days after the date on which the unit commences 
commercial operation.
    (3) The owner or operator of a TR SO2 Group 2 unit for 
which construction of a new stack or flue or installation of add-on 
SO2 emission controls is completed after the applicable 
deadline

[[Page 48480]]

under paragraph (b)(1) or (2) of this section shall meet the 
requirements of Sec. Sec.  75.4(e)(1) through (e)(4) of this chapter, 
except that:
    (i) Such requirements shall apply to the monitoring systems 
required under Sec.  97.730 through Sec.  97.735, rather than the 
monitoring systems required under part 75 of this chapter;
    (ii) SO2 concentration, stack gas moisture content, 
stack gas volumetric flow rate, and O2 or CO2 
concentration data shall be determined and reported, rather than the 
data listed in Sec.  75.4(e)(2) of this chapter; and
    (iii) Any petition for another procedure under Sec.  75.4(e)(2) of 
this chapter shall be submitted under Sec.  97.735, rather than Sec.  
75.66.
    (c) Reporting data. The owner or operator of a TR SO2 
Group 2 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, 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.
    (d) Prohibitions. (1) No owner or operator of a TR SO2 
Group 2 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.  97.735.
    (2) No owner or operator of a TR SO2 Group 2 unit shall 
operate the unit so as to discharge, or allow to be discharged, 
SO2 to the atmosphere without accounting for all such 
SO2 in accordance with the applicable provisions of this 
subpart and part 75 of this chapter.
    (3) No owner or operator of a TR SO2 Group 2 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 discharged into the 
atmosphere or heat input, 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 TR SO2 Group 2 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.  97.705 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 Administrator 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 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.  
97.731(d)(3)(i).
    (e) Long-term cold storage. The owner or operator of a TR 
SO2 Group 2 unit is subject to the applicable provisions of 
Sec.  75.4(d) of this chapter concerning units in long-term cold 
storage.

Sec.  97.731  Initial monitoring system certification and 
recertification procedures.

    (a) The owner or operator of a TR SO2 Group 2 unit shall 
be exempt from the initial certification requirements of this section 
for a monitoring system under Sec.  97.730(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 appendices B and 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.  97.730(a)(1) that is exempt from initial 
certification requirements under paragraph (a) of this section.
    (c) [Reserved]
    (d) Except as provided in paragraph (a) of this section, the owner 
or operator of a TR SO2 Group 2 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.  97.730(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.  
97.730(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.  97.730(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.  97.730(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.  97.730(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. 
For initial certification of a continuous monitoring system under Sec.  
97.730(a)(1), paragraphs (d)(3)(i) through (v) of this section apply. 
For recertifications of such monitoring systems, paragraphs (d)(3)(i) 
through (iv) of this section and the procedures in Sec. Sec.  
75.20(b)(5) and (g)(7) of this chapter (in lieu of the

[[Page 48481]]

procedures in paragraph (d)(3)(v) of this section) apply, provided that 
in applying paragraphs (d)(3)(i) through (iv) of this section, the 
words ``certification'' and ``initial certification'' are replaced by 
the word ``recertification'' and the word ``certified'' is replaced by 
with the word ``recertified''.
    (i) Notification of certification. The designated representative 
shall submit to the appropriate EPA Regional Office and the 
Administrator written notice of the dates of certification testing, in 
accordance with Sec.  97.733.
    (ii) Certification application. The designated representative shall 
submit to the Administrator 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 TR SO2 Group 2 Trading Program 
for a period not to exceed 120 days after receipt by the Administrator 
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 Administrator 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 Administrator.
    (iv) Certification application approval process. The Administrator 
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 Administrator 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 TR SO2 Group 2 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 Administrator 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 Administrator will issue a written notice of 
incompleteness that sets a reasonable date by which the designated 
representative must submit the additional information required to 
complete the certification application. If the designated 
representative does not comply with the notice of incompleteness by the 
specified date, then the Administrator may issue a notice of 
disapproval under paragraph (d)(3)(iv)(C) of this section.
    (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 Administrator 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 Administrator 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).
    (D) Audit decertification. The Administrator may issue a notice of 
disapproval of the certification status of a monitor in accordance with 
Sec.  97.732(b).
    (v) Procedures for loss of certification. If 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 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 Administrator's notice of disapproval, no later than 
30 unit operating days after the date of issuance of the notice of 
disapproval.
    (e) 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) The designated representative of each unit for which the owner 
or operator intends to use an alternative monitoring system approved by 
the Administrator 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.  97.732  Monitoring system out-of-control periods.

    (a) General provisions. 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 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

[[Page 48482]]

specification or other requirement under Sec.  97.731 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 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 Administrator or any State or 
permitting authority. By issuing the notice of disapproval, 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.  
97.731 for each disapproved monitoring system.

Sec.  97.733  Notifications concerning monitoring.

    The designated representative of a TR SO2 Group 2 unit 
shall submit written notice to the Administrator in accordance with 
Sec.  75.61 of this chapter.

Sec.  97.734  Recordkeeping and reporting.

    (a) General provisions. The designated representative shall comply 
with all recordkeeping and reporting requirements in paragraphs (b) 
through (e) of this section, the applicable recordkeeping and reporting 
requirements in subparts F and G of part 75 of this chapter, and the 
requirements of Sec.  97.714(a).
    (b) Monitoring plans. The owner or operator of a TR SO2 
Group 2 unit shall comply with requirements of Sec.  75.62 of this 
chapter.
    (c) Certification applications. The designated representative shall 
submit an application to the Administrator within 45 days after 
completing all initial certification or recertification tests required 
under Sec.  97.731, including the information required under Sec.  
75.63 of this chapter.
    (d) Quarterly reports. The designated representative shall submit 
quarterly reports, as follows:
    (1) The designated representative shall report the SO2 
mass emissions data and heat input data for the TR SO2 Group 
2 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, 
2011, the calendar quarter covering January 1, 2012 through March 31, 
2012; or
    (ii) For a unit that commences commercial operation on or after 
July 1, 2011, the calendar quarter corresponding to the earlier of the 
date of provisional certification or the applicable deadline for 
initial certification under Sec.  97.730(b), unless that quarter is the 
third or fourth quarter of 2011, in which case reporting shall commence 
in the quarter covering January 1, 2012 through March 31, 2012.
    (2) The designated representative shall submit each quarterly 
report to the Administrator within 30 days after 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 TR SO2 Group 2 units that are also subject to 
the Acid Rain Program, TR NOX Annual Trading Program, or TR 
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.
    (4) The Administrator may review and conduct independent audits of 
any quarterly report in order to determine whether the quarterly report 
meets the requirements of this subpart and part 75 of this chapter, 
including the requirement to use substitute data.
    (i) The Administrator will notify the designated representative of 
any determination that the quarterly report fails to meet any such 
requirements and specify in such notification any corrections that the 
Administrator believes are necessary to make through resubmission of 
the quarterly report and a reasonable time period within which the 
designated representative must respond. Upon request by the designated 
representative, the Administrator may specify reasonable extensions of 
such time period. Within the time period (including any such 
extensions) specified by the Administrator, the designated 
representative shall resubmit the quarterly report with the corrections 
specified by the Administrator, except to the extent the designated 
representative provides information demonstrating that a specified 
correction is not necessary because the quarterly report already meets 
the requirements of this subpart and part 75 of this chapter that are 
relevant to the specified correction.
    (ii) Any resubmission of a quarterly report shall meet the 
requirements applicable to the submission of a quarterly report under 
this subpart and part 75 of this chapter, except for the deadline set 
forth in paragraph (d)(2) of this section.
    (e) Compliance certification. The 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.  97.735  Petitions for alternatives to monitoring, recordkeeping, 
or reporting requirements.

    (a) The designated representative of a TR SO2 Group 2 
unit may submit a petition under Sec.  75.66 of this chapter to the 
Administrator, requesting approval to apply an alternative to any 
requirement of Sec. Sec.  97.730 through 97.734.
    (b) A petition submitted under paragraph (a) of this section shall 
include sufficient information for the evaluation of the petition, 
including, at a minimum, the following information:
    (i) Identification of each unit and source covered by the petition;
    (ii) A detailed explanation of why the proposed alternative is 
being suggested in lieu of the requirement;
    (iii) A description and diagram of any equipment and procedures 
used in the proposed alternative;
    (iv) A demonstration that the proposed alternative is consistent 
with the purposes of the requirement for which the alternative is 
proposed and with the purposes of this subpart and part 75 of this 
chapter and that any

[[Page 48483]]

adverse effect of approving the alternative will be de minimis; and
    (v) Any other relevant information that the Administrator may 
require.
    (c) Use of an alternative to any requirement referenced in 
paragraph (a) of this section is in accordance with this subpart only 
to the extent that the petition is approved in writing by the 
Administrator and that such use is in accordance with such approval.

[FR Doc. 2011-17600 Filed 8-5-11; 8:45 am]
BILLING CODE 6560-50-P