
[Federal Register: August 2, 2010 (Volume 75, Number 147)]
[Proposed Rules]               
[Page 45209-45465]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr02au10-14]                         
 

[[Page 45209]]

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

Part II





 Environmental Protection Agency





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



40 CFR Parts 51, 52, 72, et al.



Federal Implementation Plans To Reduce Interstate Transport of Fine 
Particulate Matter and Ozone; Proposed Rule


[[Page 45210]]


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

ENVIRONMENTAL PROTECTION AGENCY

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

[EPA-HQ-OAR-2009-0491; FRL-9174-9]
RIN 2060-AP50

 
Federal Implementation Plans To Reduce Interstate Transport of 
Fine Particulate Matter and Ozone

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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

SUMMARY: EPA is proposing to limit the interstate transport of 
emissions of nitrogen oxides (NOX) and sulfur dioxide 
(SO2). In this action, EPA is proposing to both identify and 
limit emissions within 32 states in the eastern United States that 
affect the ability of downwind states to attain and maintain compliance 
with the 1997 and 2006 fine particulate matter (PM2.5) 
national ambient air quality standards (NAAQS) and the 1997 ozone 
NAAQS. EPA is proposing to limit these emissions through Federal 
Implementation Plans (FIPs) that regulate electric generating units 
(EGUs) in the 32 states. This action will substantially reduce the 
impact of transported emissions on downwind states. In conjunction with 
other federal and state actions, it helps assure that all but a handful 
of areas in the eastern part of the country will be in compliance with 
the current ozone and PM2.5 NAAQS by 2014 or earlier. To the 
extent the proposed FIPs do not fully address all significant 
transport, EPA is committed to assuring that any additional reductions 
needed are addressed quickly. EPA takes comments on ways this proposal 
could achieve additional NOX reductions and additional 
actions including other rulemakings that EPA could undertake to achieve 
any additional reductions needed.

DATES: Comments. Comments must be received on or before October 1, 
2010.
    Public Hearing: Three public hearings will be held before the end 
of the comment period. The dates, times and locations will be announced 
separately. Please refer to SUPPLEMENTARY INFORMATION for additional 
information on the comment period and the public hearings.

ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-
OAR-2009-0491 by one of the following methods:
     http://www.regulations.gov. Follow the online instructions 
for submitting comments. Attention Docket ID No. EPA-HQ-OAR-2009-0491.
     E-mail: a-and-r-docket@epa.gov. Attention Docket ID No. 
EPA-HQ-OAR-2009-0491.
     Fax: (202) 566-9744. Attention Docket ID No. EPA-HQ-OAR-
2009-0491.
     Mail: EPA Docket Center, EPA West (Air Docket), Attention 
Docket ID No. EPA-HQ-OAR-2009-0491, U.S. Environmental Protection 
Agency, Mailcode: 2822T, 1200 Pennsylvania Avenue, NW., Washington, DC 
20460. Please include 2 copies. In addition, please mail a copy of your 
comments on the information collection provisions to the Office of 
Information and Regulatory Affairs, Office of Management and Budget 
(OMB), Attn: Desk Officer for EPA, 725 17th Street, NW., Washington, DC 
20503.
     Hand Delivery: U.S. Environmental Protection Agency, EPA 
West (Air Docket), 1301 Constitution Avenue, Northwest, Room 3334, 
Washington, DC 20004, Attention Docket ID No. EPA-HQ-OAR-2009-0491. 
Such deliveries are only accepted during the Docket's normal hours of 
operation, and special arrangements should be made for deliveries of 
boxed information.
    Instructions. Direct your comments to Docket ID No. EPA-HQ-OAR-
2009-0491. EPA's policy is that all comments received will be included 
in the public docket without change and may be made available online at 
http://www.regulations.gov, including any personal information 
provided, unless the comment includes information claimed to be 
Confidential Business Information (CBI) or other information whose 
disclosure is restricted by statute. Do not submit information that you 
consider to be CBI or otherwise protected through http://
www.regulations.gov or e-mail. The http://www.regulations.gov Web site 
is an ``anonymous access'' system, which means EPA will not know your 
identity or contact information unless you provide it in the body of 
your comment. If you send an e-mail comment directly to EPA without 
going through http://www.regulations.gov, your e-mail address will be 
automatically captured and included as part of the comment that is 
placed in the public docket and made available on the Internet. If you 
submit an electronic comment, EPA recommends that you include your name 
and other contact information in the body of your comment and with any 
disk or CD-ROM you submit. If EPA cannot read your comment due to 
technical difficulties and cannot contact you for clarification, EPA 
may not be able to consider your comment. Electronic files should avoid 
the use of special characters, avoid any form of encryption, and be 
free of any defects or viruses. For additional information about EPA's 
public docket, visit the EPA Docket Center homepage at http://
www.epa.gov/epahome/dockets.htm.
    Docket. All documents in the docket are listed in the http://
www.regulations.gov index. 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, will be publicly available only in hard copy. 
Publicly available docket materials are available either electronically 
in http://www.regulations.gov or in hard copy at the Air and Radiation 
Docket and Information Center, EPA/DC, EPA West Building, Room 3334, 
1301 Constitution Ave., 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: Mr. Tim Smith, Air Quality Policy 
Division, Office of Air Quality Planning and Standards (C539-04), 
Environmental Protection Agency, Research Triangle Park, NC 27711; 
telephone number: (919) 541-4718; fax number: (919) 541-0824; e-mail 
address: smith.tim@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.

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
CBI Confidential Business Information
CFR Code of Federal Regulations
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
Hg Mercury
IPM Integrated Planning Model
lb/mmbtu Pounds Per Million British Thermal Unit
[mu]g/m3 Micrograms Per Cubic Meter

[[Page 45211]]

NAAQS National Ambient Air Quality Standards
NOX Nitrogen Oxides
NSPS New Source Performance Standard
OTAG Ozone Transport Assessment Group
PUC Public Utility Commission
SNCR Selective Non-catalytic Reduction
SCR Selective Catalytic Reduction
SIP State Implementation Plan
PM2.5 Fine Particulate Matter, Less Than 2.5 Micrometers
PM10 Fine and Coarse Particulate Matter, Less Than 10 
Micrometers
PM Particulate Matter
RIA Regulatory Impact Analysis
SO2 Sulfur Dioxide
SOX Sulfur Oxides, Including Sulfur Dioxide 
(SO2) and Sulfur Trioxide (SO3)
TIP Tribal Implementation Plan tpy Tons Per Year
TSD Technical Support Document

II. General Information

A. Does this action apply to me?

    This rule affects EGUs, and regulates the following groups:

------------------------------------------------------------------------
             Industry group                         NAICS \a\
------------------------------------------------------------------------
Utilities (electric, natural gas, other  2211, 2212, 2213
 systems).
------------------------------------------------------------------------
\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 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, 97,604, and 97.704.

B. Where can I get a copy of this document and other related 
information?

    In addition to being available in the docket, an electronic copy of 
this proposal will also be available on the World Wide Web. Following 
signature by the EPA Administrator, a copy of this action will be 
posted on the transport rule Web site http://www.epa.gov/airtransport.

C. What should I consider as I prepare my comments for EPA?

    1. Submitting CBI. Do not submit this information to EPA through 
http://www.regulations.gov or e-mail. Clearly mark the part or all of 
the information that you claim to be CBI. For CBI information in a disk 
or CD-ROM that you mail to EPA, mark the outside of the disk or CD-ROM 
as CBI and then identify electronically within the disk or CD-ROM the 
specific information that is claimed as CBI. In addition to one 
complete version of the comment that includes information claimed as 
CBI, a copy of the comment that does not contain the information 
claimed as CBI must be submitted for inclusion in the public docket. 
Information so marked will not be disclosed except in accordance with 
procedures set forth in 40 CFR part 2. Send or deliver information 
identified as CBI only to the following address: Roberto Morales, OAQPS 
Document Control Officer (C404-02), U.S. EPA, Research Triangle Park, 
NC 27711, Attention Docket ID No. EPA-HQ-OAR-2009-0491.
    2. Tips for preparing your comments. When submitting comments, 
remember to:
     Identify the rulemaking by docket number and other 
identifying information (subject heading, Federal Register date and 
page number).
     Follow directions--The agency may ask you to respond to 
specific questions or organize comments by referencing a Code of 
Federal Regulations (CFR) part or section number.
     Explain why you agree or disagree; suggest alternatives 
and substitute language for your requested changes.
     Describe any assumptions and provide any technical 
information and/or data that you used.
     If you estimate potential costs or burdens, explain how 
you arrived at your estimate in sufficient detail to allow for it to be 
reproduced.
     Provide specific examples to illustrate your concerns, and 
suggest alternatives.
     Explain your views as clearly as possible, avoiding the 
use of profanity or personal threats.
     Make sure to submit your comments by the comment period 
deadline identified.

D. How can I find information about the public hearings?

    The EPA will hold three public hearings on this proposal. The 
dates, times and locations of the pubic hearings will be announced 
separately. Oral testimony will be limited to 5 minutes per commenter. 
The EPA encourages commenters to provide written versions of their oral 
testimonies either electronically or in paper copy. Verbatim 
transcripts and written statements will be included in the rulemaking 
docket. If you would like to present oral testimony at one of the 
hearings, please notify Ms. Pamela S. Long, Air Quality Policy Division 
(C504-03), U.S. EPA, Research Triangle Park, NC 27711, telephone number 
(919) 541-0641; e-mail: long.pam@epa.gov. Persons interested in 
presenting oral testimony should notify Ms. Long at least 2 days in 
advance of the public hearings. For updates and additional information 
on the public hearings, please check EPA's website for this rulemaking, 
http://www.epa.gov/airtransport. The public hearings will provide 
interested parties the opportunity to present data, views, or arguments 
concerning the proposed rule. The EPA officials may ask clarifying 
questions during the oral presentations, but will not respond to the 
presentations or comments at that time. Written statements and 
supporting information submitted during the comment period will be 
considered with the same weight as any oral comments and supporting 
information presented at the public hearings.

E. How is this Preamble Organized?

I. Preamble Glossary of Terms and Abbreviations
II. General Information
    A. Does this action apply to me?
    B. Where can I get a copy of this document and other related 
information?
    C. What should I consider as I prepare my comments for EPA?
    D. How can I find information about the hearings?
    E. How is the preamble organized?
III. Summary of Proposed Rule and Background
    A. Summary of Proposed Rule
    B. Background
    1. What is the source of EPA's authority for this action?
    2. What air quality problems does this proposal address?
    3. Which NAAQS does this proposal address?
    4. EPA Transport Rulemaking History
    C. What are the goals of this proposed rule?
    1. Primary Goals
    2. Key Guiding Principles
    D. Why does this proposed rule focus on the eastern half of the 
United States?
    E. Anticipated Rules Affecting Power Sector
IV. Defining ``Significant Contribution'' and ``Interference With 
Maintenance''
    A. Background
    1. Approach Used in NOX SIP Call and CAIR
    2. Judicial Opinions
    3. Overview of Proposed Approach
    B. Overview of Approach To Identify Contributing Upwind States
    1. Background
    2. Approach for Proposed Rule
    C. Air Quality Modeling Approach and Results
    1. What air quality modeling platform did EPA use?
    2. How did EPA project future nonattainment and maintenance for 
annual PM2.5, 24-Hour PM2.5, and 8-hour ozone?
    3. How did EPA assess interstate contributions to nonattainment 
and maintenance?

[[Page 45212]]

    4. What are the estimated interstate contributions to annual 
PM2.5, 24-hour PM2.5, and 8-hour ozone 
nonattainment and maintenance?
    D. Proposed Methodology To Quantify Emissions That Significantly 
Contribute or Interfere With Maintenance
    1. Explanation of Proposed Approach To Quantify Significant 
Contribution
    2. Application
    3. Discussion of Control Costs for Sources Other Than EGUs
    E. State Emissions Budgets
    1. Defining SO2 and Annual NOX State 
Emissions Budgets for EGUs
    2. Defining Ozone Season NOX State Emissions Budgets 
for EGUs
    F. Emissions Reductions Requirements Including Variability
    1. Variability
    2. State Budgets With Variability Limits
    3. Summary of Emissions Reductions Across All Covered States
    G. How the Proposed Approach Is Consistent With Judicial 
Opinions Interpreting Section 110(a)(2)(D)(i)(I) of the Clean Air 
Act
    H. Alternative Approaches Evaluated But Not Proposed
V. Proposed Emissions Control Requirements
    A. Pollutants Included in This Proposal
    B. Source Categories
    1. Propose To Control Power Sector Emissions
    2. Other Source Categories Are Not Included
    C. Timing of Proposed Emissions Reductions Requirements
    1. Date for Prohibiting Emissions That Significantly Contribute 
or Interfere With Maintenance of the PM2.5 NAAQS
    2. Date for Prohibiting Emissions That Significantly Contribute 
or Interfere With Maintenance of the 1997 Ozone NAAQS
    3. Reductions Required by 2012 To Ensure That Significant 
Contribution and Interference With Maintenance Are Eliminated as 
Expeditiously as Practicable
    4. How Compliance Deadlines Address the Court's Concern About 
Timing
    5. EPA Will Consider Additional Reductions in Pollution 
Transport To Assist in Meeting Any Revised or New NAAQS
    D. Implementing Emission Reduction Requirements
    1. Approach Taken in NOX SIP Call and CAIR
    2. Judicial Opinions
    3. Remedy Options Overview
    4. State Budgets/Limited Trading Proposed Remedy
    5. State Budgets/Intrastate Trading Remedy Option
    6. Direct Control Remedy Option
    E. Projected Costs and Emissions for Each Remedy Option
    1. State Budgets/Limited Trading
    2. State Budgets/Intrastate Trading
    3. Direct Control
    4. State-Level Emissions Projections
    F. Transition From the CAIR Cap-and-Trade Programs to Proposed 
Programs
    1. Sunsetting of CAIR, CAIR SIPs, and CAIR FIPs
    2. Change in States Covered
    3. Applicability, CAIR Opt-Ins and NOX SIP Call Units
    4. Early Reduction Provisions
    5. Source Monitoring and Reporting
    G. Interactions With Existing Title IV Program and 
NOX SIP Call
    1. Title IV Interactions
    2. NOX SIP Call Interactions
VI. Stakeholder Outreach
VII. State Implementation Plan Submissions
    A. Section 110(a)(2)(D)(i) SIPs for the 1997 Ozone and 
PM2.5 NAAQS
    B. Section 110(a)(2)(D)(i) SIPs for the 2006 PM2.5 
NAAQS
    C. Transport Rule SIPs
VIII. Permitting
    A. Title V Permitting
    B. New Source Review
IX. What benefits are projected for the proposed rule?
    A. The Impacts on PM2.5 and Ozone of the Proposed 
SO2 and NOX Strategy
    B. Human Health Benefit Analysis
    C. Quantified and Monetized Visibility Benefits
    D. Benefits of Reducing GHG Emission
    E. Total Monetized Benefits
    F. How do the benefits compare to the costs of this proposed 
rule?
    G. What are the unquantified and unmonetized benefits of the 
transport rule emissions reductions?
    1. What are the benefits of reduced deposition of sulfur and 
nitrogen to aquatic, forest, and coastal ecosystems?
    2. Ozone Vegetation Effects
    3. Other Health or Welfare Disbenefits of the Transport Rule 
That Have Not Been Quantified
X. Economic Impacts
XI. Incorporating End-Use Energy Efficiency Into the Proposed 
Transport Rule
    A. Background
    1. What is end-use energy efficiency?
    2. How does energy efficiency contribute to cost-effective 
reductions of air emissions from EGUs?
    3. How does the proposed rule support greater investment in 
energy efficiency?
    4. How EPA and states have previously integrated energy 
efficiency into air regulatory programs?
    B. Incorporating End-Use Energy Efficiency Into the Transport 
Rule
    1. Options That Could Be Used To Incorporate Energy Efficiency 
Into Allowance Based Programs
    2. Why EPA did not propose these options?
XII. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act (RFA)
    D. Unfunded Mandates Reform Act
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination With 
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children From 
Environmental Health and Safety Risks
    H. Executive Order 13211: Actions That Significantly Affect 
Energy Supply, Distribution, or Use
    I. National Technology Transfer Advancement Act
    J. Executive Order 12898: Federal Actions To Address 
Environmental Justice in Minority Populations and Low-Income 
Populations
    1. Consideration of Environmental Justice Issues in the Rule 
Development Process
    2. Potential Environmental and Public Health Impacts to 
Vulnerable Populations
    3. Meaningful Public Participation
    4. Determination

III. Summary of Proposed Rule and Background

A. Summary of Proposed Rule

    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 notice, EPA proposes to find that 
emissions of SO2 and NOX in 32 eastern 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 average PM2.5 NAAQS 
promulgated in 1997, the 24-hour average PM2.5 NAAQS 
promulgated in 2006, and the ozone NAAQS promulgated in 1997.\1\ These 
emissions are transported downwind either as SO2 and 
NOX or, after transformation in the atmosphere, as fine 
particles or ozone. This notice identifies emission reduction 
responsibilities of upwind states, and also proposes enforceable FIPs 
to achieve the required emissions reductions in each state through 
cost-effective and flexible requirements for power plants. Each state 
will have the option of replacing these Federal rules with state rules 
to achieve the required amount of emissions reductions from sources 
selected by the state.
---------------------------------------------------------------------------

    \1\ In the context of the jurisdictions covered by this proposed 
rule, EPA uses the term ``states'' to include the District of 
Columbia.
---------------------------------------------------------------------------

    With respect to the annual average PM2.5 NAAQS, this 
proposal finds that 24 eastern states have SO2 and 
NOX emission reduction responsibilities, and quantifies each 
state's full emission reduction responsibility under section 
110(a)(2)(D)(i)(I). With respect to the 24-hour average 
PM2.5 NAAQS, this proposal finds that 25 eastern states have 
emission reduction responsibilities. The proposed reductions will at 
least partly eliminate, and subject to further analysis may fully 
eliminate, these states' significant contribution and interference with 
maintenance for purposes of the 24-hour average PM2.5 
standard. In all, emissions reductions related to interstate transport

[[Page 45213]]

of fine particles would be required in 28 states.
    With respect to the 1997 ozone NAAQS, this proposal requires 
emissions reductions in 26 states. For 16 of these states, we propose 
that the required reductions represent their full significant 
contribution and interference with maintenance for the ozone NAAQS. For 
an additional 10 states, the required NOX reductions are 
needed for these states to make measurable progress towards eliminating 
their significant contribution and interference with maintenance. EPA 
has begun to conduct additional information gathering and analysis to 
determine the extent to which further reductions from these states may 
be needed to fully eliminate significant contribution and interference 
with maintenance with the 1997 ozone NAAQS.
    This proposed rule would achieve substantial near-term emissions 
reductions from the power sector. EPA projects that with the proposed 
rule, EGU SO2 emissions would be 5.0 million tons lower, 
annual NOX emissions would be 700,000 tons lower, and ozone 
season NOX emissions would be 100,000 tons lower in 2012, 
compared to baseline 2012 projections in the proposed covered states. 
Further, EGU SO2 emissions would be 4.6 million tons lower, 
annual NOX emissions would be 700,000 tons lower, and ozone 
season NOX emissions would be 100,000 tons lower in 2014, 
compared to baseline 2014 projections (which will have dropped from 
2012 due to other federal and state requirements, thereby lowering the 
2014 baseline). See Table III.A-2 for projected EGU emissions with the 
proposed rule compared to baseline, and Table III.A-3 for projected EGU 
emissions with the proposed rule compared to 2005 actual emissions. The 
reductions obtained through the Transport Rule FIPs will help all but a 
very few areas in the eastern part of the country come into attainment 
with the 1997 PM2.5 and ozone standards and take major 
strides toward helping states address nonattainment with the 2006 24-
hour average PM2.5 standard. See Table III.A-1 for proposed 
list of covered states.
    EPA is committed to fulfilling its responsibility to ensure that 
downwind states receive the relief from upwind emissions guaranteed 
under CAA section 110(a)(2)(D) For the 24-hour PM2.5 
standard, EPA's air quality modeling shows that in the areas with 
continuing non-attainment or maintenance problems, the remaining 
exceedances occur almost entirely in the winter months. The relative 
importance of particle species such as sulfate and nitrate, is quite 
different between summer and winter. EPA is moving ahead before the 
final rule is published to determine the extent to which this 
wintertime problem is caused by emissions transported from upwind 
states. Further study of the 24-hour PM2.5 results could 
lead to a number of possible outcomes; EPA cannot judge the relative 
likelihood of these outcomes at this time. To the extent possible, EPA 
plans to finalize this rule with a full determination of, and remedy 
for, significant contribution and interference with maintenance for the 
24-hour PM2.5 standard. To that end, EPA is expeditiously 
proceeding with examination of the residual wintertime problem. (See 
full discussion in section IV.D.)
    In the case of ozone, EPA must determine whether further 
NOX reductions are warranted in certain upwind states that 
affect two or three areas with relatively persistent ozone air quality 
problems. To support a full significant contribution determination for 
these states, EPA is expeditiously conducting further analysis of 
NOX control costs, emissions reductions, air quality 
impacts, and the nature of the residual air quality issues. EPA's 
current information indicates that considering NOX 
reductions beyond the cost per ton levels proposed in this rule will 
require analysis of reductions from source categories other than EGUs, 
as well as from EGUs. EPA believes that developing supplemental 
information to consider NOX sources beyond EGUs would 
substantially delay publication of a final rule beyond the anticipated 
publication of spring 2011. EPA does not believe that this effort 
should delay the reductions and large health benefits associated with 
this proposed rule. Thus, EPA intends to proceed with additional 
rulemaking to address fully the residual significant contribution to 
nonattainment and interference with maintenance with the ozone standard 
as quickly as possible. (See full discussion in section IV.D.)
    This proposed rule is the first of several EPA rules to be issued 
over the next 2 years that will yield substantial health and 
environmental benefits for the public through regulation of power 
plants. Fossil-fuel-fired power plants contribute a large and 
substantial fraction of the emissions of several key air pollutants, 
and the agency has statutory or judicial obligations to make several 
regulatory determinations on power plant emissions. The Administrator 
in January established improved air quality as an Agency priority and 
announced plans to promote a cleaner and more efficient power sector 
and have strong but achievable reduction goals for SO2, 
NOX, mercury, and other air toxics.''
    In addition to this rule, other anticipated actions include a 
section 112(d) rule for electric utilities to be proposed by March 
2011, potential rules to address pollution transport under revised 
NAAQS, revisions to new source performance standards for coal and oil-
fired utility electric generating units, and best available retrofit 
technology (BART) and regional haze program requirements to protect 
visibility. These actions, and their relationship to this rule, are 
discussed further in section III.E.
    Ongoing reviews of the ozone and PM2.5 NAAQS could 
result in revised NAAQS. To address any new NAAQS, EPA would propose 
interstate transport determinations in future notices. Such proposals 
could require greater emissions reductions from states covered by this 
proposal and/or require reductions from states not covered by this 
proposal. In addition, while this action proposes to require reductions 
from the power sector only, it is possible that reductions from other 
source categories could be needed to address interstate transport 
requirements related to any new NAAQS.
    With this proposal, EPA is also responding to the remand of the 
CAIR by the Court in 2008. CAIR, promulgated May 12, 2005 (70 FR 25162) 
requires 28 states and the District of Columbia 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. The CAIR FIPs, promulgated April 
26, 2006 (71 FR 25328), regulate EGUs in the covered states and achieve 
the emissions reductions requirements established by CAIR until states 
have approved SIPs to achieve the reductions. In July 2008, the DC 
Circuit Court found CAIR and the CAIR FIPs unlawful. North Carolina v. 
EPA, 531 F.3d 896 (DC Cir. 2008). The Court's original decision vacated 
CAIR. Id. 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 v. EPA, 550 F.3d 1176, 1178 (DC Cir. 2008). The 
CAIR requirements are correctly in place and the CAIR's regional 
control programs are operating

[[Page 45214]]

while EPA develops replacement rules in response to the remand.
    As described more fully in the remainder of this preamble, the 
approaches used in this proposed 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 v. EPA and address the flaws in CAIR 
identified by the Court therein. Among other things, the proposal 
relies on detailed, bottom-up scientific and technical analyses, 
introduces a state-specific methodology for identifying significant 
contribution to nonattainment and interference with maintenance, and 
proposes remedy options to ensure that all necessary reductions are 
achieved in the covered states.
    In this action, EPA proposes to both identify and address emissions 
within states in the eastern United States that significantly 
contribute to nonattainment or interfere with maintenance by other 
downwind states. As discussed in sections III and VII in this preamble 
and described in greater detail in two separate Federal Register 
notices published on April 25, 2005 (70 FR 21147) and June 9, 2010 (75 
FR 32673), EPA has determined, or proposed to determine, that the 32 
states covered by this proposal either have not submitted SIPs adequate 
to meet the requirements of 110(a)(2)(D)(i)(I) with respect to the 1997 
and 2006 PM2.5 NAAQS and the 1997 ozone NAAQS, or that the 
SIP provisions currently in place are not adequate to meet those 
requirements.
    As described in section IV in this preamble, EPA is proposing a 
state-specific methodology to identify specific reductions that states 
in the eastern United States must make to satisfy 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. The proposed methodology uses state-specific inputs and focuses 
on the emissions reductions available in each individual state to 
address the Court's concern that the approach used in CAIR (which 
identified a single level of emissions achievable by the application of 
highly cost effective controls in the region) was insufficiently state 
specific. The proposed methodology uses air quality analysis to 
determine whether a state's contribution to downwind air quality 
problems is above specific thresholds. If a state's contribution does 
not exceed those thresholds, its contribution is found to be 
insignificant and it is no longer considered in the analysis. If a 
state's contribution exceeds those thresholds, EPA takes a second step 
that uses a multi-factor analysis that takes into account both air 
quality and cost considerations to identify the portion of a state's 
contribution that is significant or that interferes with maintenance. 
Section 110(a)(2)(D) requires states to eliminate the emissions that 
constitute this ``significant contribution'' and ``interference with 
maintenance.''
    This proposed methodology for determining upwind state emission 
reduction responsibility is designed to be applicable to current and 
potential future ozone and PM2.5 NAAQS. It is based on cost 
and air quality considerations that are common to any NAAQS, but also 
calls for evaluation of facts specific to a particular NAAQS. As a 
result, application of the methodology to a revised, more stringent 
NAAQS might lead to a determination that greater reductions in 
transported pollution from upwind states are reasonable than for a 
current, less stringent NAAQS.
    To facilitate implementation of the requirement that significant 
contribution and interference with maintenance be eliminated, EPA 
developed state emissions budgets. By tying these budgets directly to 
EPA's quantification of each individual state's significant 
contribution and interference with maintenance, EPA directly linked the 
budgets to the mandate in section 110(a)(2)(D)(i)(I), and thus 
addressed the Court's concerns about the development of budgets for the 
CAIR. EPA also addressed these concerns by completely eschewing any 
consideration or reliance on Fuel Adjustment Factors and the existing 
allocation of Title IV allowances.
    These new emissions budgets are based on the Agency's state-by-
state analysis of each upwind state's significant contribution to 
nonattainment and interference with maintenance downwind. A state's 
emissions budget is the quantity of emissions that would remain after 
elimination of the part of significant contribution and interference 
with maintenance that EPA has identified in an average year (i.e., 
before accounting for the inherent variability in power system 
operations).\2\ EPA proposes SO2 and NOX budgets 
for each state covered for the 24-hour and/or annual average 
PM2.5 NAAQS. EPA proposes an ozone season \3\ NOX 
budget for each state covered for the ozone NAAQS.
---------------------------------------------------------------------------

    \2\ For the 10 states discussed above for which EPA has only 
quantified a minimum amount of emissions reductions needed to make 
measurable progress towards eliminating their significant 
contribution and interference with maintenance with respect to the 
1997 8-hour ozone NAAQS, the emissions budget is the emissions that 
will remain after removal of those emissions.
    \3\ Consistent with the approach taken by the Ozone Transport 
Assessment Group (OTAG), the NOX SIP call, and the CAIR, 
we propose to define the ozone season, for purposes of emissions 
reductions requirements in this rule, as May through September. We 
recognize that this ozone season for regulatory requirements differs 
from the official state-specific monitoring season.
---------------------------------------------------------------------------

    EPA recognizes that baseline emissions from a state can be affected 
by changing weather patterns, demand growth, or disruptions in 
electricity supply from other units. As a result, emissions could vary 
from year to year in a state where covered sources have installed all 
controls and taken all measures necessary to eliminate the state's 
significant contribution and interference with maintenance. As 
described in detail in section IV of this preamble, EPA proposes to 
account for the inherent variability in power system operations through 
``assurance provisions'' based on state variability limits which extend 
above the state emissions budgets. See section V for a detailed 
discussion of the assurance provisions. The small amount of variability 
allowed takes into account the inherent variability in baseline 
emissions. Section IV in this preamble describes the proposed approach 
to significant contribution and interference with maintenance and the 
state emissions budgets and variability limits in detail.
    EPA is also proposing FIPs to immediately implement the emission 
reduction requirements identified and quantified by EPA in this action. 
For some covered states, these FIPs will completely satisfy the 
emissions reductions requirements of 110(a)(2)(D)(i)(I) with respect to 
the 1997 and 2006 PM2.5 NAAQS and the 1997 ozone NAAQS. The 
exception is for the 10 eastern states for which EPA has not completely 
quantified the total significant contribution or interference with 
maintenance with respect to the 1997 ozone NAAQS and the 15 states for 
which EPA has not completely quantified total significant contribution 
or interference with maintenance with respect to the 2006 
PM2.5 NAAQS in which case the FIPs would achieve measurable 
progress towards implementing that requirement.
    The emissions reductions requirements (i.e., the ``remedy'') that 
EPA is proposing to include in the FIPs responds to the Court's 
concerns that EPA had not shown that the CAIR reduction requirements 
would get all

[[Page 45215]]

necessary reductions ``in the state'' as required by section 
110(a)(2)(D)(i)(I). The proposed 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.
    The proposed FIPs would regulate EGUs in the 32 covered states. EPA 
is proposing to regulate these sources through a program that uses 
state-specific budgets and allows intrastate and limited interstate 
trading. EPA is also taking comment on two alternative regulatory 
options. All options would achieve the emissions reductions necessary 
to address the emissions transport requirements in section 
110(a)(2)(D)(i)(I) of the CAA.
    The option EPA is proposing for the FIPs (``State Budgets/Limited 
Trading'') would use state-specific emissions budgets and allow for 
intrastate and limited interstate trading. This approach would assure 
environmental results while providing some limited flexibility to 
covered sources. The approach would also facilitate the transition from 
CAIR to the Transport Rule for implementing agencies and covered 
sources.
    The first alternative remedy option for which EPA requests comment 
would use state-specific emissions budgets and allow intrastate 
trading, but prohibit interstate trading. The second alternative remedy 
option, for which EPA also requests comment, would use state-specific 
budgets and emissions rate limits. See section V for further discussion 
of the remedy options.
    The proposed remedy option and the first alternative, both of which 
are cap-and-trade approaches, would use new allowance allocations 
developed on a different basis from CAIR. Allowance allocations, like 
the state budgets described previously, would be developed based on the 
methodology used by EPA to quantify each state's significant 
contribution and interference with maintenance. See section IV for the 
proposed state budget approach and section V for proposed allowance 
allocation approaches.
    In this action, EPA proposes to require reductions in 
SO2 and NOX emissions in the following 25 
jurisdictions that contribute significantly to nonattainment in, or 
interfere with maintenance by, a downwind area with respect to the 24-
hour PM2.5 NAAQS promulgated in September 2006: Alabama, 
Connecticut, Delaware, District of Columbia, Georgia, Illinois, 
Indiana, Iowa, Kansas, Kentucky, Maryland, Massachusetts, Michigan, 
Minnesota, Missouri, Nebraska, New Jersey, New York, North Carolina, 
Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and Wisconsin.
    EPA proposes to require reductions in SO2 and 
NOX emissions in the following 24 jurisdictions that 
contribute significantly to nonattainment in, or interfere with 
maintenance by, a downwind area with respect to the annual 
PM2.5 NAAQS promulgated in July 1997: Alabama, Delaware, 
District of Columbia, Florida, Georgia, Illinois, Indiana, Iowa, 
Kentucky, Louisiana, Maryland, Michigan, Minnesota, Missouri, New 
Jersey, New York, North Carolina, Ohio, Pennsylvania, South Carolina, 
Tennessee, Virginia, West Virginia, and Wisconsin.
    EPA also proposes to require reductions in ozone season 
NOX emissions in the following 26 jurisdictions that 
contribute significantly to nonattainment in, or interfere with 
maintenance by, a downwind area with respect to the 1997 ozone NAAQS 
promulgated in July 1997: Alabama, Arkansas, Connecticut, Delaware, 
District of Columbia, Florida, Georgia, Illinois, Indiana, Kansas, 
Kentucky, Louisiana, Maryland, Michigan, Mississippi, New Jersey, New 
York, North Carolina, Ohio, Oklahoma, Pennsylvania, South Carolina, 
Tennessee, Texas, Virginia, and West Virginia.
    As discussed previously, EPA also is proposing FIPs to directly 
regulate EGU SO2 and/or NOX emissions in the 32 
covered states. The proposed FIPs would require the 28 jurisdictions 
covered for purposes of the 24-hour and/or annual PM2.5 
NAAQS to reduce SO2 and NOX emissions by 
specified amounts. The proposed FIPs would require the 26 states 
covered for purposes of the ozone NAAQS to reduce ozone season 
NOX emissions by specified amounts.
    In response to the Court's opinion in North Carolina v. EPA, EPA 
has coordinated the compliance deadlines for upwind states to eliminate 
emissions that significantly contribute to or interfere with 
maintenance in downwind areas with the NAAQS attainment deadlines that 
apply to the downwind nonattainment and maintenance areas. EPA proposes 
to require that all significant contribution to nonattainment and 
interference with maintenance identified in this action with respect to 
the PM2.5 NAAQS be eliminated by 2014 and proposes an 
initial phase of reductions starting in 2012 (covering 2012 and 2013) 
to ensure that the reductions are made as expeditiously as practicable 
and that no backsliding from current emissions levels occurs when the 
requirements of the CAIR are eliminated. Sources will be required to 
comply by January 1, 2012 and January 1, 2014 for the first and second 
phases, respectively. With respect to the 1997 ozone NAAQS, EPA 
proposes to require an initial phase of NOX reductions 
starting in 2012 to ensure that reductions are made as expeditiously as 
practicable. Sources will be required to comply by May 1, 2012 and May 
1, 2014 for the first and second phases, respectively. EPA has 
determined, that for many states, these reductions will be sufficient 
to eliminate their significant contribution with respect to the 1997 
ozone NAAQS. EPA intends to issue a subsequent proposal that would 
require all significant contribution and interference with maintenance 
be eliminated by a future date for the 1997 ozone NAAQS. See Table 
III.A-1 for proposed lists of covered state.

 Table III.A-1--Lists of Covered States for PM2.5 and 8-Hour Ozone NAAQS
------------------------------------------------------------------------
                                     Covered for  24-   Covered for  8-
                                       hour and/or         hour ozone
                                       annual PM2.5   ------------------
               State               -------------------
                                       Required to        Required to
                                      reduce SO2 and      reduce ozone
                                           NOX             Season NOX
------------------------------------------------------------------------
Alabama...........................                 X                  X
Arkansas..........................  .................                 X
Connecticut.......................                 X                  X
Delaware..........................                 X                  X
District of Columbia..............                 X                  X
Florida...........................                 X                  X

[[Page 45216]]


Georgia...........................                 X                  X
Illinois..........................                 X                  X
Indiana...........................                 X                  X
Iowa..............................                 X   .................
Kansas............................                 X                  X
Kentucky..........................                 X                  X
Louisiana.........................                 X                  X
Maryland..........................                 X                  X
Massachusetts.....................                 X   .................
Michigan..........................                 X                  X
Minnesota.........................                 X   .................
Mississippi.......................  .................                 X
Missouri..........................                 X   .................
Nebraska..........................                 X   .................
New Jersey........................                 X                  X
New York..........................                 X                  X
North Carolina....................                 X                  X
Ohio..............................                 X                  X
Oklahoma..........................  .................                 X
Pennsylvania......................                 X                  X
South Carolina....................                 X                  X
Tennessee.........................                 X                  X
Texas.............................  .................                 X
Virginia..........................                 X                  X
West Virginia.....................                 X                  X
Wisconsin.........................                 X   .................
                                   -------------------------------------
    Totals........................                28                 26
------------------------------------------------------------------------

    As discussed previously, EPA is proposing new SO2 and/or 
NOX emissions budgets for each covered state. The budgets 
are based on the EPA's state-by-state analysis of each upwind state's 
significant contribution to nonattainment and interference with 
maintenance downwind, before accounting for the inherent variability in 
power system operations.
    As discussed in detail in section IV, the proposed approach to 
significant contribution to nonattainment and interference with 
maintenance would group the 28 states covered for the 24-hour and/or 
annual PM2.5 NAAQS in two tiers reflecting the stringency of 
SO2 reductions required to eliminate that state's 
significant contribution to nonattainment and interference with 
maintenance. There would be a stringent SO2 tier comprising 
15 states (``group 1'') and a moderate SO2 tier comprising 
13 states (``group 2''), with uniform stringency within each tier.\4\ 
For these same 28 states, there would be one annual NOX tier 
with uniform stringency of NOX reductions across all 28 
states. Similarly, for the 26 states covered for the ozone NAAQS there 
would be one ozone season NOX tier with uniform stringency 
across all 26 states.
---------------------------------------------------------------------------

    \4\ 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.
---------------------------------------------------------------------------

    The proposed stringent SO2 tier (``group 1'') would 
include Georgia, Illinois, Indiana, Iowa, Kentucky, Michigan, Missouri, 
New York, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West 
Virginia, and Wisconsin. The proposed moderate SO2 tier 
(``group 2'') would include Alabama, Connecticut, Delaware, District of 
Columbia, Florida, Kansas, Louisiana, Maryland, Massachusetts, 
Minnesota, Nebraska, New Jersey, and South Carolina.
    As discussed previously, EPA proposes to require an initial phase 
of reductions starting in 2012 (covering 2012 and 2013) requiring 
SO2 and NOX reductions in the 28 states covered 
for 24-hour and/or annual PM2.5 NAAQS. A second phase of 
reductions would be due in 2014, covering 2014 and thereafter. As 
described later, for certain states the 2014 reduction requirements 
would be more stringent, and for certain states would remain at the 
same level as the 2012 requirements.
    For the 15 states in the stringent SO2 tier (``group 
1''), the 2014 phase would substantially increase the SO2 
reduction requirements (i.e., these states would have smaller 
SO2 emissions budgets starting in 2014), reflecting the 
greater reductions needed to eliminate the portion of significant 
contribution and interference with maintenance that EPA has identified 
in this proposal from these states with respect to the 24-hour 
PM2.5 NAAQS. For the 13 states in the moderate 
SO2 tier (``group 2''), the 2014 SO2 emissions 
budgets would remain the same as the 2012 SO2 budgets for 
these states.
    The 2014 annual NOX emissions budgets for all 28 states 
covered for the 24-hour and/or annual PM2.5 NAAQS would 
remain the same as the 2012 annual NOX budgets.
    With respect to the ozone NAAQS, EPA is proposing a single phase of 
reductions which begins in 2012. Thus, the rule does not call for any 
adjustment to be made to the 2012 ozone season NOX budgets 
for the 26 states covered for the ozone NAAQS. EPA intends to issue a 
subsequent proposal that would, among other things, address whether an 
additional phase of NOX reductions is necessary to address 
all significant

[[Page 45217]]

contribution and interference with maintenance with respect to the 1997 
ozone NAAQS. While this proposal assures downwind states that they will 
receive relief from upwind reductions that will help them achieve the 
NAAQS, EPA is committed to fulfilling its obligation to assure the 
downwind states that they receive the full relief they are entitled to 
under section 110(a)(2)(D). The Agency intends to quickly address any 
remaining significant contribution to nonattainment and interference 
with maintenance in a subsequent action that will also address a new 
more stringent ozone standard that is expected to be established by EPA 
later in 2010.
    Tables III.A-2 and III.A-3 show projected Transport Rule emissions 
reductions for EGUs in all states that EPA proposes to cover.

  Table III.A-2--Projected SO2 and NOX EGU Emissions in Covered States With the Transport Rule \5\ Compared to Base Case \6\ Without Transport Rule or
                                                                          CAIR
                                                                     [Million tons]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                               2012                                            2014
                                                            2012  Base       Transport         2012         2014  Base       Transport         2014
                                                               case            rule          Emissions         case            rule          Emissions
                                                             emissions       emissions      reductions       emissions       emissions      reductions
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO2.....................................................             8.4             3.4             5.0             7.2             2.6             4.6
Annual NOX..............................................             2.0             1.3             0.7             2.0             1.3             0.7
Ozone Season NOX........................................             0.7             0.6             0.1             0.7             0.6             0.1
--------------------------------------------------------------------------------------------------------------------------------------------------------


  Table III.A-3--Projected SO2 and NOX EGU Emissions in Covered States With the Transport Rule Compared to 2005
                                                Actual Emissions
                                                 [Million tons]
----------------------------------------------------------------------------------------------------------------
                                                       2012            2012            2014            2014
                                   2005  Actual      Transport       Emissions       Transport       Emissions
                                     emissions         rule         reductions         rule         reductions
                                                     emissions       from 2005       emissions       from 2005
----------------------------------------------------------------------------------------------------------------
SO2.............................             8.9             3.4             5.5             2.6             6.3
Annual NOX......................             2.7             1.3             1.4             1.3             1.4
Ozone Season NOX................             0.9             0.6             0.3             0.6             0.3
----------------------------------------------------------------------------------------------------------------

    In addition to the emissions reductions shown previously, EPA 
projects other substantial benefits, as described in section IX in this 
preamble. Air quality modeling was used to quantify the improvements in 
PM2.5 and ozone concentrations that are expected to result 
from the emissions reductions in 2014. The results of this modeling 
were used to calculate the average reduction in annual average 
PM2.5, 24-hour average PM2.5, and 8-hour ozone 
concentrations for monitoring sites in the eastern U.S. that are 
projected to be nonattainment in the 2014 base case. For annual 
PM2.5 and 24-hour PM2.5, the average reductions 
are 2.4 micrograms per cubic meter ([mu]g/m\3\) and 4.3 [mu]g/m\3\, 
respectively. The average reduction in 8-hour ozone at monitoring sites 
projected to be nonattainment in the 2014 base case is 0.3 parts per 
billion (ppb). The reductions in annual PM2.5, 24-hour 
PM2.5, and ozone concentrations for individual nonattainment 
and/or maintenance sites are provided in section IX.
---------------------------------------------------------------------------

    \5\ Projected Transport Rule emissions result from individual 
stae budgets in the proposed approach and include some banking of 
allowances in 2012 adn use of that bank in 2014.
    \6\ EPA's base case EGU emissions modeling does not assume 
enforceable SO2 or NOX reductions attributed 
to the Transport Rule or CAIR. In this base case, a unit with 
existing SO2 or NOX control equipment, but 
without an enforceable federal or state control requirement, is 
allowed to choose its most economic approach to operation within 
existing Acid Rain Program requirements and may opt not to operate a 
control. See section IV.C.1 and the IPM Documentation for further 
information on the base case modeling.
---------------------------------------------------------------------------

    Table III.A-4 compares projected EGU emissions with the Transport 
Rule to projected EGU emissions with CAIR.

Table III.A-4--Simple Comparison of SO2 and NOX Emissions From Electric Generating Units in States in the CAIR or Transport Rule Regions * for Each Rule
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                               2005                    2012                            2014
                                                                         -------------------------------------------------------------------------------
                                                                              Actual      Transport rule      CAIR **     Transport rule      CAIR **
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO2 (Million Tons)......................................................             9.5             4.1             5.1             3.3            4.6
NOX (Million Tons)........................  Annual......................             2.9             1.6             1.7             1.6             1.7
                                            Ozone Season................             1.0             0.7             0.8             0.7             0.8
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Emissions totals include states covered by either the Transport Rule or CAIR. For PM2.5 (SO2 and annual NOX), the following 30 states are included:
  AL, CT, DE, DC, FL, GA, IL, IN, IA, KS, KY, LA, MD, MA, MI, MN, MS, MO, NE, NJ, NY, NC, OH, PA, SC, TN, TX, VA, WV, WI. For ozone (ozone-season NOX),
  the following 30 states are included: AL, AR, CT, DE, DC, FL, GA, IL, IN, IA, KS, KY, LA, MD, MA, MI, MS, MO, NJ, NY, NC, OH, OK, PA, SC, TN, TX, VA,
  WV, WI.
** CAIR SO2 totals are interpolations from emissions analysis originally done for 2010 and 2015. CAIR NOX totals are as originally projected for 2010.
  This CAIR modeling represents a scenario that differed somewhat from the final CAIR (the modeling did not include a regionwide ozone season NOX cap
  and included PM2.5 requirements for the state of Arkansas).


[[Page 45218]]

    In addition to discussion of EPA's proposed regulatory approach 
(discussed in sections IV and V), this preamble also covers the 
stakeholder outreach EPA conducted (section VI), SIP submissions 
(section VII), permitting (section VIII), projected benefits of the 
proposed rule (section IX), economic impacts (section X), end-use 
energy efficiency (section XI), and statutory and executive order 
reviews (section XII).
    Table III.A-5 shows the results of the cost and benefits analysis 
for the proposed and alternate remedies. Further discussion of these 
results is contained in preamble section XII-A and in the Regulatory 
Impacts Analysis. A listing of health and welfare effects is provided 
in RIA Table 1-6. Estimates here are subject to uncertainties discussed 
further in the body of the document. The social costs are the loss of 
household utility as measured in Hicksian equivalent variation. The 
capital costs spent for pollution controls installed for CAIR were not 
included in the annual social costs since the Transport Rule did not 
lead to their installation. Those CAIR-related capital investments are 
roughly estimated to have an annual social cost less than $1.15 to $ 
1.29 billion (under the two discount rates.)
    Most of the estimated PM-related benefits in this rule accrue to 
populations exposed to higher levels of PM2.5. Of these 
estimated PM-related mortalities avoided, about 80 percent occur among 
populations initially exposed to annual mean PM2.5 level of 
10 [mu]g/m\3\ and about 97 percent occur among those initially exposed 
to annual mean PM2.5 level of 7.5 [mu]g/m\3\. These are the 
lowest air quality levels considered in the Laden et al. (2006) and 
Pope et al. (2002) studies, respectively. This fact is important, 
because as we estimate PM-related mortality among populations exposed 
to levels of PM2.5 that are successively lower, our 
confidence in the results diminishes. However, our analysis shows that 
the great majority of the impacts occur at higher exposures.

 Table III.A-5--Summary of Annual Benefits, Costs, and Net Benefits of Versions of the Proposed Remedy Option in
                                                    2014 \a\
                                               [Billions of 2006$]
----------------------------------------------------------------------------------------------------------------
                                    Preferred remedy--State
           Description             budgets/ limited trading       Direct control           Intrastate trading
----------------------------------------------------------------------------------------------------------------
Social costs:
    3% discount rate.............  $2.03...................  $2.68...................  $2.49.
    7% discount rate.............  $2.23...................  $2.91...................  $2.70.
Health-related benefits: b, c
    3% discount rate.............  $118 to $288 + B........  $117 to $286 + B........  $113 to $276 + B.
    7% discount rate.............  $108 to $260 + B........  $108 to $262 + B........  $104 to $252 + B.
Net benefits (benefits-costs):
    3% discount rate.............  $116 to $286............  $115 to $283............  $110 to $273.
    7% discount rate.............  $105 to $258............  $105 to $259............  $101 to $249.
----------------------------------------------------------------------------------------------------------------
Notes: (a) All estimates are rounded to three significant digits and represent annualized benefits and costs
  anticipated for the year 2014. For notational purposes, unquantified benefits are indicated with a ``B'' to
  represent the sum of additional monetary benefits and disbenefits. Data limitations prevented us from
  quantifying these endpoints, and as such, these benefits are inherently more uncertain than those benefits
  that we were able to quantify. (b) The reduction in premature mortalities account for over 90 percent of total
  monetized benefits. Benefit estimates are national. Valuation assumes discounting over the SAB-recommended 20-
  year segmented lag structure described in Chapter 5. Results reflect 3 percent and 7 percent discount rates
  consistent with EPA and OMB guidelines for preparing economic analyses (U.S. EPA, 2000; OMB, 2003). The
  estimate of social benefits also includes CO2-related benefits calculated using the social cost of carbon,
  discussed further in Chapter 5. Benefits are shown as a range from Pope et al. (2002) to Laden et al. (2006).
  Monetized benefits do not include unquantified benefits, such as other health effects, reduced sulfur
  deposition or visibility. These models assume that all fine particles, 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. (c) Not all possible
  benefits or disbenefits are quantified and monetized in this analysis. B is the sum of all unquantified
  benefits and disbenefits. Potential benefit categories that have not been quantified and monetized are listed
  in RIA Table 1-4.

B. Background

1. What is the source of EPA's authority for this action?
    The statutory authority for this action is provided by the CAA, as 
amended (42 U.S.C. 7401 et seq.). Relevant portions of the CAA include, 
but are not necessarily limited to, sections 110(a)(2)(D), 110(c)(1), 
and 301(a)(1).
    Section 110(a)(2)(D) of the CAA, often referred to as the ``good 
neighbor'' provision of the Act, 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:
    (D) Contain adequate provisions--
    (i) Prohibiting, consistent with the provisions of this subchapter, 
any source or other type of emissions activity within the State from 
emitting any air pollutant in amounts which will--
    (I) Contribute significantly to nonattainment in, or interfere with 
maintenance by, any other State with respect to any such national 
primary or secondary ambient air quality standard, or
    (II) Interfere with measures required to be included in the 
applicable implementation plan for any other State under part C of this 
subchapter to prevent significant deterioration of air quality or to 
protect visibility.
    (ii) Insuring compliance with the applicable requirements of 
sections 7426 and 7415 of this title (relating to interstate and 
international pollution abatement). 42 U.S.C. 7410(a)(2)(D).
    This proposal addresses the requirement in section 
110(a)(2)(D)(i)(I) regarding the prohibition of emissions within a 
state that significantly contribute to nonattainment or interfere with 
maintenance of the NAAQS in any other state. As discussed in greater 
detail later, 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 v. EPA, 213 F.3d 
663 (DC Cir. 2000). The CAIR, promulgated in 2005, was remanded by the 
DC Circuit in North Carolina v. EPA, 531 F.3d 896 (DC Cir. 2008), 
modified on reh'g, 550 F.3d. 1176 (DC Cir. 2008). These decisions 
provide additional guidance regarding the requirements of section 
110(a)(2)(D)(i)(I) and are discussed later in this section.
    Section 301(a)(1) of the CAA gives the Administrator of EPA general 
authority to ``prescribe such regulations as are necessary to carry out 
[her] functions under this chapter.'' 42 U.S.C. 7601(a)(1). Pursuant to 
this section, EPA has authority to clarify the applicability of CAA 
requirements. In this action,

[[Page 45219]]

EPA is clarifying the applicability of section 110(a)(2)(D)(i)(I) by 
proposing to identify SO2 and NOX emissions that 
each affected state must prohibit pursuant to that section with respect 
to the PM2.5 NAAQS promulgated in 1997 and 2006 and the 8-
hour ozone NAAQS promulgated in 1997. The improvements in air quality 
that would result from the reductions in upwind state emissions that 
EPA is proposing to require would assist downwind states affected by 
transported pollution in developing, pursuant to section 110 of the 
CAA, their SIPs to provide for expeditious attainment and maintenance 
of the NAAQS.
    Section 110(a) of the CAA assigns to each state both the primary 
responsibility for attaining and maintaining the NAAQS within such 
state, 42 U.S.C. 7410(a)(1), and the primary responsibility for 
prohibiting emissions activity within the state which will 
significantly contribute to nonattainment or interfere with maintenance 
in a downwind area. 42 U.S.C. 7410(a)(2)(D)(i)(I). States fulfill these 
CAA obligations through the SIP process described in section 110(a) of 
the Act.
    Section 110(c)(1) of the Act, however, requires EPA to act when a 
state has not been able to or has not fulfilled its obligation to 
submit a SIP that meets the requirements of the Act. Specifically, 
section 110(c)(1) provides that: The Administrator shall promulgate a 
Federal implementation plan at any time within 2 years after the 
Administrator--
    (A) Finds that a State has failed to make a required submission or 
finds that the plan or plan revision submitted by the State does not 
satisfy the minimum criteria established under subsection (k)(1)(A) of 
this section, or
    (B) Disapproves a State implementation plan submission in whole or 
part, unless the State corrects the deficiency, and the Administrator 
approves the plan or plan revision, before the Administrator 
promulgates such Federal implementation plan.

    42 U.S.C. 7410(c)(1). Section 110(k)(1)(A), in turn, calls for the 
Administrator to establish criteria for determining whether SIP 
submissions are complete. 42 U.S.C. 7410(k)(1)(A).

    As discussed in greater detail in section VII, for all states 
covered by the FIPs proposed in this action, EPA either has taken, has 
proposed to take, or believes it may need to take one of the following 
actions with respect to the 1997 ozone NAAQS, the 1997 PM2.5 
NAAQS and/or the 2006 PM2.5 NAAQS: (1) Find that the state 
has failed to make a SIP submission required by section 
110(a)(2)(D)(i)(I) or section 110(k)(5) of the Act; (2) find that such 
a SIP submission is incomplete; or (3) disapprove such a SIP 
submission. Once EPA has taken one of the these actions, pursuant to 
section 110(c)(1), it has authority to promulgate a FIP directly 
implementing the requirements of section 110(a)(2)(D)(i)(I), provided 
the state has not submitted and EPA has not approved a SIP submission 
that corrects the SIP deficiency prior to promulgation of the FIP.
2. What air quality problems does this proposal address?
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. See EPA, Air 
Quality Criteria for Particulate Matter (EPA/600/P-99/002bF, October 
2004) at 9.2.2.3. See also integrated science assessment for the PM 
NAAQS review, December 2009, http://cfpub.epa.gov/ncea/cfm/
recordisplay.cfm?deid=216546. Individuals particularly sensitive to 
fine particle exposure include older adults, people with heart and lung 
disease, and children. This rule, and the NAAQS to which it is related, 
consider the effects of fine particles on vulnerable populations (see 
further discussion in section XII.G and section XII.J of this notice). 
More detailed information on health effects of fine particles can be 
found on EPA's Web site at: http://epa.gov/pm/standards.html.
    In addition to effects on public health, fine particles are linked 
to a number of public welfare effects. First, PM2.5 are the 
major cause of reduced visibility (haze) in parts of the United States, 
including many of our national parks and wilderness areas. For more 
information about visibility, visit EPA's Web site at http://
www.epagov/visibility. Second, particles can be carried over long 
distances by wind and then settle on ground or water. The effects of 
this settling include: 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. More information about these 
effects is available at EPA's Web site at http://www.epa.gov/acidrain/
effects/index.html. Finally, particle pollution can stain and damage 
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 average 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\.
    In the preamble to the final rule for CAIR in May 2005, EPA 
discussed ambient monitoring for 2001-2003, the most recent 3-year 
period available at the time. These results showed widespread 
exceedances of the 15 [mu]g/m\3\ annual PM2.5 standard in 
the eastern United States, with additional exceedances in parts of 
California and one county in Montana. At that time, 82 counties in the 
U.S. had at least one monitor that violated the 1997 annual 
PM2.5 standard.
    The PM2.5 ambient air quality monitoring for the 2006-
2008 period (most recent available) shows significant improvements. 
Nonetheless, areas which continue to violate the 15 [mu]g/m\3\ annual 
PM2.5 standard are located across a significant portion of 
the eastern half of the United States, in parts of California and one 
county in Arizona. Based on these nationwide data, 23 counties have at 
least one monitor that violates the annual PM2.5 standard.
    The PM2.5 ambient air quality monitoring for this same 
2006-2008 time period shows that areas violating the 2006 24-hour 
PM2.5 standard of 35 [mu]g/m\3\ (i.e., the revised 2006 
standard for 24-hour PM2.5) are located across much of the 
eastern half of the United States, in parts of California, and in some 
counties in several other western states--Alaska, Washington, Oregon, 
Utah, and Arizona. Based on these nationwide data, 52 counties have at 
least one monitor that violates the 24-hour PM2.5 standard.
    EPA believes that a great deal of the improvement in 
PM2.5 annual and 24-hour concentrations in the eastern U.S. 
can be attributed to EGU SO2 reductions achieved due to the 
CAIR. While the CAIR requirements related to SO2 did not 
begin until 2010, many actions were taken by EGU owners and operators 
in anticipation of those requirements. Emissions of SO2 from 
EGUs covered by the CAIR that were also in the acid rain

[[Page 45220]]

program (under CAA Title IV) tracking system decreased from 10.2 
million tons in 2005 to 7.6 million tons in 2008. Almost all of these 
emissions reductions were achieved in the areas of the eastern United 
States covered by the CAIR. See http://www.epa.gov/airmarkt/progress/
ARP_4.html. EPA believes that there would be substantially more 
nonattainment counties for both the annual and 24-hour standards if the 
CAIR were not in effect.
    As required by the CAA, and in response to litigation over the 2006 
standards, EPA is currently conducting a review of the 2006 
PM2.5 standards. Information and documents related to this 
review are available at: http://epa.gov/ttn/naaqs/standards/pm/s_pm_
index.html. EPA expects to complete this review and to publish any 
revised standards that may result from the review by October 2011. EPA 
is planning to propose the revised standards by February 2011.
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 recent epidemiological evidence indicating 
that there is a correlation between short-term ozone exposure and 
premature mortality.
    People who are particularly susceptible to the effects of ozone 
include people with respiratory diseases, such as asthma. Those who are 
exposed to higher levels of ozone include adults and children who are 
active outdoors. This rule, and the NAAQS which it is related to, 
consider the effects of ozone on vulnerable populations (see further 
discussion in section XII.G and section XII.J of this notice).
    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. More detailed information on 
effects of ozone can be found at the following EPA Web site: http://
www.epa.gov/ttn/naaqs/standards/ozone/s_o3_index.html.
    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.
    At the time EPA published the CAIR and the CAIR FIP rulemakings, 
wide geographic areas, including most of the nation's major population 
centers, experienced ozone levels that violated the 1997 NAAQS of 8-
hour ozone 0.08 ppm (effectively 0.084 ppm as a result of rounding). 
These areas included much of the eastern part of the United States and 
large areas of California. The EPA published the 8-hour ozone 
attainment and nonattainment designations in the Federal Register on 
April 30, 2004 (69 FR 23858). These designations, based on ozone season 
monitoring data for the 2001-2003 time period, resulted in 112 areas 
designated as nonattainment. As of December 2009, significant emissions 
reductions have allowed 58 of the original 112 nonattainment areas to 
be re-designated to attainment. In addition, a number of areas still 
designated as nonattainment ozone monitoring data for 2006-2008 (most 
recent data available) show levels below the standard. EPA believes a 
number of factors contributed to NOX emissions reductions 
subsequent to the 2001-2003 time period. First, EGU emissions were 
substantially reduced as EGUs in the eastern U.S. came into compliance 
with the NOX SIP Call. A series of 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. Additional information on emissions and air 
quality trends are available in EPA's 2007 and 2008 air quality trends 
reports, which are available at: http://www.epa.gov/airtrends/.
    Second, mobile source emissions standards for onroad gasoline and 
vehicle emissions standards began to reduce mobile source emissions as 
the fleet began turning over vehicles to meet tightened NOX 
emissions standards. Continued improvement in ozone is expected with 
continued reductions in mobile source emissions.
    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 will issue final standards soon. Information on 
the 2008 revisions to the ozone standard, and on all subsequent 
activity based on the reconsideration, is available at: http://
www.epa.gov/air/ozonepollution/actions.html#sep09s.
3. Which NAAQS does this proposal address?
    This proposed action addresses the requirements of CAA section 
110(a)(2)(D)(i)(I) as they relate to:
    (1) The 1997 annual PM2.5 standards,
    (2) The 2006 daily PM2.5 standards, and
    (3) The 1997 ozone standards
    The original CAIR and CAIR FIP rules, which pre-dated the 2006 
standards, addressed the 1997 ozone and PM2.5 standards 
only. The 1997 8-hour ozone standard is 0.08 ppm. The 1997 
PM2.5 standards promulgated in 1997 established a 15 [mu]g/
\3\ standard for 24-hour PM2.5 and a 65 [mu]g/m\3\ standard 
for annual PM2.5. In 2006, the 24-hour PM2.5 
standard was lowered to 35 [mu]g/m\3\ and the 15 [mu]g/m\3\ annual 
PM2.5 standard was left unchanged.

[[Page 45221]]

    For this proposal, EPA fully addresses the requirements of CAA 
section 110(a)(2)(D)(i)(I) for the annual PM2.5 standard of 
15 [mu]g/m\3\. For the 24-hour standard of 35 [mu]g/m\3\ and 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, but for the 
remaining states EPA will address whether further requirements are 
needed.
    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.
4. EPA Transport Rulemaking History
a. CAA Provisions
    For almost 40 years, Congress has focused major efforts on curbing 
ground-level ozone. In 1970, Congress amended the CAA to require, in 
Title I, that EPA issue and periodically review and, if necessary, 
revise NAAQS for ubiquitous air pollutants (sections 108 and 109). 
Congress required the states to submit SIPs to attain and maintain 
those NAAQS, and Congress included, in section 110, a list of minimum 
requirements that SIPs must meet. Congress anticipated that areas would 
attain the NAAQS by 1975.
    In 1977, Congress amended the CAA by providing, among other things, 
additional time for areas that were not attaining the ozone NAAQS to do 
so, as well as by imposing specific SIP requirements for those 
nonattainment areas. These provisions first required the designation of 
areas as attainment, nonattainment, or unclassifiable, under section 
107; and then required that SIPs for ozone nonattainment areas include 
the additional provisions set out in part D of Title I, as well as 
demonstrations of attainment of the ozone NAAQS by either 1982 or 1987 
(section 172).
    In addition, the 1977 Amendments included two provisions focused on 
interstate transport of air pollutants: the predecessor to current 
section 110(a)(2)(D), which requires SIPs for all areas to constrain 
emissions with certain adverse downwind effects; and section 126, 
which, in general, authorizes a downwind state to petition EPA to 
impose limits directly on upwind sources found to adversely affect that 
state. Section 110(a)(2)(D)(i)(I), which is key to the present action, 
is described in more detail later.
    In 1990, Congress amended the CAA to better address, among other 
things, continued nonattainment of the 1-hour ozone NAAQS, the 
requirements that would apply if EPA revised the 1-hour standard, and 
transport of air pollutants across state boundaries (Pub. L. 101-549, 
Nov. 15, 1990, 104 Stat. 2399, 42 U.S.C. 7401-7671q).
    As amended in 1990, the CAA further requires EPA to designate areas 
as attainment, nonattainment, and unclassifiable under a revised NAAQS 
(section 107(d)(1); section 6103, Pub. L. 105-178). The CAA authorizes 
EPA to classify areas that are designated nonattainment under the new 
NAAQS and to establish for those areas attainment dates that are as 
expeditious as practicable, but not to exceed 10 years from the date of 
designation (section 172(a)).
    All areas are required to submit SIPs within certain timeframes 
(section 110(a)(1)), and those SIPs must include specified provisions, 
under section 110(a)(2). In addition, SIPs for nonattainment areas are 
generally required to include additional specified control 
requirements, as well as controls providing for attainment of any 
revised NAAQS and periodic reductions providing ``reasonable further 
progress'' in the interim (section 172(c)). If states do not submit 
SIPs in a timely or approvable manner, EPA has the authority to make 
findings of failure to submit or impose FIPs on specific sources in the 
state that contribute to downwind nonattainment and interference with 
maintenance. Significant contribution and interference with maintenance 
are discussed in detail in section IV later.
    The 1990 Amendments reflect general awareness by Congress that 
ozone is a regional, and not merely a local, problem. Ozone and its 
precursors may be transported long distances across state lines, 
thereby exacerbating ozone problems downwind. Ozone transport is 
recognized as a major reason for the persistence of the ozone problem, 
notwithstanding the imposition of numerous controls, both Federal and 
State, across the country.
    The CAA further addresses interstate transport of pollution in 
section 126, which Congress revised slightly in 1990. Subsection (b) of 
that provision authorizes each state (or political subdivision) to 
petition EPA for a finding designed to protect that entity from upwind 
sources of air pollutants.\7\
---------------------------------------------------------------------------

    \7\ In addition, section 115 authorizes EPA to require a SIP 
revision in certain circumstances when one or more sources within a 
state ``cause or contribute to air pollution which may reasonably be 
anticipated to endanger public health or welfare in a foreign 
country.''
---------------------------------------------------------------------------

    In addition, the 1990 Amendments added section 184, which 
delineates a multi-state ozone transport region (OTR) in the Northeast, 
requires specific additional controls for all areas (not only 
nonattainment areas) in that region, and establishes the Ozone 
Transport Commission (OTC) for the purpose of recommending to EPA 
regionwide controls affecting all areas in that region. At the same 
time, Congress added section 176A, which authorized the formation of 
transport regions for other pollutants and in other parts of the 
country.
    In September 1994, the Northeast OTC states signed a Memorandum of 
Understanding (MOU) committing to reduce NOX emissions 
throughout the region. In 1999 through 2002, most of the OTC states 
achieved substantial NOX reductions through an ozone season 
cap and trade program for NOX called the OTC NOX 
Budget Program, which EPA administered, and through NOX 
emissions rate limits from certain coal plants under Title IV.
    Separate from activity in the OTC, EPA and the Environmental 
Council of the States (ECOS) formed the OTAG in 1995. This workgroup 
brought together interested states and other stakeholders, including 
industry and environmental groups. Its primary objective was to assess 
the ozone transport problem and develop a strategy for reducing ozone 
pollution throughout the eastern half of the United States.
    Notwithstanding significant efforts, the states generally were not 
able to meet the November 15, 1994 statutory deadline for the 
attainment demonstration and rate of progress (ROP) SIP submissions 
required under section 182(c). The major reason for this failure was 
that at that time, states with downwind nonattainment areas were not 
able to address transport from upwind areas. As a result, EPA 
recognized that development of the necessary technical information, as 
well as the control measures necessary to achieve the large level of 
reductions likely to be required, had been particularly difficult for 
the states affected by ozone transport.
    Accordingly, as an administrative remedial matter, EPA established 
new timeframes for the required SIP submittals. To allow time for 
states to incorporate the results of the OTAG

[[Page 45222]]

modeling into their local plans, EPA extended the submittal date to 
April 1998.\8\ The OTAG's air quality modeling and recommendations 
formed the basis for what became the NOX SIP Call rulemaking 
and included the most comprehensive analyses of ozone transport ever 
conducted. The EPA participated extensively in the OTAG process that 
generated much useful technical and modeling information on regional 
ozone transport.
---------------------------------------------------------------------------

    \8\ Guidance for Implementing the 1-hour Ozone and Pre-Existing 
PM10 NAAQS, Memorandum from Richard D. Wilson, dated December 29, 
1997.
---------------------------------------------------------------------------

    OTAG was established to address transport issues associated with 
meeting the 1-hour standard. The EPA did not promulgate the 8-hour 
standard until shortly after OTAG concluded; thus, OTAG did not 
recommend strategies to address the 8-hour NAAQS. However, because EPA 
had proposed an 8-hour standard, OTAG did examine the impacts of 
different strategies on 8-hour average ozone predictions. They found 
that ozone transport caused problems for downwind areas under either 
the 1-hour or 8-hour standard.
    EPA's Transport SIP Call Regulatory Efforts. Shortly after OTAG 
began its work, EPA indicated that it intended to issue a SIP call to 
require states to implement the reductions necessary to address the 
ozone transport problem. On January 10, 1997 (62 FR 1420), EPA 
published a notice of intent and indicated that before taking final 
action, EPA would carefully consider the technical work and any 
recommendations of OTAG. The EPA published the NPR for the 
NOX SIP Call by notice dated November 7, 1997 (62 FR 60319). 
The NPR proposed to make a finding of significant contribution due to 
transported NOX emissions to nonattainment or maintenance 
problems downwind and to assign NOX emissions budgets for 23 
jurisdictions. In light of OTAG's work and additional information, EPA 
was able to assess ozone transport as it relates to the 8-hour NAAQS 
and to set forth requirements as necessary to address the 8-hour 
standard in the rulemaking. The regional reductions of NOX 
that would have been achieved through this SIP call for the 1-hour 
NAAQS were key components for meeting the new 8-hour ozone standard in 
a cost-effective manner. Therefore, EPA believed that the OTAG 
recommendations for how to address ozone transport were valid for both 
NAAQS.
    The EPA published a supplemental notice of proposed rulemaking 
(SNPR) dated May 11, 1998 (63 FR 25902), which proposed a model 
NOX budget trading program and state reporting requirements 
and provided the air quality analyses of the proposed statewide 
NOX emissions budgets.
    Revision of the Ozone NAAQS. On July 18, 1997 (62 FR 38856), EPA 
issued its final action to revise the NAAQS for ozone. The EPA's 
decision to revise the standard was based on the Agency's review of the 
available scientific evidence linking exposures to ambient ozone to 
adverse health and welfare effects at levels allowed by the pre-
existing 1-hour ozone standards. The 1-hour primary standard was 
replaced by an 8-hour standard at a level of 0.08 ppm, with a form 
based on the 3-year average of the annual fourth-highest daily maximum 
8-hour average ozone concentration measured at each monitor within an 
area. The new primary standard provided increased protection to the 
public, especially children and other at-risk populations, against a 
wide range of ozone-induced health effects.
    The pre-existing 1-hour secondary ozone standard was replaced by an 
8-hour standard identical to the new primary standard. The new 
secondary standard provided increased protection to the public welfare 
against ozone-induced effects on vegetation.
    Section 126 Petitions. In a separate rulemaking, EPA proposed 
action on petitions submitted by 8 northeastern states \9\ under 
section 126 of the CAA. Each petition specifically requested that EPA 
make a finding that NOX emissions from certain major 
stationary sources significantly contributed to ozone nonattainment 
problems in the petitioning state. Both the NOX SIP Call and 
the section 126 petitions were designed to address ozone transport 
through reductions in upwind NOX emissions. However, the 
EPA's response to the section 126 petitions differed from EPA's action 
in the NOX SIP Call rulemaking in several ways. In the 
NOX SIP Call, EPA was determining that certain states were 
or would be significantly contributing to nonattainment or maintenance 
problems in downwind states. The EPA required the upwind states to 
submit SIP provisions to reduce the amounts of each state's 
NOX emissions that significantly contributed to downwind air 
quality problems. The states had the discretion to select the mix of 
control measures to achieve the necessary reductions. By contrast, 
under section 126, if findings of significant contribution were made 
for any sources identified in the petitions, EPA would have determined 
the necessary emissions limits to address the amount of significant 
contribution and would have directly regulated the sources. A section 
126 remedy would have applied only to sources in states named in the 
petitions.
---------------------------------------------------------------------------

    \9\ The 8 states were Connecticut, Massachusetts, Maine, New 
Hampshire, New York, Pennsylvania, Rhode Island, and Vermont.
---------------------------------------------------------------------------

b. NOX SIP Call
    Based on the findings of OTAG, EPA proposed a rulemaking known as 
the NOX SIP Call in 1997 and finalized it in 1998. (See 
``Finding of Significant Contribution and Rulemaking for Certain States 
in the Ozone Transport Assessment Group Region for Purposes of Reducing 
Regional Transport of Ozone; Rule,'' (63 FR 57356).) This rule 
concluded that NOX emissions in 22 states and the District 
of Columbia contribute to ozone nonattainment in other states, and the 
rule required affected states to amend their SIPs and limit 
NOX emissions. EPA set an ozone season NOX budget 
for each affected state, essentially a cap on ozone season (summertime) 
NOX emissions in the state. Sources in the affected states 
were given the option to participate in a regional cap and trade 
program. The first control period was scheduled for the 2003 ozone 
season.
    In response to litigation over EPA's final NOX SIP Call 
rule, the Court issued two decisions concerning the NOX SIP 
Call and its technical amendments.\10\ The Court decisions, discussed 
later, generally upheld the NOX SIP Call and technical 
amendments, including EPA's interpretation of the definition of 
''contribute significantly'' under CAA section 110(a)(2)(D). The 
litigation over the NOX SIP Call coincided with the 
litigation over the 8-hour NAAQS. Because of the uncertainty caused by 
the litigation on the 8-hour NAAQS, EPA stayed the portion of the 
NOX SIP Call based on the 8-hour NAAQS (65 FR 56245, 
September 18, 2000). Therefore, for the most part, the Court did not 
address NOX SIP Call requirements under the 8-hour ozone 
NAAQS.
(1) What was the NOX SIP Call?
---------------------------------------------------------------------------

    \10\ See Michigan v. EPA, 213 F.3d 663 (DC Cir. 2000), cert. 
denied, 532 U.S. 904 (2001) (NOX SIP call) and 
Appalachian Power v. EPA, 251 F.3d 1026 (DC Cir. 2001) (technical 
amendments).
---------------------------------------------------------------------------

    The NOX SIP Call was EPA's principal effort to reduce 
interstate transport of precursors for both the 1-hour ozone NAAQS and 
the 8-hour ozone NAAQS. The EPA's rulemaking was based on its 
consideration of OTAG's recommendations, as well as information 
resulting from EPA's additional work, and extensive public input 
generated through notice-and-comment rulemaking. The EPA believed

[[Page 45223]]

that requiring NOX emissions reductions across the region in 
amounts achievable by uniform controls was a reasonable, cost-effective 
step to take to mitigate ozone nonattainment in downwind states for 
both the 1-hour and 8-hour standards.
    It was also EPA's goal to ensure that sufficient regional 
reductions were achieved to mitigate ozone transport in the eastern 
half of the United States and thus, in conjunction with local controls, 
enable nonattainment areas to attain and maintain the ozone NAAQS.
    This NOX SIP Call required those jurisdictions that EPA 
determined significantly contribute to 1-hour and 8-hour ozone 
nonattainment problems in downwind states to revise their SIPs to 
include NOX control measures to mitigate the significant 
ozone transport during summer months known as the ``ozone season'' 
(May-September). The EPA determined emissions reductions requirements 
for the covered states and source categories (see section IV.A for a 
description of the approach EPA used to determine emissions reductions 
requirements). The affected states were required to submit SIPs 
providing the specified amounts of emissions reductions. By eliminating 
these amounts of NOX emissions, the control measures would 
assure that the remaining NOX emissions would meet the level 
identified in the rule as the state's NOX emissions budget 
and would not ``significantly contribute to nonattainment, or interfere 
with maintenance by,'' a downwind state, under section 
110(a)(2)(D)(i)(I).
    The SIP requirements permitted each state to determine what 
measures to adopt to prohibit the significant amounts and hence meet 
the necessary emissions budget. Consistent with OTAG's recommendations 
to achieve decreased NOX emissions primarily from large 
stationary sources in a trading program, EPA encouraged states to 
consider electric utility and large boiler controls under a cap and 
trade program as a cost-effective strategy. The EPA also recognized 
that promotion of energy efficiency could contribute to a cost-
effective strategy. See section V.D.1 for a discussion on the approach 
taken to implement the emissions reductions requirements in the 
NOX SIP Call.
(2) Legal Challenges to the NOX SIP Call
    Several petitioners challenged the NOX SIP Call in the 
United States Court of Appeals for the District of Columbia Circuit (DC 
Circuit). In Michigan v. EPA, 213 F.3d 663 (DC Cir., 2000), cert. 
denied, 532 U.S. 904 (2001), the Court upheld the rule in most 
respects. Of greatest relevance here, the Court upheld the essential 
features of EPA's approach to identifying and eliminating states'' 
NOX emissions that significantly contribute to downwind 
nonattainment. It upheld key aspects of EPA's air quality modeling and 
its use of cost-effectiveness criteria in defining states'' 
``significant contribution.'' See id. at 673-79. In addition, it 
accepted EPA's use of a uniform control requirement (i.e., requiring 
all covered jurisdictions, regardless of amount of contribution, to 
reduce NOX emissions by an amount achievable with highly 
cost effective controls). See id. at 679-80. The Court, however, agreed 
with petitioners that certain specific applications of EPA's approach 
were flawed. It thus vacated the rule with respect to Wisconsin, 
Missouri, and Georgia, and held that EPA had failed to provide adequate 
notice on two specific issues (a change in the definition of EGU and a 
change in control level assumed for specific sources). See id. at 681-
85, 692-94. The Court also subsequently delayed the implementation date 
to May 31, 2004. Michigan v. EPA, 2000 WL 1341477 (DC Cir. 2000).
    The decision resolved only issues involving the 1-hour ozone NAAQS 
and did not resolve any issues involving the 8-hour NAAQS, which 
provided another basis for the rule. See id. at 670-71. EPA ultimately 
stayed the 8-hour basis of the NOX SIP Call. See 65 FR 
56245. In addition, in a subsequent case that reviewed separate EPA 
rulemakings making technical corrections to the NOX SIP 
Call, the DC Circuit remanded the case for a better explanation of 
EPA's methodology for computing the growth component in the EGU heat 
input calculation. See Appalachian Power Co. v. EPA, 251 F.3d 1026 (DC 
Cir. 2001). More recently, the Court also rejected a challenge to a 
subsequent EPA rule withdrawing EPA's findings of significant 
contribution for Georgia for the 1-hour ozone standard. See North 
Carolina v. EPA, 587 F.3d 422 (DC Cir. 2009).
(3) How the NOX Budget Trading Program (NBP) Worked
    The NBP was a market-based cap and trade program created to reduce 
the regional transport of emissions of NOX from power plants 
and other large combustion sources that contribute to ozone 
nonattainment in the eastern United States. Over six ozone seasons 
(2003-2008), the NBP significantly lowered NOX emissions 
from affected sources, contributing to improvements in regional air 
quality across the Midwest, Northeast, and Mid-Atlantic. The cap level 
was intended to protect public health and the environment and to 
sustain that protection into the future regardless of growth in the 
affected sector. Ozone season NOX emissions decreased from 
levels in baseline years in all states participating in the NBP. (All 
NBP states transitioned to the CAIR NOX ozone season program 
in 2009 except Rhode Island.) Allowance trading was generally active 
from the start of the program in 2003. Prices and trading were down in 
2008, primarily due to uncertainty. Compliance remained virtually 100 
percent throughout the program's 6 years. Many nonattainment areas in 
the East saw substantial improvements in air quality concentrations 
that brought them in line with ozone NAAQS. The NBP, together with 
other Federal, State, and local programs, contributed to NOX 
reductions that have led to improvements in ozone and PM2.5, 
saving 580-1,800 lives annually in 2008.\11\ Changes in ozone and 
nitrate concentrations due to the NBP have also contributed to 
improvements in ecosystems in the East.
---------------------------------------------------------------------------

    \11\ U.S.EPA. September, 2009. The NOX Budget Trading Program: 
2008 Environmental Results, p.9.
---------------------------------------------------------------------------

    EPA stopped administering the NBP at the conclusion of 2008 control 
period activities. States still have the emissions reductions 
requirement and could use the CAIR NOX ozone season trading 
program to achieve this.
    See section V.D.4.e. for a discussion of the results of the 
NOX Budget Trading Program.
(4) Clean Air Interstate Rule
    Following promulgation of the new NAAQS in 1997, the CAA required 
all states, regardless of whether they have attainment air quality in 
all areas, to submit SIPs containing provisions specified under section 
110(a)(2). In addition, states are required to submit SIPs for 
nonattainment areas which are generally required to include additional 
emissions controls providing for attainment of the NAAQS.
    As described previously, section 110(a)(2)(D)(i)(I) provides a tool 
for addressing the problem of transported pollution that significantly 
contributes to downwind nonattainment and maintenance problems. Under 
section 110(a)(2)(D), a SIP must contain adequate provisions 
prohibiting sources in the state from emitting air pollutants in 
amounts that would contribute significantly to nonattainment or 
interfere with maintenance in one or more downwind states. Section 
110(k)(5) authorizes EPA to find that a SIP is substantially inadequate 
to meet any CAA requirement. If EPA makes such a finding, it is to 
require the state

[[Page 45224]]

to submit, within a specified period, a SIP revision to correct the 
inadequacy (``SIP call''). In 1998, EPA used this authority to issue 
the NOX SIP Call, discussed previously, to require states to 
revise their SIPs to include measures to reduce NOX 
emissions that were significantly contributing to ozone nonattainment 
problems in downwind states.
    Sulfur dioxide and NOX are not the only emissions that 
contribute to interstate transport and PM2.5 nonattainment. 
However, EPA stated in the CAIR that it believed that, given current 
knowledge, it was not appropriate to specify emissions reductions 
requirements for direct PM2.5 emissions or organic 
precursors (e.g., volatile organic compounds (VOCs) or ammonia 
(NH3)). Similarly, for 8-hour ozone, EPA continued to rely 
on the conclusion of the OTAG that analysis of interstate transport 
control opportunities should have focused on NOX, rather 
than VOCs. \12\
---------------------------------------------------------------------------

    \12\ The OTAG was active from 1995-1997 and consisted of 
representatives from the 37 states in that region; the District of 
Columbia; EPA; and interested members of the public, including 
industry and environmental groups. See discussion below under 
NOX SIP Call for further information on OTAG.
---------------------------------------------------------------------------

(5) What is the CAIR?
    The CAA contains a number of requirements to address nonattainment 
of the PM2.5 and the 8-hour ozone NAAQS, including 
requirements that states address interstate transport that 
significantly contributes to such nonattainment. \13\ Based on air 
quality modeling, ambient air quality data analyses, and cost analyses, 
EPA found that emissions in certain upwind states resulted in amounts 
of transported PM2.5, ozone, and their emissions precursors 
that significantly contributed to nonattainment in downwind states.
---------------------------------------------------------------------------

    \13\ The term ``transport'' includes the transport of both 
PM2.5 and their precursor emissions and/or transport of 
both ozone and its precursor emissions.
---------------------------------------------------------------------------

    In the CAIR, promulgated on May 12, 2005 (70 FR 25162), EPA 
required SIP revisions in 28 states and the District of Columbia, 
within 18 months after publication of the notice of final rulemaking, 
to ensure that certain emissions of SO2 and/or 
NOX--important precursors of PM2.5 
(NOX and SO2) and ozone (NOX)--were 
prohibited. Achieving the emissions reductions identified, EPA 
concluded, would address the states' requirements under section 
110(a)(2)(D)(i)(I) of the CAA and would help PM2.5 and ozone 
nonattainment areas in the eastern half of the United States attain the 
standards. Moreover, EPA concluded that such attainment would be 
achieved in a more certain, equitable, and cost-effective manner than 
if each nonattainment area attempted to implement local emissions 
reductions alone, and would also assist the covered states and their 
neighbors in making progress toward their visibility goals.
    The CAIR built on EPA's efforts in the NOX SIP Call to 
address interstate pollution transport for ozone, and was EPA's first 
attempt to address interstate pollution transport for PM2.5. 
It required significant reductions in emissions of SO2 and 
NOX, which contribute to fine particle concentrations. In 
addition, NOX emissions contribute to ozone problems. EGUs 
were found to be a major source of the SO2 and 
NOX emissions which contributed to fine particle 
concentrations and ozone problems downwind.
    CAIR was designed to provide significant air quality attainment, 
health, and environmental improvements across the eastern U.S. in a 
highly cost-effective manner by reducing SO2 and 
NOX emissions from EGUs that contribute to the 
PM2.5 and 8-hour ozone problems described in the rule. 
CAIR's emissions reductions requirements were based on controls that 
EPA had determined to be highly cost-effective for EGUs under optional 
cap and trade programs. However, states had the flexibility to choose 
the measures to adopt to achieve the specified emissions reductions. 
EPA required the emissions reductions to be implemented in two phases, 
with the first phase in 2009 and 2010 (for NOX and 
SO2, respectively), and the second phase for both pollutants 
in 2015. These requirements are described in more detail in section 
V.D.1.
    In addition to promulgating findings of significant contribution to 
nonattainment, EPA assigned emissions reductions requirements for 
SO2 and/or NOX that each of the identified states 
must meet through SIP measures.
    Section V.D.1 discusses the approach taken in CAIR using three 
model multi-state cap and trade programs for SO2 and 
NOX that EPA developed and that states could choose to adopt 
to meet the required emissions reductions in a flexible and cost-
effective way.
    The requirements in the CAIR were intended to address regional 
interstate transport of air pollution. EPA recognized, however, that 
additional local reductions might be necessary to bring some areas into 
attainment even after significantly contributing upwind emissions were 
eliminated. 70 FR 25165-66, May 12, 2005. In addition, states that 
shared an interstate nonattainment area were expected to work together 
in developing the nonattainment SIP for that area, reducing emissions 
that contributed to local-scale interstate transport problems.
    CAIR FIPs. When EPA promulgated the final CAIR in May 2005, EPA 
also issued a national finding that states had failed to submit SIPs to 
address the requirements of CAA section 110(a)(2)(D)(i) with respect to 
the 1997 ozone and PM2.5 NAAQS. States were to have 
submitted 110(a)(2)(D)(i) SIPs for those standards by July 2000. This 
action triggered a 2-year clock for EPA to issue FIPs to address 
interstate transport. On March 15, 2006 the EPA promulgated FIPs to 
ensure that the emissions reductions required by the CAIR are achieved 
on schedule. The FIPs did not limit states'' flexibility in meeting 
their CAIR requirements as all states remained free to submit SIPs at 
any time that, if approved by EPA, would replace the FIP for that 
state.
    As the control strategy for the FIPs, EPA adopted the model cap and 
trade programs that it provided in the CAIR as a control option for 
states, with minor changes to account for federal, rather than state, 
implementation. The FIPs required power plants in affected states to 
participate in one or more of three separate emissions cap and trade 
programs that cover: (1) Annual SO2 emissions, (2) annual 
NOX emissions, and (3) ozone season NOX 
emissions. Emission cap and trade programs are a proven method for 
achieving highly cost-effective emissions reductions while providing 
regulated sources with flexibility in choosing compliance strategies.
    The FIPs also provided states with an option to submit abbreviated 
SIPs to meet CAIR. Under this option, states could save the time and 
resources needed to develop the complete trading program SIP, while 
still being able to make key decisions, such as the methodology for 
allocating annual and/or ozone season NOX allowances.
    New Jersey and Delaware. Separately, on March 15, 2006, EPA issued 
a final rule to include Delaware and New Jersey in the CAIR to control 
SO2 and NOX emissions because they contribute to 
PM2.5 nonattainment in other states. 71 FR 25288, April 28, 
2006. These states were already included in the CAIR because their 
sources contributed to nonattainment of other states' 8-hour ozone air 
quality standard. The CAIR FIP established requirements for Delaware 
and New Jersey with respect to both ambient air quality standards.
    (6) Legal Challenges to the CAIR
    Petitions for review challenging various aspects of the CAIR were 
filed in the U.S. Court of Appeals for the DC Circuit. In North 
Carolina v. EPA, 531

[[Page 45225]]

F.3d 896, modified on reh'g 550 F.3d 1176 (D.C. Cir. 2008), the Court 
granted several of the petitions for review and remanded the rule to 
EPA for further proceedings. In its July 2008 opinion, North Carolina, 
531 F.3d 896, the Court upheld several challenged aspects of EPA's 
approach, but also found fatal flaws in the rule--flaws it found 
significant enough to warrant vacatur of the CAIR and the associated 
FIPs in their entirety. In December 2008, however, the Court responded 
to petitions for rehearing and determined that ``notwithstanding the 
relative flaws of CAIR, allowing the 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. Accordingly, it decided to remand the rule 
without vacatur ``so that EPA may remedy CAIR's flaws in accordance 
with [the Court's] July 11, 2008 opinion in this case.'' Id.
    Although the entire rule was remanded, important parts of EPA's 
rulemaking were upheld by the Court in its July 2008 ruling. The Court 
upheld key aspects of the air quality modeling portion of EPA's 
significant contribution analysis. It upheld EPA's decision to consider 
upwind states for inclusion in the CAIR only if those states 
contributed to projected nonattainment in 2010. See North Carolina, 531 
F.3d at 913-914. The Court further upheld the contribution threshold 
used in the air quality modeling portion of the significant 
contribution analysis for PM2.5, EPA's use of whole states 
as the unit of measurement, and the first-phase NOX 
compliance deadline of 2009 See id. at 914-17, 923-27, 928-29.
    The Court also found significant flaws in EPA's approach. The Court 
emphasized the importance of individual state contributions to downwind 
nonattainment areas and held that EPA had failed to adequately measure 
significant contribution from sources within an individual state to 
downwind nonattainment areas in other states. Id. at 907. Further, the 
Court noted that EPA had not provided adequate assurance that the 
trading programs established in the CAIR would achieve, or even make 
measurable progress towards achieving, the section 110(a)(2)(D)(i)(I) 
mandate to eliminate significant contribution. See North Carolina, 532 
F.3d at 907-08. For these reasons, it concluded that EPA had not shown 
that the CAIR rule would achieve measurable progress towards satisfying 
the statutory mandate of section 110(a)(2)(D)(i)(I) and thus EPA lacked 
authority for its action. See id. at 908. Moreover, it emphasized that 
where the rule constitutes a complete 110(a)(2)(D)(i)(I) remedy, it 
must actually require the elimination of emissions that contribute 
significantly to nonattainment or interfere with maintenance downwind. 
See id.
    The Court further rejected the state budgets for SO2 and 
NOX which were used to implement the CAIR trading programs, 
finding the budgets to be insufficiently related to the 
110(a)(2)(D)(i)(I) mandate of eliminating significant contribution and 
interference with maintenance. See id. at 916-21. It also rejected 
EPA's effort to harmonize the CAIR SO2 trading program with 
the existing requirements of Title IV of the CAA, holding that section 
110(a)(2)(D)(i)(I) did not give EPA authority to terminate or limit 
Title IV allowances. In addition, the Court found that EPA had failed 
to give meaning to the ``interfere with maintenance'' prong of section 
110(a)(2)(D)(i)(I), that EPA had not demonstrated that the 2015 
compliance deadline used in the CAIR was coordinated with the downwind 
state's deadlines for attaining the NAAQS, and that EPA had not 
adequately supported its determination that sources in Minnesota 
significantly contributed to nonattainment or interfered with 
maintenance in downwind states. See id. at 908-11, 911-13, and 926-28.
(7) How the Clean Air Interstate Rule Worked
    Building on the emissions reductions under the NBP and Acid Rain 
Program (ARP), CAIR was designed to permanently lower emissions of 
SO2 and NOX in the eastern United States. As 
explained previously, although the DC Circuit remanded the rule to EPA, 
it did so without vacatur allowing the rule to remain in effect while 
EPA addresses the remand. Thus, CAIR is continuing to help states 
address ozone and PM2.5 nonattainment and improve 
visibility, reducing transported precursors of SO2 and 
NOX, through the implementation of three separate cap and 
trade compliance programs for annual NOX, ozone season 
NOX, and annual SO2 emissions from power plants.
    See section V.D.4.e. for a discussion on CAIR implementation in 
2009, the first year of the NOX annual and ozone season 
programs. The CAIR annual SO2 program began January 1, 2010. 
Quarterly emissions will be posted on EPA's web site (see http://
camddataandmaps.epa.gov/gdm/) and an assessment of emissions reduction 
data will be available at the end of each compliance period.

C. What are the goals of this proposed rule?

    In developing this proposed rule, EPA was guided by a number of 
goals and guiding principles, as discussed in this section of the 
preamble.
1. Primary Goals
a. Respond to the Court Remand of the CAIR
    Most importantly, this proposal responds to the remand of the CAIR 
by the Court. As noted previously, the Court granted several petitions 
for review of the CAIR, finding fatal flaws with the rule; yet, it 
ultimately decided to remand the rule without vacatur to preserve the 
environmental benefits of the rule. North Carolina v. EPA, 531 F.3d 
896, modified on reh'g, 550 F.3d 1176 (DC Cir. 2008).
    The action EPA is proposing would respond to the July and December 
2008 opinions of the DC Circuit and correct the flaws in the CAIR 
methodology that were identified by the Court. The action responds to 
the Court's concerns in numerous ways. The methodology used to measure 
each state's significant contribution emphasizes air quality 
considerations and uses state specific data and information. The 
methodology also gives independent meaning to the interfere with 
maintenance prong of section 110(a)(2)(D)(i)(I). The state budgets for 
SO2, annual NOX and ozone season NOX 
are directly linked to the measurement of each state's significant 
contribution and interference with maintenance. The compliance 
deadlines are coordinated with the attainment deadlines for the 
relevant NAAQS. And the proposed remedy includes assurance provisions 
to assure that all necessary reductions occur in each individual state.
    The action would also propose FIPs which would replace the remanded 
CAIR FIPs. The proposed FIPs would apply to all states covered by the 
rule, including those for which EPA had previously approved SIPs under 
the remanded CAIR. If finalized as proposed, these FIPs would eliminate 
or, at a minimum, make measurable progress towards eliminating 
emissions of SO2 and NOX that significantly 
contribute to or interfere with maintenance of the 1997 and 2006 
PM2.5 NAAQS and the 1997 ozone NAAQS in the eastern half of 
the United States.
b. Address Transport Requirements With Respect to the Existing 
PM2.5 Standards
    This proposed rule is designed to address the requirements of 
section 110(a)(2)(D)(i)(I) of the CAA as they

[[Page 45226]]

relate to the 1997 and 2006 PM2.5 standards for states in 
the eastern United States. The proposed rule would both identify the 
emissions from states in the eastern U.S. that significantly contribute 
to nonattainment and interfere with maintenance of the NAAQS in 
downwind states, and prohibit such emissions.
    States are obligated to submit SIPs to EPA addressing the 
provisions of section 110(a)(2), including the transport provisions of 
section 110(a)(2)(D)(i)(I), within 3 years of the promulgation of a new 
or revised NAAQS. For the 1997 NAAQS, these SIPs were due in 2000. On 
April 25, 2005 (effective May 25, 2005) EPA issued findings that states 
had failed to submit SIPs to satisfy the requirements of section 
110(a)(2)(D)(i) of the Act under the 1997 ozone and PM2.5 
standards. 70 FR 21147, April 25, 2005. These findings started a 2-year 
clock for the promulgation of a FIP by EPA unless, prior to that time, 
each state makes a submission to meet the requirements of 
110(a)(2)(D)(i) and EPA approves the submission. This 2-year period 
expired in May 2007. Because the Court found CAIR inadequate to satisfy 
the requirements of 110(a)(2)(D)(i)(I), neither EPA's FIP implementing 
the requirements of CAIR nor any states SIPs that relied on CAIR to 
satisfy the requirements of this section, are adequate to meet the 
requirements of section 110(a)(2)(D)(i)(I). EPA's obligation to issue a 
FIP has therefore not yet been met. The requirements of the FIPs 
proposed in this rule are designed to address this obligation.
    Revisions to the 1997 PM2.5 standards were signed by the 
Administrator on September 21, 2006, and published in the Federal 
Register on October 17, 2006. 71 FR 61144. The revisions were effective 
December 18, 2006. EPA interprets the 3 year deadline for submission of 
110(a)(2) SIPs to be 3 years from the date of signature. Accordingly, 
for the 2006 revisions to the PM2.5 NAAQS, the SIPs under 
110(a)(2) were due on September 21, 2009. On June 9, 2010, EPA issued a 
notice making findings that states had not submitted SIPs under the 
2006 PM2.5 NAAQS by the September 2009 deadline. 75 FR 
32673. These findings started a 2-year clock for the promulgation of a 
FIP by EPA unless, prior to that time, each state makes a submission to 
meet the requirements of 110(a)(2)(D)(i)(I) and EPA approves the 
submission. This 2-year period will expire on July 9, 2012. This 
proposal is designed to provide FIPs for the 2006 standards to ensure 
that the 110(a)(2)(D)(i)(I) obligation is fully satisfied as it relates 
to those standards. EPA also notes that under FIPs, reduction 
requirements are immediately effective and thus FIPs provide for the 
most expeditious means to implement emissions reduction requirements.
c. Address Transport Requirements With Respect to the 1997 Ozone 
Standards
    This proposed rule, in concert with other actions, largely 
eliminates upwind state emissions that contribute significantly to 
nonattainment in, or interfere with maintenance by, any other state 
with respect to the 1997 8-hour ozone NAAQS. EPA will issue a 
subsequent proposal for the 1997 8-hour ozone NAAQS to address fully 
the requirements of CAA Section 110(a)(2)(D)(i)(I). EPA's goal is to 
fully address transport requirements for the 1997 ozone standards as 
soon as possible.
d. Provide for a Smooth Transition From Existing Programs
    In addressing the Court remand in a way that satisfies the CAA 
transport requirements, EPA is also mindful of the need to ensure a 
smooth transition from the existing requirements. Substantial 
improvements in air quality have resulted from those requirements with 
associated health benefits. It is important not to lose those benefits 
as the new requirements move forward. It is also important to move 
quickly with those portions of the new requirements that provide the 
greatest benefits.
2. Key Guiding Principles
a. Appropriately Identify Necessary Upwind Reductions
    Emissions from upwind states can, alone or in combination with 
local emissions, result in air quality levels that exceed the NAAQS and 
jeopardize the health of residents in downwind communities. Each upwind 
state is required by the ``good neighbor provision'' to eliminate its 
individual significant contribution to downwind state nonattainment and 
to eliminate emissions that interfere with downwind states'' 
maintenance of the air quality standards. The Act does not require 
upwind states to eliminate all emissions that affect downwind air 
quality or shift responsibility for attaining the NAAQS to the upwind 
states. Instead, the ``good neighbor provision'' requires each upwind 
state to, within 3 years of promulgation or revision of a NAAQS, submit 
a SIP to prohibit those emissions that significantly contribute to 
nonattainment or interfere with maintenance downwind. The prohibition 
on these emissions is intended to assist downwind states as they design 
strategies for ensuring that the NAAQS are attained and maintained.
    In practice, it is very complex for individual states to address 
the transport requirements. Generally for transport of ozone, and for 
transport of sulfate and nitrate fine particles, each downwind area is 
affected by emissions from multiple upwind states. In addition, in many 
cases states are simultaneously both upwind and downwind of one 
another. Further, only emissions that will significantly contribute to 
nonattainment or interfere with maintenance in another state are 
prohibited. Thus, an upwind state's obligations are affected by the air 
quality downwind. Downwind air quality, in turn, is affected by both 
local emissions and the cumulative impact of emissions from all of the 
contributing upwind states.
    The problem of interstate transport is thus extremely complex and 
any remedy must acknowledge the inherent complexity of the problem. It 
is appropriate for EPA in developing such a remedy to be mindful of the 
interaction between upwind emissions controls and local emissions 
controls.
    The EPA continues to conclude, as it did in developing the CAIR, 
that it would be difficult if not impossible for many nonattainment 
areas to reach attainment through local measures alone, and EPA finds 
no information developed subsequent to development of CAIR to alter 
this conclusion. At the time of the proposed CAIR rule, EPA conducted a 
local measures analysis representing an ambitious set of measures and 
emissions reductions that may in fact be difficult to achieve in 
practice. (Ref: Section IX of Technical Support Document for the 
Interstate Air Quality Rule Air Quality Modeling Analyses, January 
2004). This analysis was intended to provide illustrative examples of 
the nature of location measures and possible reductions. This analysis 
was not intended to precisely identify local emissions control measures 
that may be available in a particular area. The EPA continues to 
believe that a strategy based on adopting cost effective controls on 
sources of transported pollutants as a first step will produce a more 
reasonable, equitable, and optimal strategy than one beginning with 
local controls. The local measures analyses we conducted were not, 
however, intended to develop a specific or ``optimal'' regional and 
local attainment strategy for any given area. Rather, the analysis was 
intended to evaluate whether, in light of available

[[Page 45227]]

local measures, it is likely to be necessary to reduce significant 
regional transport from upwind states. EPA continues to believe that 
the two local measures analyses that were conducted for the CAIR 
strongly support the need for regional reductions of SO2 and 
NOX.
    In conclusion, EPA believes that the proposed rule represents the 
best approach for identifying upwind state emissions that significantly 
contribute to nonattainment in, or interfere with maintenance by, 
downwind states.
b. Ensuring That Pollution Controls Operate
    The proposed Transport Rule would, by 2012, cap emissions of 
SO2 and NOX on a state-by-state basis and 
guarantee that existing and planned pollution controls operate. EPA is 
convinced that the considerable benefits to air quality and public 
health that have been achieved must be ensured going forward. Keeping 
emissions of SO2 and NOX from increasing by 2012 
in 27 states and DC assures that recent gains are maintained and that 
states that significantly contribute to downwind PM2.5 
nonattainment and maintenance areas do not increase their contribution 
to those areas. Further, this proposal would maintain the ozone season 
emissions reductions achieved since 2005 in 26 states, ensuring that 
states that significantly contribute to downwind ozone nonattainment 
and maintenance areas do not increase their contribution to those 
areas. Tables III.A-2 and III.A-3 in section III.A, previously, show 
the projected EGU emissions for the 2012 phase of the Transport Rule.
c. Provide Workable Approach for EPA and States
    Another important goal in developing the proposed requirements is 
to provide requirements that can, as a practical matter, be implemented 
by both EPA and state air quality agencies. Both EPA and state 
resources are limited and EPA recognizes the importance of developing 
requirements that make efficient use of limited EPA and state 
resources. EPA also notes that the air quality improvements brought 
about by reducing transport can greatly assist states in the 
development of SIPs and attainment demonstrations.
d. Ensure a Reliable Power Supply
    EPA recognizes that requirements for EGUs must be mindful of the 
variability in the operation of the power grid, and that any 
requirements for broad reductions should be structured in a way that 
ensures a reliable power supply.
e. Provide for Cost-Effectiveness
    EPA believes that is important to keep both cost-effectiveness and 
air quality objectives in mind in addressing the CAA transport 
requirements.
f. Provide Incentives and Flexibility to the Regulated Community
    EPA seeks to provide approaches that provide regulated owners/
operators of sources with the incentive to achieve all cost-effective 
reductions. EPA's experience shows that providing this incentive, and 
the flexibility to seek alternatives to less cost-effective controls, 
provides for greater environmental protection at reduced cost.

D. Why does this proposed rule focus on the eastern half of the United 
States?

    For this proposal, we identified a 37 state region for the 
technical analysis, including all states east of the Rockies, from the 
Dakotas through Texas eastward. Western states also need to address the 
requirements of section 110(a)(2)(D)(i)(I) of the CAA. However, the 
transport issues in the eastern United States are analytically distinct 
and this rule focuses only on that subset of the 110(a)(2)(D)(i)(I) 
issues.
    First, interstate transport of PM2.5 and ozone is a 
substantial and critical component for attaining the ozone and 
PM2.5 NAAQS in the eastern United States. The significant 
reductions in ambient air pollutant concentrations since CAIR, due 
largely to the large reductions in transported emissions, only serve to 
reinforce this point.
    Second, in developing the CAIR, EPA found that interstate transport 
(particularly for anthropogenic emissions) made much smaller 
contributions to exceedances of the 1997 PM2.5 standards in 
the western United States. At the time, the only exceedances of the 15 
[mu]g/m\3\ in those states were in parts of California, and in Lincoln 
County (Libby), Montana. The Montana location has subsequently come 
into attainment.
    Technical information developed for EPA's recently completed 
nonattainment designations suggests that interstate emissions transport 
makes a relatively small contribution to exceedances in the western 
United States under the 2006 PM2.5 standards. For these 
designations, EPA identified several locations in the western U.S. with 
exceedances of the 24-hour PM2.5 standards. These locations 
were in California and a few other western states: Alaska, Washington, 
Oregon, Utah, and Arizona. Technical support information describing the 
nature of the 24-hour PM2.5 problem at each of these 
locations is available at: http://www.epa.gov/pmdesignations/
2006standards/tech.htm. A review of this information suggests to EPA 
that the Western nonattainment problems are relatively local in nature 
with limited interstate transport. EPA requests comment on this 
assessment.

E. Anticipated Rules Affecting Power Sector

    On January 12, 2010, the EPA Administrator outlined seven 
priorities for the Agency. One of them is to improve air quality. In 
her description of this priority she said, ``EPA will develop a 
comprehensive strategy for a cleaner and more efficient power sector, 
with strong but achievable reduction goals for SO2, 
NOX, mercury, and other air toxics.'' In furtherance of this 
priority goal, and to respond to statutory and judicial mandates, EPA 
is undertaking a series of regulatory actions over the course of the 
next 2 years that will affect the power sector in particular.
    The rules under the CAA will substantially reduce the emissions of 
SO2, NOX, mercury, and other air toxics. To the 
extent that the Agency has the legal authority to do so while 
fulfilling its obligations under the Act and other relevant statutes, 
the Agency will also coordinate these utility-related air pollution 
rules with upcoming regulations for the power sector from EPA's Office 
of Water (OW) and its Office of Resource Conservation and Recovery 
(ORCR). EPA expects that this comprehensive set of requirements will 
yield substantial health and environmental benefits for the public, 
benefits that can be achieved while maintaining a reliable and 
affordable supply of electric power across the economy. In developing 
and promulgating these rules, the Agency will be providing the power 
industry with a much clearer picture of what EPA will require of it in 
the next decade. In addition to promulgating the rules themselves, the 
Agency will engage with other federal, state and local authorities, as 
well as with stakeholders and the public at large, with the goal of 
fostering investments in compliance that represent the most efficient 
and forward-looking expenditure of investor, shareholder, and public 
funds, resulting, in turn, in the creation of a clean, efficient, and 
completely modern power sector.
    The major CAA rules that will drive these compliance investments 
are: (1) This transport rule; (2) potential future rules that may be 
needed to address transport under future revised ozone or fine particle 
health standards; (3) the

[[Page 45228]]

CAA Section 112(d) standards; (4) revisions to the NSPS for coal and 
oil-fired electric utility steam generating units; and (5) BART 
requirements and other requirements that address visibility and 
regional haze. Within the planning and investment horizon for 
compliance with these rules, the EPA very likely will be compelled to 
respond a pending petition to set standards for the emissions of 
greenhouse gases from steam electric generating units under the NSPS 
program. Furthermore, as set forth in the recently promulgated 
reinterpretation of the Johnson Memo, beginning in 2011 new and 
modified sources of GHG emissions, including EGUs, will be subject to 
permits under the Prevention of Significant Deterioration program 
requiring them to adopt BACT for their GHGs. Finally, EPA will also 
pursue with other federal agencies, states, and other groups energy 
efficiency improvements in the use of electricity throughout the 
economy that will contribute to additional environmental and public 
health improvements that the Agency wants to provide while lowering the 
costs of realizing those improvements.
    A brief explanation of these major CAA rulemakings and activities 
follows.
    Transport Rule. This proposed transport rule includes emissions 
reductions requirements for EGUs to address interstate transport under 
the 1997 ozone NAAQS, the 1997 PM2.5 NAAQS, and the 2006 
PM2.5 NAAQS. After considering public comments on this 
proposal, EPA will endeavor to issue a final rule in spring 2011.
    Rules to Address Transport under Revised Air Quality Health 
Standards. EPA currently is reconsidering its 2008 national ambient air 
quality standards for ozone, and is conducting a periodic review of the 
particulate matter NAAQS, including the fine particle standards. The 
Act requires EPA to ensure that primary standards are requisite to 
protect public health with an adequate margin of safety, and to set 
secondary standards requisite to protect public welfare. The Act 
requires EPA to review, and revise if appropriate, the primary and 
secondary NAAQS on a 5-year schedule to ensure that air quality 
standards reflect the latest scientific information on health and 
welfare effects. When air quality standards are set or revised, the Act 
requires revision of SIPs to ensure that these standards to protect 
public health and welfare are met expeditiously and, in the case of the 
health-based standards, within timetables in the Act.
    If more protective NAAQS are promulgated, further emissions 
reductions would likely be needed in states where pollution levels 
exceed air quality standards, and in upwind states with emissions that 
significantly contribute to the air quality problems in another state. 
This may result in additional emission reduction requirements for 
facilities in the power sector, as well as for other sectors. The 
reconsideration of the March 2008 ozone air quality standards will be 
completed soon, and the review of particulate matter air quality 
standards by October 2011. SIP deadlines and attainment deadlines would 
flow from those dates.
    EPA plans to make expeditious determinations of upwind state 
emissions reduction responsibilities for NAAQS for which interstate 
transport is an issue. This approach will lead to earlier emissions 
reductions to protect public health, as well as provide other benefits. 
In the North Carolina decision, the court made clear that downwind 
state nonattainment deadlines are legally relevant to the timing of 
reductions under section 110(a)(2)(D). Thus, expeditious determinations 
of upwind state responsibilities under section 110(a)(2)(D) can promote 
upwind reductions in time to help downwind states meet attainment 
deadlines, enable states and EPA to provide sources with earlier 
information on their emission reduction responsibilities, and maximize 
sources lead time to reduce emissions.
    If a more protective ozone NAAQS is issued in August, EPA would 
plan to propose an interstate pollution transport rule for that NAAQS 
in 2011. We would expect work on that proposal to proceed in parallel 
with efforts to finalize this Transport Rule for the 1997 and 2006 
NAAQS. A final rule to address interstate pollution transport for a 
reconsidered ozone NAAQS would be anticipated in 2012. In view of the 
implementation schedule for a reconsidered ozone NAAQS, compliance 
dates would be later than the compliance dates proposed for this 
Transport Rule, and would take into account attainment dates for that 
NAAQS and other factors such, as control cost and installation time. 
For any revised PM2.5 NAAQS, EPA plans to conduct a 
similarly expeditious analysis of interstate transport to support a 
determination as to whether or not further emissions reductions from 
the power sector are required under section 110(a)(2)(D), in light of 
the emissions reductions required by other power sector rules.
    A revised SO2 NAAQS was issued on June 2 creating a new 
1-hour SO2 NAAQS which, when implemented, will protect 
Americans from asthma and respiratory difficulties associated with 
short term exposures to SO2. Although EPA does not expect 
peak SO2 levels to be a long-range transport issue, power 
plants are among the sources that can contribute to peak SO2 
levels and will likely be evaluated by states as they consider control 
measures to attain the new standards. Anticipated emissions reductions 
from power plants and other SO2 sources under other Clean 
Air Act (CAA or Act) requirements (e.g., transport rules, and MACT 
standards) are expected to play a significant role in attainment of the 
1-hour SO2 NAAQS.
    Section 112(d) Standards for Utility Units. In 2008, the DC Circuit 
Court vacated the CAMR and the 112(n) Revision Rule, which removed 
coal- and oil-fired electric utility steam generating units from the 
section 112(c) list of sources subject to regulation. EPA is in the 
early stages of developing regulations under section 112 of the CAA 
that will require existing and new coal- and oil-fired utility units to 
meet emissions limits for mercury and other HAPs emitted from these 
sources. As required by section 112, EPA will issue a set of emissions 
standards. In part, the section 112(d) rule will require that all 
existing major sources achieve the emission limits for HAPs which will 
be at least as stringent as the average emissions reduction currently 
achieved by the best performing 12 percent of these units. 
Additionally, any new major source will be required to meet emission 
limits that are at least as stringent as what is currently achieved by 
the best-performing single source. Currently, the Agency is seeking 
data on five categories of HAP emissions: (1) Acid gases (e.g., 
hydrochloric acid, hydrogen fluoride, and hydrogen cyanide); (2) 
mercury; (3) Non-Hg metals (e.g., lead, cadmium, selenium, and 
arsenic); (4) dioxins/furans; and, (5) other organic hazardous air 
pollutants. EPA expects to receive the requested data, including stack 
testing results, by September 2010. EPA has agreed to sign the proposed 
rule by March 16, 2011, and sign the final rule no later than November 
16, 2011. EPA may provide existing sources up to 3 years to comply with 
section 112(d) standards, and the CAA authorizes the permit authority 
to grant a 1 year extension of the compliance date on a case-by-case 
basis if such extension is necessary for the installation of controls. 
The CAA requires new sources to comply on the effective date of the 
final rule or at startup, whichever is later. If EPA were to provide 3 
years for compliance with the section 112(d) standards,

[[Page 45229]]

compliance would generally be required by early 2015.
    In developing these rules, EPA will endeavor to proceed in a way 
that provides all stakeholders and other Federal, State and local 
decision-makers with ongoing, up-to-date information about the full 
suite of environmental responsibilities that the power sector must 
undertake. This, in turn, will enable power companies and others whose 
policies and decisions affect their investment choice to adopt 
compliance strategies that take full advantage of co-control 
opportunities and efficiencies and other approaches to maximizing the 
cost-effectiveness and leveraging benefits of their investments.
    New Source Performance Standards. NSPS are administered under 
section 111 of the CAA. The standards for new, modified, and 
reconstructed steam EGUs are contained in 40 CFR part 60 subpart Da, 
which was last amended in 2006. The current structure of subpart Da 
sets output-based (i.e., lbs of emission/MWh) emission limits for 
NOX and SO2 and optional output-based standards 
for particulate matter. EPA is currently re-evaluating the standards in 
Subpart Da to determine whether they reflect the degree of emission 
limitation achievable through the application of the best system of 
emission reduction, which the Administrator determines has been 
adequately demonstrated. EPA also has a pending voluntary remand to 
decide whether NSPS standards for this source category should include 
limits on GHG emissions. EPA is considering the timetable for these 
actions and decisions in light of legal obligations and policy 
considerations, including the desirability of the industry knowing its 
regulatory obligations to inform investment decisions.
    Regional Haze/BART. States are required to develop SIPs that 
address regional haze in scenic areas such as national parks and 
wilderness areas. EPA regulations for regional haze appear in Chapter 
40 of the CFR in sections 51.308 and 51.309. One of the requirements of 
the regional haze SIPs is to provide for BART for large industrial 
sources including EGUs. The BART provisions affect EGUs put into 
operation between 1962 and 1977.
    Energy Efficiency. Policies that will promote efficient use of 
electric power can be an integral, highly cost-effective component of 
power companies'' compliance strategies. Reducing demand for 
electricity can in itself achieve large emissions reductions and public 
health benefits, while enhancing the reliability of the grid. It can 
also lower the cost of emissions reductions for consumers of 
electricity and for the power industry, as investments are avoided in 
unnecessary infrastructure.
    EPA does not have sole responsibility for the development of energy 
policy to promote efficiency. To facilitate this component of the power 
sector's compliance strategy, EPA intends to engage with other federal, 
state, and local agencies whose policies and actions can make it easier 
for power companies to adopt, or benefit from, energy efficiency 
investments in their compliance strategies. EPA will continue to use 
its authorities to advance energy efficiency by providing incentives 
for energy efficiency in our regulatory programs (e.g., output-based 
standards) and through our successful existing voluntary programs such 
as ENERGY STAR. The Department of Energy (DOE) also has considerable 
resources to encourage efficient use of electricity. Additional 
resources have been made available under the American Recovery and 
Reinvestment Act to both DOE and EPA to promote energy efficiency. 
State governments, both in their environmental programs and through 
their public service commissions, which regulate electric utility 
rates, can promote energy efficiency. Many state governments have been 
leaders in promoting efficient use of electricity through such 
mechanisms as energy efficiency standards and demand response, and EPA 
and DOE are assisting state governments in this effort. Local 
governments as well, through building codes, zoning, and other actions, 
can and do promote end-use energy efficiency. The Federal Energy 
Regulatory Commission (FERC) regulates wholesale electricity markets 
and sets mandatory reliability standards to assure a safe reliable 
power system. In carrying out this mission FERC recognizes that energy 
efficiency is a resource, to be considered along with other energy 
resources in reliability and economic planning.
    All of these entities will need to work in concert to achieve a 
truly efficient, reliable, cost-effective electric power system. EPA is 
committed to meeting this challenge.
    Non-Air Office Regulations. EPA is also working on three additional 
rules that will have potential impacts on the power sector. The Office 
of Solid Waste and Emergency Response is developing revised regulations 
for coal combustion residues, which are the combustion byproducts 
associated with the use of coal as a fuel. The Administrator signed the 
proposed rule on May 4, 2010. Over the next few years, EPA's Office of 
Water plans to develop two rules affecting electric generating units; 
the precise timing of these rules is being determined. One will 
regulate cooling water intake structures. The other will revise the 
effluent guidelines for wastewater discharges from power plants. Each 
of these rules has cost implications to the power sector, and the 
Agency intends to coordinate these regulations with the upcoming air 
regulations. We intend to maximize reductions in pollution while 
maintaining cost-effective solutions.
    As a first step to carrying out its commitment to promote and 
facilitate the most cost-effective and forward-looking compliance 
investments and strategies on the part of the power sector, EPA will 
conduct extensive outreach concerning the full range of the upcoming 
environmental responsibilities of the sector as it proposes the 
Transport Rule. Upon this proposal, the Agency will begin an outreach 
effort with the public, the regulated community, state air regulators, 
and others to (1) describe the Transport Rule proposal, and (2) provide 
information on the 2011 section 112 standards for utility units and 
other upcoming EPA rulemakings affecting the power sector. The intent 
will be to inform all stakeholders of the industry's obligations and 
opportunities for the industry to use investments in SO2 and 
NOX reductions to help smooth transition to compliance with 
the Section 112(d) standards applicable to utility units.
    At the same time EPA also intends to expand its outreach to 
others--who can play a significant role in promoting or requiring 
investment in energy efficiency. EPA intends to continue these efforts 
over time as more information becomes available in the development of 
the various rulemakings under development for the power sector.

IV. Defining ``Significant Contribution'' and ``Interference With 
Maintenance''

    This section describes EPA's proposed approach to define emissions 
that significantly contribute to nonattainment or interfere with 
maintenance of the PM2.5 and ozone NAAQS downwind. The 
section begins by providing background on how ``significant 
contribution'' and ``interference with maintenance'' were defined in 
the past by EPA for the NOX SIP Call and the CAIR, 
describing past Court opinions on EPA's approach, and presenting an 
overview of EPA's proposed Transport Rule approach (section IV.A). 
Next, section IV.B describes the proposed approach to identify upwind 
contributing states. Section IV.C details the air quality modeling 
approach and results used for

[[Page 45230]]

this proposed rule. Section IV.D provides a detailed description of 
EPA's proposed approach to quantify emissions that significantly 
contribute and interfere with maintenance. Section IV.E includes 
proposed state emissions budgets before accounting for the inherent 
variability in power system operations. Section IV.F discusses the 
inherent variability in power system operations, proposes variability 
limits on the state budgets, and presents projected emissions reduction 
results. Section IV.G describes how the proposed approach is consistent 
with judicial opinions. Finally, section IV.H lists alternative 
approaches to defining significant contribution and interference with 
maintenance that EPA evaluated but is not proposing.

A. Background

1. Approach Used in NOX SIP Call and the CAIR
a. Significant Contribution
    Two rules EPA promulgated that address interstate transport of 
pollutants are the NOX SIP Call (63 FR 57356; October 27, 
1998) and the CAIR (70 FR 25162; May 12, 2005), which are described in 
section III.B. In both of these rules, EPA used a 2-step approach to 
quantify significant contribution. The approaches used in both rules 
were similar.
    In the first step, EPA applied an air quality threshold to 
determine a set of upwind states whose potential for significant 
contribution should be evaluated further. That is, EPA compared the 
contributions that individual upwind states make to downwind receptors 
and identified states whose contributions were greater than the 
specified threshold amount. EPA referred to these states as significant 
contributors but did not rely on this first step to quantify or measure 
the states' significant contribution.
    In the second step, EPA determined the quantity of emissions that 
the states collectively could remove using highly cost-effective 
controls. EPA defined this quantity of emissions as the ``significant 
contribution.'' The approach used in each rule is described in more 
detail, later.
    NOX SIP Call. EPA addressed the section 110(a)(2)(D)(i)(I) 
requirement to prohibit emissions that significantly contribute to 
downwind nonattainment in the NOX SIP Call. To do so, EPA 
developed a methodology for identifying emissions that constitute 
upwind states' ``significant contribution.'' EPA determined that 
emissions ``contribute'' to nonattainment downwind if they have an 
impact on nonattainment downwind (62 FR 60325). EPA established several 
criteria or factors for the ``significant contribution'' test (and 
further indicated that the same criteria should apply to the 
``interfere with maintenance'' provision).\14\
---------------------------------------------------------------------------

    \14\ In the NOX SIP Call, because the same criteria 
applied, the discussion of the ``contribute significantly to 
nonattainment'' test generally also applied to the ``interfere with 
maintenance'' test. However, in the NOX SIP Call, EPA 
stated that the ``interfere with maintenance'' test applied with 
respect to only the 8-hour ozone NAAQS (63 FR 57379-80).
---------------------------------------------------------------------------

    EPA determined the amount of emissions that significantly 
contribute to downwind nonattainment from sources in a particular 
upwind state by: (i) Evaluating, with respect to each upwind state, 
several air quality related factors, including determining that all 
emissions from the state have a sufficiently great impact downwind (in 
the context of the collective contribution nature of the ozone 
problem); and (ii) determining the amount of that state's emissions 
that can be eliminated through the application of cost-effective 
controls (63 FR 57403).
    Air Quality Factor. The first factor that EPA used to determine the 
amount of emissions that significantly contribute to downwind 
nonattainment was the air quality factor, consisting of an evaluation 
of the impact on downwind air quality of the upwind state's emissions.
    EPA specifically considered three air quality factors with respect 
to each upwind state:
     The overall nature of the ozone problem (i.e., 
``collective contribution'');
     The extent of the downwind nonattainment problems to which 
the upwind state's emissions are linked, including the ambient impact 
of controls required under the CAA or otherwise implemented in the 
downwind areas; and
     The ambient impact of the emissions from the upwind 
state's sources on the downwind nonattainment problems (63 FR 57376).
    EPA explained the first factor, collective contribution, by noting,

    [V]irtually every nonattainment problem is caused by numerous 
sources over a wide geographic area * * * [. This] factor suggest[s] 
that the solution to the problem is the implementation over a wide 
area of controls on many sources, each of which may have a small or 
immeasurable ambient impact by itself (63 FR 57377).

    The second air quality factor is the extent of downwind 
nonattainment problems. EPA considered the then-current air quality of 
the area, the predicted future air quality (assuming implementation of 
required controls but not the transport requirements that were the 
subject of the NOX SIP Call), and, when air quality 
designations had already been made, the boundaries of the area in light 
of designation status (63 FR 57377).\15\
---------------------------------------------------------------------------

    \15\ EPA explained in the NOX SIP Call, ``It should 
be reiterated that EPA relied on the designated area solely as a 
proxy to determine which areas have air quality in nonattainment. 
This proxy is readily available under the 1-hour NAAQS because areas 
have long been designated nonattainment. The EPA's reliance on 
designated nonattainment areas for purposes of the 1-hour NAAQS does 
not indicate that the reference in section 110(a)(2)(D)(i)(I) to 
``nonattainment'' should be interpreted to refer to areas designated 
nonattainment.'' (63 FR 57375, footnote 25)
---------------------------------------------------------------------------

    EPA applied the third air quality factor by projecting the amount 
of the upwind state's entire inventory of anthropogenic emissions to 
the year 2007, and then quantifying the impact of those emissions on 
downwind nonattainment through the appropriate air quality modeling 
techniques.\16\ Specifically, (i) EPA determined the minimum threshold 
impact that the upwind state's emissions must have on a downwind 
nonattainment area to be considered potentially to contribute 
significantly to nonattainment; and then (ii) for states with impacts 
above that threshold, EPA developed a set of metrics for further 
evaluating the contribution of the upwind state's emissions on a 
downwind nonattainment area (63 FR 57378). EPA referred to states with 
emissions that had a sufficiently great impact as significant 
contributors; however, the precise amount of their significant 
contribution was not calculated until the next step. Because the ozone 
problem is caused by many relatively small contributions, even 
relatively small contributors must participate in the solution. For 
this reason, EPA determined that even a relatively small contribution 
can be significant contribution given the nature of the problem, and 
established relatively low thresholds.
---------------------------------------------------------------------------

    \16\ Although EPA's air quality modeling techniques examined all 
of the upwind state's emissions of ozone precursors (including VOC 
and NOX), only the NOX emissions had 
meaningful interstate impacts.
---------------------------------------------------------------------------

    Cost Factor. The cost factor is the second major factor that EPA 
applied to determine the significant contribution to nonattainment: 
``EPA* * * determined whether any amounts of the NOX 
emissions may be eliminated through controls that, on a cost-per-ton 
basis, may be considered to be highly cost effective'' (63 FR 57377). 
Applying this cost factor on top of the air quality factor, EPA 
determined that emissions that both were from states that exceeded

[[Page 45231]]

the air quality thresholds and could be eliminated through the 
application of highly cost-effective controls constituted a given 
state's significant contribution.
    Choice of Highly Cost-Effective Standard. EPA chose the standard of 
``highly cost-effective'' in order to assure state flexibility in 
selecting control strategies to meet the emissions reduction 
requirements of the rulemaking. That is, the rulemaking required the 
states to achieve specified levels of emissions reductions--the levels 
achievable if states implemented the control strategies that EPA 
identified as highly cost-effective--but the rulemaking did not mandate 
those highly cost-effective control strategies, or any other control 
strategy. Indeed, in calculating the amount of the required emissions 
reductions by assuming the implementation of highly cost-effective 
control strategies, EPA assured that other control strategies--ones 
that were cost-effective, if not highly cost-effective--remained 
available to the states.
    Determination of Highly Cost-Effective Amount. EPA determined the 
dollar amount considered to be highly cost-effective by reference to 
the cost-effectiveness of recently promulgated or proposed 
NOX controls. EPA determined that the average cost-
effectiveness of controls ranged up to approximately $1,800 per ton of 
NOX removed (1990$) on an annual basis. The EPA considered 
the controls in the reference list to be cost-effective.
    EPA established $2,000 per ton (1990$) in average cost-
effectiveness for summer ozone season emissions reductions as, at least 
directionally, the highly cost-effective amount. Identifying this 
amount on an ozone season basis was appropriate because the 
NOX SIP Call concerned the ozone standard, for which 
emissions reductions during only the summer ozone season are necessary. 
In determining the highly cost-effective amount, EPA analyzed costs on 
a regionwide basis, and assumed a cap and trade program for EGUs and 
large non-EGU boilers and turbines.
    Source Categories. EPA then determined that the source categories 
for which highly cost-effective controls were available included EGUs, 
large industrial boilers and turbines, and cement kilns. At the same 
time, EPA determined, for those source categories, the level of 
emissions reductions in each state that would result from the 
application of all controls that would be highly cost-effective and 
that would be feasible. The EPA considered other source categories, but 
found that highly cost-effective controls were not available for 
various reasons, including the size of the sources, the relatively 
small amount of emissions from the sources, or the control costs.
    Other Factors. EPA also relied on several other, secondary 
considerations to identify the required amount of emissions reductions. 
The first concerned the consistency of regional reductions with 
downwind attainment needs. The second general consideration was ``the 
overall fairness of the control regimes'' to which the downwind and 
upwind areas were subject. The third general consideration was 
``general cost considerations.'' The EPA noted that ``in general, areas 
that currently have, or that in the past have had, nonattainment 
problems * * * have already incurred ozone control costs.'' The next 
set of controls available to these nonattainment areas would be more 
expensive than the controls available to the upwind areas. The EPA 
found that this cost scenario further confirmed the reasonableness of 
the upwind control obligations (63 FR 57379).
    In the NOX SIP Call, EPA considered all of these factors 
together in determining the level of controls considered to be highly 
cost-effective. Within the region, the nonattainment areas already had 
implemented required VOC and NOX controls that covered much 
of their inventory. However, the upwind states in the region generally 
had not implemented such controls (except as needed to address their 
ozone nonattainment areas). In this context, EPA considered it 
reasonable to impose an additional control burden on the upwind states. 
Air quality modeling showed that residual nonattainment remained even 
with this additional level of upwind controls so that further 
reductions from downwind and/or upwind areas would be necessary.
    After ascertaining the controls that qualified as highly cost-
effective, EPA developed a methodology for calculating the amount of 
NOX emissions that each state was required to reduce on 
grounds that those emissions contribute significantly to nonattainment 
downwind. The total amount of required NOX emissions 
reductions was the sum of the amounts that would be reduced by 
application of highly cost-effective controls to each of the source 
categories for which EPA determined that such controls were available 
(63 FR 57378).
    Electric Generating Units. The largest of the source categories 
discussed previously was EGUs. EPA determined the amount of reductions 
associated with EGU controls by applying the control rate that EPA 
considered to reflect highly cost-effective controls to each state's 
EGU heat input (adjusted for projected growth) (70 FR 25173.) In the 
NOX SIP Call, EPA evaluated the costs of control on a 
region-wide basis.
    CAIR. In the CAIR, EPA again addressed the section 
110(a)(2)(D)(i)(I) requirement to prohibit emissions that significantly 
contribute to downwind nonattainment (70 FR 25162). While the 
NOX SIP Call had addressed significant contribution with 
respect to the 1997 ozone NAAQS, the CAIR addressed significant 
contribution with respect to both the ozone and annual PM2.5 
NAAQS promulgated in 1997. In the CAIR, EPA used a methodology to 
identify states'' significant contribution based on and very similar to 
the methodology used in the NOX SIP Call.
    To quantify the amounts of emissions that contribute significantly 
to nonattainment, EPA explained in the CAIR that the Agency primarily 
focused on the air quality factor reflecting the upwind state's ambient 
impact on downwind nonattainment areas, and the cost factor of highly 
cost-effective controls. See 70 FR 25174.
    Air Quality Factor--PM2.5. EPA employed air quality modeling 
techniques to assess the impact of each upwind state's entire inventory 
of anthropogenic SO2 and NOX emissions on 
downwind nonattainment and maintenance for the annual PM2.5 
NAAQS.\17\ EPA determined that upwind NOX and SO2 
emissions contribute significantly to annual PM2.5 
nonattainment as of the year 2010.
---------------------------------------------------------------------------

    \17\ EPA did not address 24-hour PM2.5 NAAQS in CAIR, 
only the annual PM2.5 NAAQS.
---------------------------------------------------------------------------

    As in the NOX SIP Call, EPA used a 2-step approach to 
quantify significant contribution. In the CAIR, in the first step EPA 
adopted a threshold air quality impact of 0.2 [mu]g/m3 for 
PM2.5. An upwind state with contributions to downwind 
nonattainment below this level would not be subject to regulatory 
requirements, but a state with contributions at or higher than this 
level would be subject to further evaluation (70 FR 25174-75).
    This level reflects the fact that PM2.5 nonattainment, 
like ozone, is caused by many sources in a broad region and therefore 
may be solved only by controlling sources throughout the region. As 
with the NOX SIP Call, the collective contribution condition 
of PM2.5 air quality is reflected in the relatively low 
threshold (70 FR 25175).
    Air Quality Factor--8-Hour Ozone. EPA employed air quality modeling 
techniques to assess the impact of each upwind state's inventory of 
NOX and VOC emissions on downwind nonattainment. The EPA 
determined

[[Page 45232]]

that upwind NOX emissions contribute significantly to 8-hour 
ozone nonattainment as of the year 2010. Therefore, EPA projected 
NOX emissions to the year 2010, assuming certain required 
controls (but not controls required under the CAIR), and then modeled 
the impact of those projected emissions on downwind 8-hour ozone 
nonattainment in that year (70 FR 25175).
    EPA used the same threshold amounts and metrics for 8-hour ozone 
that it used in the NOX SIP Call. That is, emissions from an 
upwind state were found to contribute significantly to nonattainment if 
the maximum contribution was at least 2 parts per billion, the average 
contribution greater than one percent, and certain other numerical 
criteria were met. EPA also evaluated frequency, magnitude, and 
relative amounts of contribution to determine which linkages were 
significant before costs were considered.
    Cost Factor. The second step in the 2-step process is to apply the 
cost factor. As in the NOX SIP Call, EPA interpreted this 
factor as mandating emissions reductions in amounts that would result 
from application of highly cost-effective controls. In the CAIR, EPA 
determined the level of costs that would be highly cost-effective on a 
regional basis by reference to the cost effectiveness of other recent 
controls. EPA concluded that EGUs were the only source category for 
which highly cost-effective SO2 and NOX controls 
were available at the time. EPA determined as highly cost-effective the 
dollar amount of cost-effectiveness that falls near the low end of a 
reference range of control costs. See 70 FR 25175. In the CAIR, as in 
the NOX SIP Call, EPA analyzed the costs of control on a 
regionwide basis.
    Other Factors. As with the NOX SIP Call, EPA considered 
other factors that influence the application of the air quality and 
cost factors, and that confirm the conclusions concerning the amounts 
of emissions that upwind states must eliminate as contributing 
significantly to downwind nonattainment. See 70 FR 25175.
b. Interference With Maintenance
    Section 110(a)(2)(D)(i)(I) requires that SIPs for national primary 
and secondary air quality standards contain adequate provisions 
prohibiting emissions in amounts that ``interfere with maintenance by 
any other state'' of any such standard.
    In the NOX SIP Call and in the CAIR, EPA gave the term 
``interfere with maintenance'' a meaning much the same as the meaning 
given to the term ``significant contribution.'' That approach, which 
was found inconsistent with the requirements of 110(a)(2)(D)(i)(I), is 
described later. EPA's proposed new approach to interpreting 
``interfere with maintenance'' is described in section IV.D, later.
    NOX SIP Call: In the NOX SIP Call, EPA explained its 
approach as follows (63 FR 57379-80):

    After an area has reached attainment of the 8-hour NAAQS, that 
area is obligated to maintain that NAAQS. (See sections 110(a)(1) 
and 175A.) Emissions from sources in an upwind area may interfere 
with that maintenance. The EPA proposes to apply much the same 
approach in analyzing the first component of the ``interfere-with-
maintenance'' issue, which is identifying the downwind areas whose 
maintenance of the NAAQS may suffer interference due to upwind 
emissions. The EPA has analyzed the ``interfere-with-maintenance'' 
issue for the 8-hour NAAQS by examining areas whose current air 
quality is monitored as attaining the 8-hour NAAQS [or which have no 
current air quality monitoring], but for which air quality modeling 
shows nonattainment in the year 2007. This result is projected to 
occur, notwithstanding the imposition of certain controls required 
under the CAA, because of projected increases in emissions due to 
growth in emissions generating activity. Under these circumstances, 
emissions from upwind areas may interfere with the downwind area's 
ability to attain. Ascertaining the impact on the downwind area's 
air quality of the upwind area's emissions aids in determining 
whether the upwind emissions interfere with maintenance (62 FR 
60326).
    In today's action, EPA is taking the same positions with respect 
to the interfere-with-maintenance test as described in the notice of 
proposed rulemaking.

    In addition, the NOX SIP Call preamble stated:

    This [interfere-with-maintenance] requirement * * * does not, by 
its terms, incorporate the qualifier of ``significantly.'' Even so, 
EPA believes that for present purposes, the term ``interfere'' 
should be interpreted much the same as the term ``contribute 
significantly,'' that is, through the same weight-of-evidence 
approach.

    CAIR: In the CAIR, EPA also interpreted ``interfere with 
maintenance'' in a limited way. EPA only considered whether upwind 
state emissions eventually posed a maintenance problem for areas that 
EPA projected to be in nonattainment in 2010 (the year that was the 
focus of the analysis of significant contribution to nonattainment). 
EPA did not examine whether areas in attainment in 2010 might face a 
maintenance problem either in 2010 or thereafter, so no upwind state 
controls were considered to assist such areas with maintaining clean 
air. The CAIR preamble stated (70 FR 25193, footnote 45), ``we believe 
the `interfere with maintenance' prong may come into play only in 
circumstances where EPA or the state can reasonably determine or 
project, based on available data, that an [nonattainment] area in a 
downwind state will achieve attainment, but due to emissions growth or 
other relevant factors is likely to fall back into nonattainment.'' 
\18\
---------------------------------------------------------------------------

    \18\ The CAIR final preamble stated: ``EPA has evaluated the 
attainment status of the downwind receptors in 2010 and 2015, and 
has determined that each upwind state's 2010 and 2015 emissions 
reductions are necessary to the extent required by the rule because 
a downwind receptor linked to that upwind state will either (i) 
remain in nonattainment and continue to experience significant 
contribution to nonattainment from the upwind state's emissions; or 
(ii) attain the relevant NAAQS but later revert to nonattainment 
due, for example, to continued growth of the emissions inventory.''
---------------------------------------------------------------------------

    In responding to comments on the CAIR proposal, we also used this 
interpretation of the maintenance provision to help support the need 
for Phase II CAIR reductions. For ozone, we conducted an analysis that 
looked at (1) the amount by which receptor locations were projected to 
attain in 2015 and (2) the year-to-year variability in ozone levels due 
to weather and other factors based on a review of historical monitoring 
data. This analysis concluded that areas within 3-5 ppb of the 
standard, and sometimes greater (e.g., Fulton County, Atlanta) had 
historic variability as great as 8 ppb, and that this variability 
suggests strongly that upwind states could be interfering with 
maintenance even if modeling shows attainment by up to these amounts. 
For PM2.5, while we lacked historical data to support the 
same variability analysis, we characterized attaining the annual 
standard by 0.5 [mu]g/m3 as ``attaining by a narrow margin'' thus 
giving rise to maintenance concerns, and noted that in past (mobile 
source) rules we had indicated that attainment by a margin of 10 
percent or less could be considered to raise maintenance concerns.
2. Judicial Opinions
a. Significant Contribution
    In North Carolina v. EPA, 531 F.3d. 896 (DC Cir. 2008), the Court 
held that the approach EPA used in CAIR to measure each state's 
significant contribution was insufficient. EPA, the Court concluded, 
had failed to ``measure[ ] the significant contribution from sources 
within an individual state to downwind nonattainment areas.'' Id. at 
907. The Court further reasoned that the lack of a state-specific 
significant contribution analysis made it impossible for EPA to show 
that the

[[Page 45233]]

trading programs and state budgets established to implement the trading 
programs, effectuated the section 110(a)(2)(D)(i)(I) statutory mandate 
to eliminate emissions within the state that significantly contribute 
to nonattainment or interfere with maintenance in other states.
    Specifically, the court rejected the regional scope of EPA's 
analysis. It reasoned that ``because EPA evaluated whether its proposed 
emissions were `highly cost effective' at the regionwide level assuming 
a trading program, it never measured the `significant contribution' 
from sources within an individual state to downwind nonattainment 
areas.'' Id. at 907. In reaching this conclusion, however, the Court 
also recognized that aspects of EPA's methodology for analyzing 
significant contribution had been upheld in Michigan v. EPA, 213 F.3d 
663 (DC Cir. 2000), and it left those holdings undisturbed. 
Specifically, the Court acknowledged its prior conclusion that 
``significance may include cost'' North Carolina, 531 F.3d at 919 
(citing Michigan 213 F.3d 677-79), and thus it is acceptable for EPA to 
use cost to ``draw the `significant contribution' line''. Id. The Court 
also recognized that Michigan approved EPA's decision to apply a 
uniform emissions control requirement to all upwind states despite 
different levels of contribution. See North Carolina, 531 F.3d at 908. 
The Court thus concluded that while EPA must ``measure each state's 
`significant contribution' to downwind nonattainment'' that measurement 
need not ``directly correlate with each state's individualized air 
quality impact on downwind nonattainment relative to other upwind 
states.'' Id. at 908.
    In North Carolina, the Court also upheld several aspects of the air 
quality modeling EPA used in the significant contribution analysis. It 
upheld EPA's use of whole state modeling, see id. at 923-26, and 
deferred to EPA's selection of the PM2.5 contribution 
threshold, see id. at 914-15. With regard to EPA's application of the 
methodology to individual states, the Court found that EPA had failed 
to respond to comments by Minnesota Power alleging errors in the 
application of this methodology to determine Minnesota's contribution 
to downwind PM2.5 nonattainment areas. See id. at 926-28.
b. Interference With Maintenance
    In the CAIR case, the Court also rejected EPA's approach to the 
second prong of section 110(a)(2)(D)(i)(I), holding that EPA's failure 
to give independent meaning to the term ``interfere with maintenance'' 
was inconsistent with the statutory mandate. See North Carolina, 531 
F.3d at 910. The Court rejected the approach used in CAIR reasoning 
that it ``provides no protection for downwind areas that, despite EPA's 
predictions, still find themselves struggling to meet NAAQS due to 
upwind interference in 2010.'' Id. at 910-11.
3. Overview of Proposed Approach
    In this section, EPA will explain how it proposes to identify which 
states are significantly contributing to downwind non-attainment and/or 
interfering with maintenance of the NAAQS at downwind sites and to 
quantify what that contribution is.
    In this action, EPA is proposing to use a two step approach to 
measuring each state's significant contribution. The methodology used 
is based on the approach used in CAIR and the NOX SIP Call 
but modified to address the concerns raised by the Court. In the first 
step of this proposed approach, EPA uses air quality modeling to 
quantify individual states' contributions to downwind nonattainment and 
maintenance sites in 2012. States whose contributions to any downwind 
sites are greater than 1 percent of the relevant NAAQS are considered 
``linked'' to those sites for the purpose of the second step in the 
analysis. In the second step, EPA identifies the portion of each 
state's contribution that constitutes its ``significant contribution'' 
and ``interference with maintenance.'' To do so, EPA uses maximum cost 
thresholds, informed by air quality considerations. Specifically, for 
each precursor pollutant (i.e., SO2 and NOX for 
PM2.5 and NOX for ozone) emitted by the upwind 
states that EPA has identified as linked to NAAQS nonattainment and 
maintenance sites downwind, EPA identifies, through this process, the 
reductions available from EGUs in each individual upwind state at the 
appropriate maximum cost threshold. These emissions reductions are the 
amount of the upwind state's significant contribution. The cost 
thresholds used in this portion of the analysis, in contrast to the 
thresholds used in CAIR and the NOX SIP Call, are informed 
by air quality considerations, in addition to a comparison of the cost 
of control in other regulatory contexts. Specific cost thresholds were 
developed for annual SO2, annual NOX, and ozone-
season NOX. Where appropriate, EPA developed higher and 
lower cost thresholds, based on the downwind air quality impact of 
emissions from different groups of states. Although EPA in the past has 
applied a uniform remedy to all states found to have a significant 
contribution, in this proposal EPA divides, for individual pollutants, 
the significantly contributing states into two groups: Those whose 
significant contribution can be eliminated at a lower cost threshold; 
and those whose significant contribution is not eliminated (to the 
extent that it has been identified in this proposal) until they reach 
the higher cost threshold. The lower cost threshold applies to a state 
if the reduction in emissions at that threshold eliminates 
nonattainment and maintenance problems at all ``linked'' sites.
    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. Both components of 
maintenance are addressed in this proposal.

Step One: Air Quality Analysis

    In step one of this proposed approach, EPA analyzes emissions from 
37 states to quantify the impact of those emissions on downwind 
nonattainment and maintenance sites in 2012 (see section IV.C for a 
detailed discussion of air quality modeling). To begin this analysis, 
EPA first identifies all monitors projected to be in nonattainment or, 
based on historic variability in air quality, projected to have 
maintenance problems in 2012. This baseline analysis takes into account 
emissions reductions associated with the implementation of all federal 
rules promulgated by December 2008 and assumes that the CAIR is not in 
effect. This baseline presents a unique situation. EPA has been 
directed to replace the CAIR; yet the CAIR remains in place and has led 
to significant emissions reductions in many states.
    A key step in the process of developing a 110(a)(2)(D)(i)(I) rule 
involves analyzing existing (base case) emissions to determine which 
states significantly contribute to downwind nonattainment and 
maintenance areas. EPA cannot prejudge at this stage which states will 
be affected by the rule. For example, a state affected by CAIR may not 
be affected by the new rule and after the new rule goes into effect, 
the CAIR requirements will no longer apply. For a state covered by CAIR 
but not covered by the new rule, the CAIR requirements would not be 
replaced with new requirements, and therefore an increase in emissions 
relative to present levels could occur in that state. More 
fundamentally, the court has made clear that, due to legal flaws, the 
CAIR rule cannot remain in place and must be replaced. If EPA's base 
case analysis

[[Page 45234]]

were to ignore this fact and assume that reductions from CAIR would 
continue indefinitely, areas that are in attainment solely due to 
controls required by CAIR would again face nonattainment problems 
because the existing protection from upwind pollution would not be 
replaced. For these reasons, EPA cannot assume in its base case 
analysis, that the reductions required by CAIR will continue to be 
achieved.
    Following this logic, the 2012 base case shows emissions higher 
than current levels in some states. Because EPA has been directed to 
replace CAIR, EPA believes that for many states, the absence of the 
CAIR NOX program will lead to the status quo of the 
NOX Budget Program, which limits ozone-season NOX 
emissions and ensures the operation of NOX controls in those 
states. Also, without the CAIR SO2 program, emission 
requirements in many areas would revert to the comparatively less 
stringent requirements of the Title IV Acid Rain Program. As a result, 
SO2 emissions in many states would increase markedly in the 
2012 base case relative to the present. Efforts to comply with ARP 
rules at the least-cost would occur in many cases without the operation 
of existing scrubbers through use of readily available, inexpensive 
Title IV allowances. Notably, all known controls that are required 
under state laws, NSPS, consent decrees, and other enforceable binding 
commitments through 2014 are accounted for in the base case. It is 
against this backdrop that the Transport Rule is analyzed and that 
significant contribution to nonattainment and interference with 
maintenance must be addressed.

Step Two: Quantifying Each State's Significant Contribution

    In step two, EPA identifies the portion of each state's 
contributing emissions that constitute the emissions from that state 
that ``significantly contribute to, or interfere with maintenance by'' 
another state. To do so with respect to the 1997 ozone NAAQS, EPA 
analyzes the costs and associated air quality impacts of reductions in 
ozone-season NOX. To do so with respect to the 1997 and 2006 
PM2.5 NAAQS, EPA analyzes the costs and associated air 
quality impacts of reductions in annual SO2 and annual 
NOX. The analysis uses cost thresholds, informed by air 
quality considerations and applied on a state specific basis. EPA 
considered a number of factors, including air quality and cost factors 
because the circumstances that lead to nonattainment and maintenance 
problems at downwind sites are extremely complex. By using both cost 
and air quality factors, EPA's analysis can address the different 
circumstances influencing the linkages between upwind and downwind 
states. As such, EPA believes it is appropriate to consider these 
factors in identifying the emissions that must be prohibited.
    While we believe it is important to consider cost, we also 
recognize that we can't ``just pick a cost for the region and deem 
`significant' any emissions that sources can eliminate more cheaply.'' 
North Carolina, 531 F.3d at 918. In contrast to the approach used in 
CAIR and the NOX SIP Call, the cost thresholds EPA uses in 
this proposed approach are informed by air quality considerations and 
applied on a state specific basis. EPA first develops state-specific 
costs curves showing what level of emissions reductions could be 
achieved at different cost levels in 2012 and 2014. EPA then uses a 
simplified air quality assessment tool to examine the impact of the 
reductions at specific cost levels on downwind nonattainment and 
maintenance sites. This approach allows EPA to identify specific cost 
breakpoints based on air quality considerations (such as the cost at 
which the air quality assessment analysis projects large numbers of 
downwind sites maintenance and nonattainment problems would be 
resolved) or cost criteria (such as being a cost where large emissions 
reductions occur because a particular technology is widely implemented 
at that cost). EPA then evaluated the reasonableness of the cost 
breakpoints using a number of criteria to determine which of the 
breakpoints appropriately represented a cost threshold with which to 
define significant contribution.
    These thresholds are then applied on a state-specific basis to 
quantify each individual state's significant contribution.
    The remainder of this section provides further detail on the 
specific methodology developed by EPA and the application of this 
methodology to identify emissions that significantly contribute to or 
interfere with maintenance of the 1997 ozone NAAQS and the 1997 and 
2006 PM2.5 NAAQS.

B. Overview of Approach To Identify Contributing Upwind States

    This section describes EPA's proposal to require reductions in 
upwind emissions of SO2 and NOX to address 
PM2.5 transport and to require reductions in upwind 
emissions of NOX to address ozone-related transport. In 
addition, this section provides an overview of EPA's approach to 
identifying which states are subject to the proposed rule, and which 
states are not subject to the rule because their sources' emissions 
were found to not significantly contribute to nonattainment of the 
PM2.5 or 8-hour ozone standards or interfere with 
maintenance of those standards, in downwind states.
    The EPA assessed individual upwind states'' 2012 projected ambient 
impacts on downwind nonattainment and maintenance receptors for a 37-
state region in the eastern U.S., and established threshold values for 
PM2.5 and ozone to identify those states whose impact does 
not constitute a significant contribution to air quality violations in 
the downwind states. EPA used these same threshold values in 
considering the potential for upwind state emissions to interfere with 
maintenance of the PM2.5 and 8-hour ozone NAAQS in downwind 
areas. The EPA used air quality modeling of emissions in each state to 
estimate the ambient impacts. The air quality modeling platform and 
approach to quantifying interstate contributions to PM2.5 
and ozone are discussed in section IV.C.
    As noted previously, 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 is 
discussed in section IV.C., and directly affects the proposed 
requirements of this rule. EPA also considered whether further 
reductions were necessary to ensure continued lack of interference with 
maintenance of the NAAQS over time. EPA concluded that in light of 
projected emission trends, and also considering the emissions 
reductions from this proposed rule, no further reductions are required 
solely for this purpose at PM and ozone receptors for which we are 
partially or fully determining significant contribution for the current 
NAAQS. (See discussion of emissions trends in Chapter 7 of TSD entitled 
``Emission Inventories,'' included in the docket for this proposal.)
1. Background
a. For the CAIR, how did EPA determine which pollutants were necessary 
to control to address interstate transport for PM2.5?
    Section II of the January 2004 CAIR proposal summarized key 
scientific and technical aspects of the occurrence, formation, and 
origins of PM2.5, as well as findings and observations 
relevant to formulating control approaches for reducing the 
contribution of transport to

[[Page 45235]]

fine particle problems (69 FR 4575-87). Key concepts and provisional 
conclusions drawn from this discussion were summarized as follows in 
the preamble to the final CAIR:
    (1) Fine particles (measured as PM2.5 for the NAAQS) 
consist of a diverse mixture of substances that vary in size, chemical 
composition, and source. The PM2.5 includes both ``primary'' 
particles that are emitted directly to the atmosphere as particles, and 
``secondary'' particles that form in the atmosphere through chemical 
reactions from gaseous precursors. The major components of fine 
particles in the eastern U.S. can be grouped as follows: Carbonaceous 
material (including both primary and secondary organic carbon and black 
carbon); sulfates; nitrates; ammonium; and crustal material, which 
includes suspended dust as well as some other directly emitted 
materials. The major gaseous precursors of PM2.5 include 
SO2, NOX, NH3, and certain volatile 
organic compounds.
    (2) Examination of urban and rural monitors indicate that in the 
eastern U.S., sulfates, carbonaceous material, nitrates, and ammonium 
associated with sulfates and nitrates are typically the largest 
components of transported PM2.5, while crustal material 
tends to be only a small fraction.
    (3) Atmospheric interactions among particulate ammonium sulfates 
and nitrates and gas phase nitric acid and ammonia vary with 
temperature, humidity, and location. Both ambient observations and 
modeling simulations suggest that regional SO2 reductions 
are effective at reducing sulfate and associated ammonium, and, 
therefore, PM2.5. Under certain conditions reductions in 
particulate ammonium sulfates can release ammonia as a gas, which then 
reacts with gaseous nitric acid to form nitrate particles, a phenomenon 
called ``nitrate replacement.'' In such conditions SO2 
reductions would be less effective in reducing PM2.5, unless 
accompanied by reductions in NOX emissions to address the 
potential increase in nitrates.
    (4) Reductions in ammonia can reduce the ammonium, but not the 
sulfate portion of sulfate particles. The relative efficacy of reducing 
nitrates through NOX or ammonia control varies with 
atmospheric conditions; the highest particulate nitrate concentrations 
in the East tend to occur in cooler months and regions. At present, our 
knowledge about sources, emissions, control approaches, and costs is 
greater for NOX than for ammonia. Measures to reduce 
NOX from stationary and mobile sources have been implemented 
for more than 20 years. From a chemical perspective, as NOX 
reductions accumulate relative to ammonia, the atmospheric chemical 
system would move towards an equilibrium in which ammonium nitrate 
reductions become more responsive to further NOX reductions 
relative to ammonia reductions.
    (5) Much less is known about the sources of regional transport of 
carbonaceous material. Key uncertainties include how much of this 
material is due to biogenic as compared to anthropogenic sources, and 
how much is directly emitted as compared to formed in the atmosphere.
    Based on the understanding of current scientific and technical 
information, as well as EPA's air quality modeling, as summarized in 
the CAIR proposal, EPA concluded that it was both appropriate and 
necessary to focus on control of SO2 and NOX 
emissions as the most effective approach to reducing the contribution 
of interstate transport to PM2.5.
    For the CAIR, the EPA did not include emissions controls that 
affect 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). For 
all of these components, the lack of knowledge of and ability to 
quantify accurately the interstate transport of these components 
limited EPA's ability to include these components in the CAIR.
b. For the CAIR, how did EPA determine which pollutants were necessary 
to control to address interstate transport for ozone?
    In the notice of proposed rulemaking for the CAIR, EPA provided the 
following characterization of the origin and distribution of 8-hour 
ozone air quality problems:
    The ozone present at ground level as a principal component of 
photochemical smog is formed in sunlit conditions through atmospheric 
reactions of two main classes of precursor compound: VOCs and 
NOX (mainly NO and NO2). The term ``VOC'' 
includes many classes of compounds that possess a wide range of 
chemical properties and atmospheric lifetimes, which help determine 
their relative importance in forming ozone. Sources of VOCs include 
man-made sources such as motor vehicles, chemical plants, refineries, 
and many consumer products, but also natural emissions from vegetation. 
Nitrogen oxides contributing to ozone formation are emitted by motor 
vehicles, power plants, and other combustion sources, with lesser 
amounts from natural processes including lightning and soils. Key 
aspects of current and projected inventories for NOX and VOC 
are summarized in section IV of the proposal notice and EPA Web sites 
(e.g., http://www.gov/ttn/chief.) The relative importance of 
NOX and VOC in ozone formation and control varies with 
local- and time-specific factors, including the relative amounts of VOC 
and NOX present. In rural areas with high concentrations of 
VOC from biogenic sources, ozone formation and control is governed by 
NOX. In some urban core situations, NOX 
concentrations can be high enough relative to VOC to suppress ozone 
formation locally, but still contribute to increased ozone downwind 
from the city. In such situations, VOC reductions are most effective at 
reducing ozone within the urban environment and immediately downwind. 
The formation of ozone increases with temperature and sunlight, which 
is one reason ozone levels are higher during the summer. Increased 
temperature 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, 
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 would be most effective, whereas VOC reductions are most 
effective in more dense urbanized areas.
    Studies conducted in the 1970s established that ozone occurs on a 
regional scale (i.e., 1,000s 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.
    In the notice of proposed rulemaking for CAIR, EPA noted that we 
continue to rely on the assessment of ozone

[[Page 45236]]

transport made in great depth by the OTAG in the mid-1990s. As 
indicated in the NOX SIP Call proposal, the OTAG Regional 
and Urban Scale Modeling and Air Quality Analysis Work Groups concluded 
that regional NOX emissions reductions are effective in 
producing ozone benefits; the more NOX reduced, the greater 
the benefit.
    More recent assessments of ozone, for example those conducted for 
the Regulatory Impact Analysis for the ozone standards in 2008, 
continue to show the importance of NOX transport. 
Information on these analyses can be found at EPA's Web site at: http:/
/www.epa.gov/ttn/ecas/regdata/RIAs/452_R_08_003.pdf.
    For addressing interstate ozone transport in the CAIR, EPA 
addressed NOX emissions, 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. The EPA expects that states will need to examine 
the extent to which VOC emissions affect ozone pollution levels across 
state lines, and identify areas where multi-state VOC strategies might 
assist in meeting the 8-hour standard, in planning for attainment.
c. For the CAIR, which thresholds were used to identify states included 
under the rule?
(1) Fine Particles
    In the CAIR, EPA used as the metric for identifying a state as 
significantly contributing (depending upon further consideration of 
costs) to downwind nonattainment, the predicted change, due to the 
upwind state's NOX and SO2 emissions, in 
annual\19\ PM2.5 concentration in the downwind nonattainment 
area that receives the largest ambient impact. The EPA proposed this 
metric in the form of a range of alternatives for a ``bright line,'' 
that is, air quality impacts at or greater than the chosen threshold 
level indicated that the upwind state's emissions do contribute 
significantly (depending on cost considerations), and that air quality 
impacts below the threshold indicate that the upwind state's emissions 
do not contribute significantly to nonattainment.
---------------------------------------------------------------------------

    \19\ For the CAIR, 24-hour PM2.5 was not at issue 
because there were little or no exceedances of the then-existing 65 
[mu]g/m\3\ 24-hour standards
---------------------------------------------------------------------------

    This metric addresses how much each state contributes to a downwind 
neighbor. EPA does not believe that a particular upwind state must 
contribute to multiple downwind receptors to be required to make 
emissions reductions under CAA section 110(a)(2)(D). Under this 
provision, an upwind state must include in the SIP adequate provisions 
that prohibit that state's emissions that ``contribute significantly to 
nonattainment in * * * any other State * * *'' 42 U.S.C. 
7410(a)(2)(D)(i)(I). Our interpretation of this provision is that the 
emphasized terms make clear that the upwind state's emissions must be 
controlled as long as they contribute significantly to a single 
nonattainment area.
    As discussed in section II of the preamble to the final CAIR, EPA's 
approach to evaluating a state's impact on downwind nonattainment 
considered the entirety of the state's SO2 and 
NOX emissions, rather than treating them separately. We 
believed this approach was consistent with the chemical interactions in 
the atmosphere of SO2 and NOX in forming 
PM2.5. The contributions of SO2 and 
NOX emissions are generally not additive, but rather are 
interrelated due to complex chemical reactions.
    In the CAIR proposal, EPA proposed to establish a state-level 
annual average PM2.5 contribution threshold from 
anthropogenic SO2 and NOX emissions that was a 
small percentage of the annual air quality standard of 15.0 [mu]g/m\3\. 
The EPA based this proposal on the general concept that an upwind 
state's contribution of a relatively low level of ambient impact should 
be regarded as significant (depending on the further assessment of the 
control costs). We based our reasoning on several factors. The EPA's 
modeling indicates that at least some nonattainment areas will find it 
difficult to attain the standards without reductions in upwind 
emissions. In addition, our analysis of base case PM2.5 
transport shows that, in general, PM2.5 nonattainment 
problems result from the combined impact of relatively small 
contributions from many upwind states, along with contributions from 
in-state sources and, in some cases, substantially larger contributions 
from a subset of particular upwind states. In the NOX SIP 
Call rulemaking, we termed this pattern of contribution--which is also 
present for ozone nonattainment--``collective contribution.''
    In the case of PM2.5, we have found collective 
contribution to be a pronounced feature of the PM2.5 
transport problem, in part because the annual nature of the 
PM2.5 NAAQS means that throughout the entire year and across 
a range of wind patterns--rather than during just one season of the 
year or on only the few worst days during the year which may share a 
prevailing wind direction--emissions from many upwind states affect the 
downwind nonattainment area.
    As a result, to address the transport affecting a given 
nonattainment or maintenance area, many upwind states must reduce their 
emissions, even though their individual contributions may be relatively 
small. As a result, for the CAIR EPA determined that a relatively low 
value for the PM2.5 transport contribution threshold was 
appropriate. For the final CAIR EPA decided to apply a threshold of 
0.20 [mu]g/m\3\, such that any model result that is below this value 
(0.19 or less) indicates a lack of significant contribution, while 
values of 0.20 or higher exceeded the threshold.
(2) Ozone
    For the CAIR ozone program, in assessing the contribution of upwind 
states to downwind 8-hour ozone nonattainment, EPA followed the 
approach used in the NOX SIP Call and employed the same 
contribution metrics, but with an updated model and updated inputs.
    The air quality modeling approach we proposed to quantify the 
impact of upwind emissions included two different methodologies: Zero-
out and source apportionment. EPA applied each methodology to estimate 
the impact of all of the upwind state's anthropogenic NOX 
and VOC emissions on each downwind nonattainment area.
    The EPA's first step in evaluating the results of these 
methodologies was to remove from consideration those states whose 
upwind contributions were very low. Specifically, EPA considered an 
upwind state not to contribute significantly to a downwind 
nonattainment area if the state's maximum contribution to the area was 
either (1) less than 2 ppb; or (2) less than one percent of total 
nonattainment in the downwind area; as indicated by either of the two 
modeling techniques.
    If the upwind state's impact exceeded these thresholds, then EPA 
conducted a further evaluation to determine if the impact was high 
enough to meet the air quality portion of the ``contribute 
significantly'' standard. In doing so, EPA organized the outputs of the 
two modeling techniques into a set of ``metrics.'' The metrics reflect 
three key contribution factors:
     The magnitude of the contribution (actual amount of ozone 
contributed by emissions in the upwind state to nonattainment in the 
downwind area);
     The frequency of the contribution (how often contributions 
above certain thresholds occur); and
     The relative amount of the contribution ( the total ozone

[[Page 45237]]

contributed by the upwind state compared to the total amount of 
nonattainment ozone in the downwind area).
2. Approach for Proposed Rule
a. Which pollutants do we propose to control?
    For the proposed rule, EPA believes that the conclusions and 
findings in the final CAIR regarding the nature of pollutant 
contributions are still appropriate. EPA proposes to continue to focus 
the PM2.5 transport requirements on SO2 and 
NOX transport, and the ozone transport requirements on 
NOX.
    EPA recognizes that, in some circumstances, the state's 
NOX contribution to PM2.5 in downwind states may 
be considerably smaller than the state's SO2 contribution to 
PM2.5 in downwind states. In addition, for monitors in EPA's 
speciation trends network that are located in southern states with 
warmer climates, the level of monitored nitrates can be very small. For 
these states, it is possible that annual NOX controls, 
within levels that could realistically be achieved, would result in a 
very small change in ambient PM2.5 levels. EPA considered 
identifying states where this was the case. For a number of reasons, we 
propose not to take this course of action. First, these states can 
impact downwind states in cooler climates, and thus impact nitrate 
formation in those downwind states. For example, EPA modeling results 
show that Georgia's emissions are linked to Ohio, Maryland, New Jersey, 
and Pennsylvania where monitored nitrates are higher. Second, EPA is 
concerned with the possibility for the ``nitrate replacement'' effect 
described previously. That is, there is a possibility for increases in 
nitrate particles if SO2 emissions decrease without 
accompanying decreases in NOX. Third, EPA believes that 
there would be important disbenefits to relaxing annual NOX 
requirements in those states. If for those states, EPA were to relax 
the annual NOX requirements currently required for their 
contribution to PM2.5, annual NOX emissions would 
increase, with potentially harmful effects on visibility and nitrogen 
deposition.
b. Thresholds
    For the proposed rule, as for CAIR, EPA uses air quality thresholds 
to identify states whose contributions do not warrant transport 
requirements. We propose air quality thresholds for annual 
PM2.5, 24-hour PM2.5, and 8-hour ozone. Each 
threshold is based on 1 percent of the NAAQS.
    As we found at the time of the 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. For ozone, as 
we found in the CAIR and the SIP call, we also found important 
contributions from multiple upwind states. In short, EPA continues to 
find an upwind ``collective contribution'' that is important to both 
PM2.5 and ozone.
    A second reason that low threshold values are warranted, as EPA 
discussed in the notices for the CAIR, is that there are adverse health 
impacts associated with ambient PM2.5 and ozone even at low 
levels. See relevant portions of the CAIR proposal notice (63 FR 4583-
84) and the CAIR final rule notice (70 FR 25189-25192).
    For annual PM2.5 for the final CAIR, as noted 
previously, EPA decided to use a single-digit value, 0.2 [mu]g/m\3\, 
rather than the two-digit value in the proposed CAIR, 0.15 [mu]g/m\3\. 
The rationale for the single digit value for the final rule was that a 
single digit is consistent with the EPA monitoring requirements in part 
50, appendix N, section 4.3. The reporting requirements for annual 
PM2.5 require that:

    Annual PM2.5 standard design values shall be rounded 
to the nearest 0.1 [mu]g/m\3\ (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\.
    For the 24-hour standard of 35 [mu]g/m\3\, we attempted to apply 
the same rationale for determining a single-digit air quality 
threshold. That is, we applied rounding conventions in Part 50, 
Appendix N to a value representing one percent of the NAAQS. The 
rounding requirements for the 24-hour standard are indicated in section 
4.3 as follows:

    24-hour PM2.5 standard design values 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).

    One percent of the 24-hour standard is 0.35 [mu]g/m\3\, and 
rounding to the nearest whole [mu]g/m\3\ would yield an air quality 
threshold of zero. Thus applying the same rationale for the final CAIR, 
there would be no air quality threshold for 24-hour PM2.5, 
which EPA believes to be counterintuitive and unworkable as an approach 
for assessing interstate contributions.
    For the proposed rule, EPA proposes to decouple the precision of 
the air quality thresholds with the monitoring reporting requirements, 
and to use 2-digit values representing one percent of the 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 approach is readily 
applicable to any current and future NAAQS. 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 0.1 [mu]g/m\3\. This would occur because any 
value less than 0.15 [mu]g/m\3\ (e.g., 0.14 [mu]g/m\3\) would be 
rounded down to 0.1 [mu]g/m\3\. EPA finds it within its discretion to 
adjust its approach to account for the additional considerations that 
were not in existence at the time of the final CAIR.
    For the proposal, EPA is proposing to take a more straightforward 
approach to air quality thresholds for ozone than the multi-factor 
approach we used for the NOX SIP Call or for the CAIR. The 
proposed approach uses a single ``bright line'' threshold for ozone 
that is one percent of the 1997 8-hour ozone standard of 0.08 ppm. As 
described later in section IV.C, the 1 percent threshold is averaged 
over multiple model days. EPA believes this to be a robust metric 
compared to previous metrics which might have relied on the maximum 
contribution on a single day. Under this approach, one percent of the 
NAAQS is a value of 0.8 ppb. State contributions of 0.8 ppb and higher 
are above the threshold; ozone contributions less than 0.8 ppb are 
below the threshold. EPA believes that this approach is preferable 
because it is a robust metric, it is consistent with the approach for 
PM2.5, and because it provides for a consistent approach 
that takes into account, and is applicable to, any future ozone 
standards below 0.08 ppm.
    EPA seeks comment on the pollutants and air quality thresholds used 
for identifying states to be included under the proposed rule. In 
particular, EPA requests comment on alternatives to the 1 percent 
threshold. In addition, EPA requests comment on whether EPA should use 
the same rounding

[[Page 45238]]

convention that was used in the final CAIR for the 15 [mu]g/m\3\ annual 
PM2.5 standard, or whether commenters agree with EPA's 
approach that does not use this rounding convention. To identify the 
potential effect of alternative thresholds for the annual 
PM2.5 standard, see Table IV.C-13 (showing state specific 
contributions to areas with annual PM2.5 nonattainment and 
maintenance issues) and Table IV.C-16 (showing state specific 
contributions to areas with 24-hour PM2.5 nonattainment and 
maintenance issues).

C. Air Quality Modeling Approach and Results

1. What air quality modeling platform did EPA use?
a. Introduction
    In this section, we describe the air quality modeling performed to 
support the proposed rule. We used air quality modeling to (1) identify 
locations where we expect there to be nonattainment or maintenance 
problems for annual average PM2.5, 24-hour PM2.5, 
and/or 8-hour ozone for the analytic years chosen for this proposal, 
(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, (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, and (4) assess the health 
and welfare benefits of the emissions reductions expected to result 
from this proposal. This section includes information on the air 
quality model applied in support of the proposed rule, the 
meteorological and emissions inputs to these models, the evaluation of 
the air quality model compared to measured concentrations, and the 
procedures for projecting ozone and PM2.5 concentrations for 
future year scenarios. We also provide in this section the interstate 
contributions for annual average and 24-hour PM2.5, and 8-
hour ozone. The Air Quality Modeling Technical Support Document 
(AQMTSD) contains more detailed information on the air quality modeling 
aspects of this rule.
    To support the proposal, air quality modeling was performed for 
four emissions 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 emissions reductions expected from the proposed FIPs. The 
remedy proposed for inclusion in the FIPs is described in section V.D. 
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 2014 base case and 2014 control case modeling were used to quantify 
the benefits of this proposal.
    For CAIR, EPA used the Comprehensive Air Quality Model with 
Extensions (CAMx) version 5 \20\ to simulate ozone and PM2.5 
concentrations for the 2005 base year and the 2012 and 2014 future year 
scenarios. In contrast, for the CAIR EPA used two air quality models, 
CAMx version 3.1 for modeling ozone and the Community Multiscale Air 
Quality Model (CMAQ) version 4.3 for modeling PM2.5. Both 
CAMx and CMAQ are grid cell-based, multi-pollutant photochemical models 
that simulate the formation and fate of ozone and fine particles in the 
atmosphere. The use of one model for both pollutants, as we have done 
for this proposal, provides a more scientifically integrated ``one 
atmosphere'' approach versus using different models for ozone and 
PM2.5. In addition, using a single model rather than two 
models is computationally more efficient. 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.\21\ The modeling region (i.e., 
modeling domain) extends from Texas northward to North Dakota and 
eastward to the East Coast and includes 37 states and the District of 
Columbia. A map of the air quality modeling domain is provided in the 
AQMTSD.
---------------------------------------------------------------------------

    \20\ Comprehensive Air Quality Model with Extensions Version 5 
User's Guide. Environ International Corporation. Novato, CA. March 
2009.
    \21\ 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.
---------------------------------------------------------------------------

    Both CAMx and CMAQ contain certain 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 CAMx model was chosen for use in this 
proposal because the source apportionment tools in this model have had 
extensive use and evaluation by states and industry. Also, the source 
apportionment tools in CAMx received favorable comments in a recent 
peer review.\22\
---------------------------------------------------------------------------

    \22\ Arunachalam, S. Peer Review of Source Apportionment Tools 
in CAMx and CMAQ, EP-D-07-102. University of North Carolina, 
Institute for the Environment, August 2009.
---------------------------------------------------------------------------

    The 2005-based air quality modeling platform used for the proposal 
includes 2005 base year emissions and 2005 meteorology for modeling 
ozone and PM2.5 with CAMx. This platform provides an update 
to the now more historical data in the 2001-based platform used for 
CAIR that included 2001 emissions, 2001 meteorology for modeling 
PM2.5, and 1995 meteorology for modeling ozone. In the 
remainder of this section we provide an overview of (1) the emissions 
and meteorological components of the 2005-based platform, (2) the 
methods for projecting future nonattainment and maintenance along with 
a list of 2012 base case nonattainment and maintenance locations, (3) 
the approach to developing metrics to measure interstate contributions 
to annual and 24-hour PM2.5 and ozone, and (4) the predicted 
interstate contributions to downwind nonattainment and maintenance. We 
also identify which predicted interstate contributions are at or above 
the air quality impact thresholds described previously in section IV.B.
b. Emissions Inventories
    Emissions estimates were made for a 2005 base year and for 2012 and 
2014. All inventories include emissions from EGUs, nonEGU point 
sources, stationary nonpoint sources, onroad mobile sources, and 
nonroad mobile sources. When emissions were only available at annual or 
monthly temporal resolutions, emissions modeling steps were applied to 
estimate hourly emissions. Point source emissions were assigned to 
modeling grid cells based on latitude and longitude in the inventory, 
and county total emissions were allocated to grid cells. Emissions of 
NOX, VOCs and PM2.5 were split into their 
component species using other data sources, to provide the modeling 
species needed by CAMx. Elevated point sources were identified for 
simulating releases of emissions from those sources in layers 2 and 
higher in CAMx. In addition to the anthropogenic emission sources 
described previously, hourly, gridded biogenic emissions were estimated 
for individual modeling days using the BEIS model version 
3.14.23 24 The same

[[Page 45239]]

biogenic emissions data were used in all scenarios modeled.
---------------------------------------------------------------------------

    \23\ Pouliot, G., Pierce., T. ``A Tale of Two Models: A 
comparison of the Biogenic Emission Inventory System (BEIS) and 
Model of Emissions of Gases and Aerosols from Nature (MEGAN),'' 7th 
Annual Community Multiscale Analysis System Conference, Chapel Hill, 
NC, October 6-8, 2008.
    \24\ Donna Schwede, D., Pouliot, G., and Pierce, T. ``Changes to 
the Biogenic Emissions Inventory System Version 3 (BEIS3),'' 4th 
Annual Community Multiscale Analysis System Conference, Chapel Hill, 
NC, September 26-28, 2005.
---------------------------------------------------------------------------

(1) Development of 2005 Base Year Emissions
    Emissions inventory inputs representing the year 2005 were 
developed to provide a base year for forecasting future air quality, 
described in section IV.C.2. The 2005 National Emission Inventory 
(NEI), version 2 from October 6, 2008, was the starting point for the 
U.S. inventories used for 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. In 
addition, a 2006 Canadian inventory and a 1999 Mexican inventory were 
used for the portions of Canada and Mexico within the modeling domains. 
Additional details on these inventories and the augmentation described 
here are available from the Emissions Inventory Technical Support 
Document (EITSD) for the Transport Rule.
    The onroad and nonroad emissions were primarily based on the 
National Mobile Inventory Model (NMIM) monthly, county, process level 
emissions from the 2005 NEI v2. The 2005 onroad mobile emissions were 
augmented for onroad gasoline emissions sources with emissions based on 
a draft version of the Motor Vehicle Emissions Simulator (MOVES) for 
carbon monoxide (CO), NOX, VOC, PM2.5, and 
particulate matter less than ten microns (PM10). While these 
data were preliminary, they more closely reflect the PM2.5 
emissions from the final release of MOVES 2010. To account for the 
temperature dependence of PM2.5, MOVES-based temperature 
adjustment factors were applied to gridded, hourly emissions using 
gridded, hourly meteorology. Additional information on this approach is 
available in the EITSD.
    The annual NOX and SO2 emissions for EGUs in 
the 2005 NEI v2 are based primarily on data from EPA's Clean Air 
Markets Division's Continuous Emissions Monitoring (CEM) program, with 
other pollutants estimated using emission factors and the CEM annual 
heat input. For EGUs without CEMs, data were obtained from the states 
as included in the NEI. For modeling, the 2005 EGU emissions for 
SO2 and NOX were augmented by using hourly CEM 
data to develop a temporal allocation approach of the 2005 NEI v2 
emissions. The annual emissions themselves were unchanged, and match 
closely with data from the CEM program except where states have 
provided data for partial CEM and non-CEM units. The 2005 EGUs were 
identified as all units in 2005 that map to the units modeled by the 
version of the Integrated Planning Model (IPM) used for this proposal, 
and include records both with and without data submitted to the CEM 
program. Temporal profiles were used instead of the actual 2005 CEM 
data so that the temporal allocation approach could be consistent in 
the future year modeling.
    For the 2005 base year, the annual EGU NEI emissions were allocated 
to hourly emissions values needed for modeling based on the 2004, 2005, 
and 2006 CEM data. The NOX CEM data were used to create 
NOX-specific profiles, the SO2 data were used to 
create SO2-specific profiles, and the heat input data were 
used to allocate all other pollutants. The 3 years of data were used to 
create state-specific profiles to allocate from annual to monthly 
values and from daily to hourly values. Only the 2005 data were used to 
create state-specific factors for allocation from month to day, which 
is intended to preserve an appropriate level of daily temporal 
variability needed for this type of modeling.
    Other significant augmentations were also made to the 2005 NEI and 
include the following. The nonpoint inventory was augmented with the 
oil and gas exploration inventory \25\ 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. The 
commercial marine category 3 (C3) vessel 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.'' The 2005 point source 
daily wildfire and prescribed burning emissions were replaced with 
average-year county-based inventories. Additionally, the inventories 
were processed to provide the hourly, gridded, model-species needed by 
CAMx.
---------------------------------------------------------------------------

    \25\ The oil and gas exploration inventory was provided by the 
Western Regional Air Partnership.
---------------------------------------------------------------------------

    Tables IV.C-1 and IV.C-2 provide summaries of SO2 and 
NOX emissions by state by sector for the 2005 base year for 
those states within the eastern 12 km modeling domain. Emissions for 
other states within the 36 km modeling domain are available in the 
EISTD. In the tables, the EGU column summarizes all units matched to 
the IPM model and the nonEGU column is for other point source units. 
The Nonpoint column shows emissions for all nonpoint stationary 
sources. The Nonroad column summarizes emissions for nonroad mobile 
sources, including aircraft, locomotive, and marine sources including 
the C3 commercial marine. The Onroad column summarizes emissions for 
the combined NEI and draft MOVES-based emissions, in which emissions 
from the draft MOVES were used when available, and NEI emissions based 
on MOBILE6 were used for the remainder. Finally, the Fires column 
represents the average-year fire emissions for wildfires and prescribed 
burning mentioned previously.

                                   Table IV.C-1--2005 Base Case SO2 Emissions (Tons/Year) for Eastern States by Sector
--------------------------------------------------------------------------------------------------------------------------------------------------------
                            State                                  EGU         NonEGU      Nonpoint     Nonroad       Onroad       Fires        Total
--------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama......................................................      460,123       70,346       52,325        6,397        3,199          983      593,372
Arkansas.....................................................       66,384       13,066       27,260        5,678        1,632          728      114,749
Connecticut..................................................       10,356        1,831       18,455        2,548        1,128            4       34,320
Delaware.....................................................       32,378       34,859        5,859       11,648          422            6       85,173
District of Columbia.........................................        1,082          686        1,559          414          172            0        3,914
Florida......................................................      417,321       57,475       70,490       93,543       10,285        7,018      656,131
Georgia......................................................      616,054       56,116       56,829       13,331        5,690        2,010      750,031
Illinois.....................................................      330,382      156,154        5,395       19,302        5,716           20      516,969
Indiana......................................................      878,978       95,200       59,775        9,436        3,981           24    1,047,396
Iowa.........................................................      130,264       61,241       19,832        8,838        1,702           25      221,902
Kansas.......................................................      136,520       13,142       36,381        8,035        1,824          103      196,005

[[Page 45240]]


Kentucky.....................................................      502,731       25,811       34,229        6,942        2,711          364      572,787
Louisiana....................................................      109,851      165,737        2,378       73,233        2,399          892      354,489
Maine........................................................        3,887       18,519        9,969        3,725          834          150       37,084
Maryland.....................................................      283,205       34,988       40,864       17,819        2,966           32      379,874
Massachusetts................................................       85,768       19,620       25,261       25,335        2,168           93      158,245
Michigan.....................................................      349,877       76,510       42,066       14,533        7,204           91      490,280
Minnesota....................................................      101,666       25,169       14,747       10,410        2,558          631      155,181
Mississippi..................................................       74,117       29,892        6,796        6,003        2,158        1,051      120,016
Missouri.....................................................      284,384       78,307       44,573       10,464        4,251          186      422,165
Nebraska.....................................................       74,955        6,429       29,575        9,199        1,326          105      121,589
New Hampshire................................................       51,445        3,245        7,408          805          630           38       63,571
New Jersey...................................................       57,044        7,640       10,726       23,484        2,486           61      101,441
New York.....................................................      180,847       58,562      125,158       20,908        5,628          113      391,216
North Carolina...............................................      512,231       66,150       22,020       42,743        5,341          696      649,181
North Dakota.................................................      137,371        9,458        6,455        5,986          443           66      159,779
Ohio.........................................................    1,116,084      118,468       19,810       15,615        6,293           22    1,276,292
Oklahoma.....................................................      110,081       40,482        7,542        5,015        2,699          469      166,288
Pennsylvania.................................................    1,002,202       85,411       68,349       11,972        5,363           32    1,173,328
Rhode Island.................................................          176        2,743        3,365        2,494          208            1        8,987
South Carolina...............................................      218,782       31,495       30,016       20,477        2,976          646      304,393
South Dakota.................................................       12,215        1,698       10,347        3,412          511          498       28,682
Tennessee....................................................      266,148       78,206       32,714        6,288        4,834          277      388,468
Texas........................................................      534,949      223,625      109,215       52,749       13,470        1,178      935,187
Vermont......................................................            9          902        5,385          385          305           49        7,036
Virginia.....................................................      220,248       69,440       32,923       18,420        3,829          399      345,259
West Virginia................................................      469,456       48,314       14,589        2,133        1,095          215      535,802
Wisconsin....................................................      180,200       66,807        6,369        7,129        3,110           70      263,685
                                                              ------------------------------------------------------------------------------------------
    Grand total..............................................   10,019,774    1,953,745    1,117,009      596,847      123,547       19,345   13,380,267
--------------------------------------------------------------------------------------------------------------------------------------------------------


                                   Table IV.C-2--2005 Base Case NOX Emissions (Tons/Year) for Eastern States by Sector
--------------------------------------------------------------------------------------------------------------------------------------------------------
                            State                                  EGU         NonEGU      Nonpoint     Nonroad       Onroad       Fires        Total
--------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama......................................................      133,051       74,830       32,024       61,623      142,221        3,814      447,562
Arkansas.....................................................       35,407       37,478       21,453       63,493       81,014        2,654      241,499
Connecticut..................................................        6,865        5,824       12,554       21,785       69,645           14      116,688
Delaware.....................................................       11,917        5,567        3,259       15,567       22,569           23       58,902
District of Columbia.........................................          492          501        1,740        3,494        9,677            0       15,904
Florida......................................................      217,263       53,778       29,533      277,888      460,474       25,600    1,064,537
Georgia......................................................      111,017       53,297       38,919       95,175      279,449        7,955      585,812
Illinois.....................................................      127,923       97,504       47,645      223,697      276,507           71      773,347
Indiana......................................................      213,503       73,647       30,185      110,100      187,426           88      614,949
Iowa.........................................................       72,806       39,299       15,150       92,965       91,795           90      312,105
Kansas.......................................................       90,220       70,785       42,286       86,553       76,062          378      366,285
Kentucky.....................................................      164,743       35,432       17,557       90,669      127,435        1,326      437,163
Louisiana....................................................       63,791      165,162       27,559      301,170      112,889        3,254      673,824
Maine........................................................        1,100       18,309        7,423       13,379       38,469          566       79,246
Maryland.....................................................       62,574       24,621       21,715       55,812      129,796          137      294,656
Massachusetts................................................       25,618       18,429       34,373       74,419      118,148          341      271,327
Michigan.....................................................      120,005       94,139       43,499      101,087      279,816          330      638,876
Minnesota....................................................       83,836       64,438       56,700      115,873      146,138        2,300      469,286
Mississippi..................................................       45,166       53,985       12,212       79,394       98,060        3,833      292,649
Missouri.....................................................      127,431       38,604       32,910      123,228      183,022          678      505,873
Nebraska.....................................................       52,426       12,156       13,820      107,180       58,643          381      244,607
New Hampshire................................................        8,827        3,241       11,235        9,246       32,537          137       65,223
New Jersey...................................................       30,114       20,598       26,393       88,486      157,736          223      323,550
New York.....................................................       63,465       55,122       87,608      121,363      282,072          412      610,042
North Carolina...............................................      111,576       44,502       18,869      135,936      225,756       11,424      548,064
North Dakota.................................................       76,381        7,545       10,046       59,635       21,575          240      175,422
Ohio.........................................................      258,687       71,715       41,466      173,988      270,383           81      816,321
Oklahoma.....................................................       86,204       73,465       94,574       55,424      117,240        1,709  ...........
Pennsylvania.................................................      176,870       89,208       53,435      118,774      266,649          117      705,053
Rhode Island.................................................          545        2,164        2,964        7,798       13,456            4       26,930
South Carolina...............................................       53,823       29,069       20,281       68,146      128,765        2,357      302,441
South Dakota.................................................       15,650        5,035        5,766       30,324       24,850        1,817       83,442
Tennessee....................................................      102,934       60,353       18,676       82,331      207,410        1,012      472,717
Texas........................................................      176,170      292,806      274,338      377,246      615,715        4,890    1,741,166
Vermont......................................................          297          799        3,438        3,951       13,316          179       21,980
Virginia.....................................................       62,512       60,101       53,605       91,298      194,173        1,456      463,145
West Virginia................................................      159,804       36,913       14,519       32,739       50,040          785      294,801

[[Page 45241]]


Wisconsin....................................................       72,170       40,688       21,994       75,981      147,952          256      359,042
                                                              ------------------------------------------------------------------------------------------
    Grand total..............................................    3,223,184    1,931,111    1,301,726    3,647,215    5,758,880       80,931   15,943,047
--------------------------------------------------------------------------------------------------------------------------------------------------------

(2) Development of Future Year Emissions
    The future base case scenarios represent predicted emissions in the 
absence of any further controls beyond those federal measures already 
promulgated. For EGUs, all state and other programs available at the 
time of modeling have been included. For mobile sources, all national 
measures available at the time of modeling have been included. For 
nonEGU point and nonpoint stationary sources, any 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. The future base case scenarios do reflect 
projected economic changes and fuel usage for EGU and mobile sectors, 
as described in the EITSD.
    Tables IV.C-3 through IV.C-6 provide 2012 and 2014 summaries of 
emissions data for 2012 and 2014 modeling for all sectors for 
SO2 and NOX for states included in the 12 km 
modeling domain. The EITSD provides summaries for additional pollutants 
with additional detail and for all states in the nationwide 36 km 
modeling domain.

                                   Table IV.C-3--2012 Base Case SO2 Emissions (Tons/Year) for Eastern States by Sector
--------------------------------------------------------------------------------------------------------------------------------------------------------
                            State                                  EGU         NonEGU      Nonpoint     Nonroad       Onroad       Fires        Total
--------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama......................................................      335,734       70,346       52,315        2,333          585          983      462,297
Arkansas.....................................................       85,068       13,054       27,257          818          336          728      127,259
Connecticut..................................................        5,493        1,831       18,443        1,292          330            4       27,392
Delaware.....................................................        7,841       10,974        5,858       14,193           98            6       38,970
District of Columbia.........................................            0          686        1,559           10           41            0        2,296
Florida......................................................      228,360       57,491       70,482      102,076        2,072        7,018      467,498
Georgia......................................................      552,007       56,122       56,817        7,984        1,253        2,010      676,193
Illinois.....................................................      724,657      133,201        5,384        1,960        1,174           20      866,396
Indiana......................................................      829,988       95,201       59,767          871          775           24      986,626
Iowa.........................................................      169,039       61,242       19,821          482          346           25      250,954
Kansas.......................................................       59,567       13,048       36,376          518          302          103      109,915
Kentucky.....................................................      718,980       25,813       34,214        1,368          510          364      781,249
Louisiana....................................................      100,239      159,722        2,373       78,051          455          892      341,731
Maine........................................................       15,759       18,519        9,950        3,926          156          150       48,460
Maryland.....................................................       49,078       34,988       40,854       17,112          608           32      142,672
Massachusetts................................................       16,299       19,622       25,242       29,825          575           93       91,657
Michigan.....................................................      287,807       76,458       42,066        7,636        1,074           91      415,132
Minnesota....................................................       53,596       25,100       14,733        1,342          596          631       95,997
Mississippi..................................................       46,432       24,426        6,788        2,094          375        1,051       81,166
Missouri.....................................................      445,643       78,310       44,550        1,307          765          186      570,761
Nebraska.....................................................      120,790        6,430       29,571          817          209          105      157,921
New Hampshire................................................        7,290        3,245        7,396           72          142           38       18,183
New Jersey...................................................       37,746        6,747       10,715       25,286          772           61       81,327
New York.....................................................      144,074       58,566      125,187       12,336        1,541          113      341,818
North Carolina...............................................      126,620       66,128       22,000       48,861          935          696      265,240
North Dakota.................................................       77,383        9,458        6,451          288           76           66       93,722
Ohio.........................................................      946,667      105,406       19,810        3,456        1,131           22    1,076,493
Oklahoma.....................................................      156,032       36,912        7,536          341          502          469      201,791
Pennsylvania.................................................      966,136       79,142       68,330        4,938        1,135           32    1,119,712
Rhode Island.................................................            0        2,743        3,364        2,879           82            1        9,069
South Carolina...............................................      149,515       31,452       30,005       22,697          532          646      234,846
South Dakota.................................................       13,453        1,698       10,342           65           91          498       26,147
Tennessee....................................................      596,987       77,595       32,701          828          795          277      709,182
Texas........................................................      327,873      162,915      109,199       37,109        2,409        1,178      640,682
Vermont......................................................            0          902        5,381            6           94           49        6,432
Virginia.....................................................      145,452       69,166       32,904       15,158          883          399      263,963
West Virginia................................................      588,392       41,817       14,583          443          197          215      645,646
Wisconsin....................................................      107,365       66,452        6,370          928          646           70      181,830
                                                              ------------------------------------------------------------------------------------------
    Grand total..............................................    9,243,362    1,802,927    1,116,694      451,705       24,595       19,345   12,658,628
--------------------------------------------------------------------------------------------------------------------------------------------------------


                                   Table IV.C-4--2012 Base Case NOX Emissions (Tons/Year) for Eastern States by Sector
--------------------------------------------------------------------------------------------------------------------------------------------------------
                            State                                  EGU         NonEGU      Nonpoint     Nonroad       Onroad       Fires        Total
--------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama......................................................      121,809       74,832       31,958       49,622       82,135        3,814      364,171
Arkansas.....................................................       43,222       37,479       21,429       48,349       46,959        2,654      200,092
Connecticut..................................................        2,770        5,830       12,475       15,865       37,847           14       74,801

[[Page 45242]]


Delaware.....................................................        4,639        5,567        3,248       15,511       10,700           23       39,687
District of Columbia.........................................            2          501        1,739        2,704        4,857            0        9,802
Florida......................................................      195,673       55,017       29,475      282,147      275,603       25,600      863,515
Georgia......................................................       78,011       53,317       38,825       76,901      158,771        7,955      413,780
Illinois.....................................................       77,920       92,440       47,564      167,046      157,915           71      542,957
Indiana......................................................      203,107       73,651       30,125       83,760      114,396           88      505,127
Iowa.........................................................       66,316       39,301       15,064       72,031       58,920           90      251,721
Kansas.......................................................       70,823       70,751       42,249       66,897       43,914          378      295,012
Kentucky.....................................................      149,179       34,875       17,446       72,289       71,284        1,326      346,399
Louisiana....................................................       44,773      161,724       27,525      285,562       64,074        3,254      586,912
Maine........................................................        3,139       18,309        7,295       13,354       21,896          566       64,559
Maryland.....................................................       17,376       24,624       21,647       53,580       64,368          137      181,731
Massachusetts................................................        6,312       18,447       34,245       75,149       57,417          341      191,911
Michigan.....................................................       96,874       93,953       43,392       80,900      163,505          330      478,955
Minnesota....................................................       51,285       64,250       56,581       92,080       86,198        2,300      352,694
Mississippi..................................................       37,517       52,454       12,151       64,138       52,709        3,833      222,801
Missouri.....................................................       77,571       38,610       32,731       96,197      108,298          678      354,085
Nebraska.....................................................       52,820       12,159       13,788       81,177       33,907          381      194,233
New Hampshire................................................        2,514        3,243       11,153        7,308       19,710          137       44,067
New Jersey...................................................       15,987       18,996       26,320       81,906       76,979          223      220,410
New York.....................................................       25,755       55,167       87,776      100,212      154,260          412      423,582
North Carolina...............................................       61,643       44,514       18,715      133,476      126,081       11,424      395,854
North Dakota.................................................       59,547        7,544       10,018       46,649       12,111          240      136,110
Ohio.........................................................      159,627       69,075       41,378      133,650      149,134           81      552,945
Oklahoma.....................................................       86,858       71,808       94,528       43,057       71,207        1,709      369,167
Pennsylvania.................................................      193,032       85,168       53,289       92,594      142,217          117      566,418
Rhode Island.................................................          221        2,168        2,959        7,468        8,120            4       20,940
South Carolina...............................................       47,762       28,953       20,273       63,564       75,994        2,357      238,903
South Dakota.................................................       15,493        5,035        5,733       24,117       14,957        1,817       67,151
Tennessee....................................................       68,425       59,594       18,573       65,209      126,353        1,012      339,166
Texas........................................................      159,738      287,831      274,203      313,204      303,453        4,890    1,343,319
Vermont......................................................            0          800        3,406        3,077       10,328          179       17,790
Virginia.....................................................       36,036       60,101       53,496       79,717      111,583        1,456      342,389
West Virginia................................................      102,725       35,698       14,473       26,040       27,694          785      207,415
Wisconsin....................................................       49,351       40,694       21,979       58,951       86,315          256      257,546
                                                              ------------------------------------------------------------------------------------------
    Grand Total..............................................    2,485,856    1,904,481    1,299,224    3,075,459    3,232,168       80,932   12,078,120
--------------------------------------------------------------------------------------------------------------------------------------------------------


                                   Table IV.C-5--2014 Base Case SO2 Emissions (Tons/Year) for Eastern States by Sector
--------------------------------------------------------------------------------------------------------------------------------------------------------
                            State                                  EGU         NonEGU      Nonpoint     Nonroad       Onroad       Fires        Total
--------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama......................................................      322,130       69,150       52,313        1,873          605          983      447,053
Arkansas.....................................................       88,187       13,055       27,256          142          347          728      129,714
Connecticut..................................................        5,512        1,834       18,440        1,294          340            4       27,423
Delaware.....................................................        7,806       10,974        5,857       14,891          101            6       39,635
District of Columbia.........................................            0          686        1,559            4           42            0        2,291
Florida......................................................      192,903       57,521       70,480      108,579        2,159        7,018      438,658
Georgia......................................................      173,210       56,014       56,813        8,263        1,307        2,010      297,618
Illinois.....................................................      200,475      133,109        5,381          390        1,221           20      340,596
Indiana......................................................      804,294       95,037       59,764          193          810           24      960,123
Iowa.........................................................      163,966       60,195       19,817           85          360           25      244,448
Kansas.......................................................       65,125       13,048       36,375           54          313          103      115,018
Kentucky.....................................................      739,592       23,804       34,210          258          528          364      798,755
Louisiana....................................................       94,824      151,216        2,372       78,097          470          892      327,871
Maine........................................................       11,650       18,520        9,945        4,215          160          150       44,640
Maryland.....................................................       42,635       34,994       40,851       16,966          631           32      136,109
Massachusetts................................................       16,299       19,624       25,237       32,043          594           93       93,890
Michigan.....................................................      275,637       76,437       42,066        7,536        1,107           91      402,874
Minnesota....................................................       61,447       25,112       14,728          468          618          631      103,005
Mississippi..................................................       48,149       24,427        6,785        1,280          385        1,051       82,077
Missouri.....................................................      500,649       77,086       44,543          214          796          186      623,473
Nebraska.....................................................      115,695        6,431       29,570           55          217          105      152,072
New Hampshire................................................        6,608        3,246        7,393           45          148           38       17,476
New Jersey...................................................       37,669        6,756       10,712       26,589          799           61       82,585
New York.....................................................      141,354       58,584      125,196       10,853        1,594          113      337,694
North Carolina...............................................      140,585       66,046       21,994       52,897          961          696      283,180
North Dakota.................................................       80,320        9,458        5,763           35           78           66       95,720
Ohio.........................................................      841,194      105,123       19,810        2,085        1,171           22      969,405
Oklahoma.....................................................      165,773       36,924        7,534           45          524          469      211,268
Pennsylvania.................................................      972,977       76,256       68,324        4,117        1,169           32    1,122,876

[[Page 45243]]


Rhode Island.................................................            0        2,745        3,364        3,128           85            1        9,323
South Carolina...............................................      156,096       31,453       30,002       24,380          551          646      243,129
South Dakota.................................................       13,459        1,699       10,298           22           94          498       26,070
Tennessee....................................................      600,066       77,605       32,696          173          829          277      711,647
Texas........................................................      373,950      155,720      109,194       36,109        2,511        1,178      678,662
Vermont......................................................            0          903        5,380            7          101           49        6,439
Virginia.....................................................      135,741       69,177       32,899       15,624          918          399      254,758
West Virginia................................................      496,307       41,817       14,581           96          201          215      553,218
Wisconsin....................................................      117,253       66,456        6,370          638          675           70      191,461
                                                              ------------------------------------------------------------------------------------------
    Grand Total..............................................    8,209,536    1,778,244    1,116,600      453,742       25,516       19,345   11,602,982
--------------------------------------------------------------------------------------------------------------------------------------------------------


                                   Table IV.C-6--2014 Base Case NOX Emissions (Tons/Year) for Eastern States by Sector
--------------------------------------------------------------------------------------------------------------------------------------------------------
                            State                                  EGU         NonEGU      Nonpoint     Nonroad       Onroad       Fires        Total
--------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama......................................................      118,420       74,622       31,939       45,932       67,011        3,814      341,738
Arkansas.....................................................       44,792       37,491       21,422       44,299       38,965        2,654      189,623
Connecticut..................................................        2,821        5,854       12,451       14,410       31,534           14       67,084
Delaware.....................................................        4,513        5,567        3,245       15,270        8,736           23       37,353
District of Columbia.........................................            1          501        1,738        2,398        3,929            0        8,568
Florida......................................................      180,801       55,343       29,457      278,920      225,478       25,600      795,599
Georgia......................................................       48,091       53,557       38,797       71,011      130,240        7,955      349,650
Illinois.....................................................       80,228       93,059       47,540      151,373      131,403           71      503,676
Indiana......................................................      200,899       73,523       30,107       76,024       94,217           88      474,858
Iowa.........................................................       68,146       38,831       15,038       65,751       48,836           90      236,692
Kansas.......................................................       78,920       70,730       42,238       61,613       35,950          378      289,829
Kentucky.....................................................      148,509       34,979       17,413       65,805       57,759        1,326      325,791
Louisiana....................................................       45,457      161,766       27,515      274,697       52,360        3,254      565,049
Maine........................................................        2,535       18,316        7,257       13,169       18,061          566       59,903
Maryland.....................................................       19,990       24,687       21,626       52,501       53,040          137      171,980
Massachusetts................................................        6,619       18,527       34,207       75,654       46,748          341      182,095
Michigan.....................................................       97,455       94,079       43,360       73,939      135,806          330      444,969
Minnesota....................................................       51,859       64,372       56,545       84,040       71,161        2,300      330,278
Mississippi..................................................       37,142       52,440       12,133       58,559       42,525        3,833      206,633
Missouri.....................................................       82,979       38,744       32,677       88,233       90,001          678      333,312
Nebraska.....................................................       52,970       12,173       13,779       75,252       27,856          381      182,410
New Hampshire................................................        2,515        3,255       11,129        6,587       16,260          137       39,884
New Jersey...................................................       16,268       19,089       26,298       78,875       63,254          223      204,007
New York.....................................................       28,350       55,359       87,826       92,841      129,376          412      394,165
North Carolina...............................................       61,747       44,573       18,669      133,455      104,150       11,424      374,018
North Dakota.................................................       59,556        7,549        3,969       42,972        9,925          240      130,252
Ohio.........................................................      164,945       69,157       41,352      120,900      122,426           81      518,861
Oklahoma.....................................................       81,122       72,525       94,513       39,539       58,382        1,709      347,790
Pennsylvania.................................................      196,151       84,111       53,246       83,885      118,122          117      535,631
Rhode Island.................................................          281        2,186        2,957        7,384        6,772            4       19,585
South Carolina...............................................       47,512       28,969       20,271       62,400       62,996        2,357      224,505
South Dakota.................................................       15,514        5,039        5,157       22,021       12,254        1,817       62,368
Tennessee....................................................       68,779       59,694       18,542       59,145      104,711        1,012      311,882
Texas........................................................      166,177      282,509      274,163      289,605      241,009        4,890    1,258,354
Vermont......................................................            0          803        3,397        2,771        8,563          179       15,713
Virginia.....................................................       32,115       60,216       53,464       75,461       92,291        1,456      315,002
West Virginia................................................      100,103       35,700       14,459       23,798       22,863          785      197,708
Wisconsin....................................................       53,774       40,729       21,974       53,848       71,163          256      241,743
                                                              ------------------------------------------------------------------------------------------
    Grand total..............................................    2,468,057    1,900,624    1,298,473    2,884,338    2,656,134       80,932   11,288,558
--------------------------------------------------------------------------------------------------------------------------------------------------------

Development of Future-Year Emissions Inventories for Electric 
Generating Units

    Future year 2012 and 2014 base case EGU emissions used for the air 
quality modeling runs that predicted ozone and PM2.5 were 
obtained from version 3.02 EISA of the IPM (http://www.epa.gov/
airmarkt/progsregs/epa-ipm/index.html). The IPM is a multiregional, 
dynamic, deterministic linear programming model of the U.S. electric 
power sector; version 3.02 EISA features an updated Title IV 
SO2 allowance bank assumption, reflects state rules and 
consent decrees through February 3, 2009, and incorporates updates 
related to the Energy Independence and Security Act of 2007. Units with 
advanced controls (e.g., scrubber, SCR) that were not required to run 
for compliance with Title IV, New Source Review (NSR), state 
settlements, or state-specific rules were allowed in IPM to decide on 
the basis of economic efficiency whether to operate those controls. 
Further details on the EGU emissions inventory used for this proposal 
can be found in the IPM Documentation. Also note that as explained in 
section IV.A.3, the baseline used in this analysis assumes no CAIR. If 
EPA's base case analysis were to

[[Page 45244]]

assume that reductions from CAIR would continue indefinitely, areas 
that are in attainment solely due to controls required by CAIR would 
again face nonattainment problems because the existing protection from 
upwind pollution would not be replaced. 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).

Development of Future-Year Emissions Inventories for Mobile Inventories

    Mobile source inventories of onroad and nonroad mobile emissions 
were created for 2012 and 2015 using a combination of the NMIM and 
draft MOVES models. Mobile source emissions were further interpolated 
between 2012 and 2015 to estimate 2014 emissions. Emissions for these 
years reflect onroad mobile control programs including the Light-Duty 
Vehicle Tier 2 Rule, the Onroad Heavy-Duty Rule, and the Mobile Source 
Air Toxics (MSAT) final rule. Nonroad mobile emissions reductions for 
these years 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 
EITSD.
    The onroad emissions were primarily based on the NMIM monthly, 
county, process level emissions. For both 2012 and 2015, emissions from 
onroad gasoline sources were augmented with emissions based on the same 
preliminary version of MOVES as was used for 2005. MOVES-based 
emissions were computed for CO, NOX, VOC, PM2.5, 
and PM10. The same MOVES-based PM2.5 temperature 
adjustment factors were also applied as in 2005.
    Nonroad mobile emissions were created only with NMIM using a 
consistent approach as was used for 2005, but emissions were calculated 
using NMIM future-year equipment population estimates and control 
programs for 2012 and 2014. Emissions from 2012 and 2015 were used for 
locomotives and category 1 and 2 (C1 and C2) commercial marine vessels, 
based on emissions published in OTAQ's Locomotive Marine Rule, 
Regulatory Impact Assessment, Chapter 3. For category 3 (C3) commercial 
marine vessels, a coordination strategy of emissions reductions is 
ongoing that includes NOX, VOC, and CO reductions for new C3 
engines as early as 2011 and fuel sulfur limits that could go into 
affect as early as 2012. However, given the uncertainty about the 
timing for parts of these emissions reductions and the fact that the 
2012 modeling was conducted well in advance of the December 2009 
publication of the rule, we have not used the controlled emissions in 
modeling supporting this proposal.

Development of Future-Year Emissions Inventories for Other Inventory 
Sources

    Other inventory sources include nonEGU point sources, stationary 
nonpoint sources, and emissions in Canada and Mexico. Emissions from 
Canada and Mexico for all source sectors (including EGUs) in these 
countries were held constant for all cases. This approach reflects the 
unavailability of future-year emissions from Canada and Mexico for the 
future years of interest in time to support the modeling for this 
proposal.
    The future year emissions for other sectors are described next. For 
all sector projections, EPA seeks comment on growth and control 
approaches, particularly where a control measure has not been included. 
The EITSD provides more details on these projections for additional 
review and we have included in the EITSD a table for the public to 
provide more detailed control data to EPA.
    For nonEGU point sources, emissions were projected by including 
emissions reductions and increases from a variety of sources. For 
nonEGUs, emissions were not grown using economic growth projections and 
emissions reductions were applied through plant closures, refinery and 
other consent decrees, and reductions stemming from several MACT 
standards. Since aircraft at airports were treated as point emissions 
sources in the 2005 NEI v2, we also applied projection factors based on 
activity growth projected by the Federal Aviation Administration 
Terminal Area Forecast (TAF) system, published December 2008. Controls 
from the NOX SIP Call were assumed to have been implemented 
by 2005 and captured in the 2005 NEI v2.
    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 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 woodstoves 
with new woodstoves 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.
(3) Preparation of Emissions for AQ Modeling
    The annual and summer day emissions inventory files were processed 
through the Sparse Matrix Operator Kernel Emissions (SMOKE) Modeling 
System version 2.6 to produce the gridded model-ready emissions for 
input to CAMx. Emissions processing using SMOKE was performed to create 
the hourly, gridded data of CAMx species required for air quality 
modeling for all sectors, including biogenic emissions. Additional 
information on the development of the emissions data sets for modeling 
is provided in the EITSD. Details about preparation of emissions for 
contribution modeling are described in the Transport Rule AQ Modeling 
TSD.
c. Preparation of Meteorological and Other Air Quality Modeling Inputs
    The gridded meteorological input data for the entire year of 2005 
were derived from simulations of the Pennsylvania State University/
National Center for Atmospheric Research Mesoscale Model. This model, 
commonly referred to as MM5, is a limited-area, nonhydrostatic, 
terrain-following system that solves for the full set of physical and 
thermodynamic equations which govern atmospheric motions.\26\ The 
meteorological outputs from MM5 were processed to create model-ready 
inputs for CMAQ using the MM5-to-CAMx preprocessor (ref CAMx user's 
guide).
---------------------------------------------------------------------------

    \26\ Grell, G., J. Dudhia, and D. Stauffer, 1994: A Description 
of the Fifth-Generation Penn State/NCAR Mesoscale Model (MM5), NCAR/
TN-398+STR., 138 pp, National Center for Atmospheric Research, 
Boulder CO.
---------------------------------------------------------------------------

    The 2005 MM5 meteorological predictions for selected variables were 
compared to measurements as part of several performance evaluations of 
the predicted data. The evaluation approach included a combination of 
qualitative and quantitative analyses to assess the adequacy of the MM5 
simulated fields. The qualitative aspects involved comparisons of the 
model-estimated synoptic patterns against observed patterns from 
historical weather chart archives. Additionally, the evaluations 
compared spatial patterns of monthly average rainfall and monthly 
maximum planetary boundary layer (PBL) heights. The operational 
evaluation included

[[Page 45245]]

statistical comparisons of model/observed pairs (e.g., mean normalized 
bias, mean normalized error, index of agreement, root mean square 
errors, etc.) for multiple meteorological parameters. For this portion 
of the evaluation, five meteorological parameters were investigated: 
Temperature, humidity, shortwave downward radiation, wind speed, and 
wind direction. The three individual MM5 evaluations are described 
elsewhere.27 28 29  It was ultimately determined that the 
bias and error values associated with the 2005 meteorological data were 
generally within the range of past meteorological modeling results that 
have been used for air quality applications. Additional details on the 
meteorological inputs can be found in the AQMTSD.
---------------------------------------------------------------------------

    \27\ Baker K. and P. Dolwick. Meteorological Modeling 
Performance Evaluation for the Annual 2005 Eastern U.S. 12-km Domain 
Simulation, USEPA/OAQPS, February 2, 2009.
    \28\ Baker K. and P. Dolwick. Meteorological Modeling 
Performance Evaluation for the Annual 2005 Western U.S. 12-km Domain 
Simulation, USEPA/OAQPS, February 2, 2009.
    \29\ Baker K. and P. Dolwick. Meteorological Modeling 
Performance Evaluation for the Annual 2005 Continental U.S. 36-km 
Domain Simulation, USEPA/OAQPS, February 2, 2009.
---------------------------------------------------------------------------

    As noted previously, the CAMx simulations for this proposal were 
performed using a spatial resolution of 12 x 12 km. The concentrations 
of pollutants transported into this eastern U.S. modeling region were 
obtained from air quality model simulations performed at coarser 36 x 
36 km resolution for a modeling domain covering the lower 48 states and 
portions of northern Mexico and southern Canada. The 12 x 12 km model 
simulations were also initialized with air quality predictions from the 
coarse scale modeling. Pollutant concentrations at the boundaries of 
the coarse scale modeling domain were obtained from a three-dimensional 
global atmospheric chemistry model, the GEOSChem \30\ model (standard 
version 7-04-11 \31\). The global GEOSChem model simulates atmospheric 
chemical and physical processes driven by assimilated meteorological 
observations from the NASA's Goddard Earth Observing System (GEOS). 
This model was run for 2005 with a grid resolution of 2.0 degrees x 2.5 
degrees (latitude-longitude). The predictions were used to provide one-
way dynamic boundary conditions at three-hour intervals and an initial 
concentration field for the coarse scale simulations.
---------------------------------------------------------------------------

    \30\ Yantosca, B., 2006. GEOS-CHEMv7-04-11 User's Guide, 
Atmospheric Chemistry Modeling Group, Harvard University, Cambridge, 
MA, March 05, 2006.
    \31\ Henze, D.K., J.H. Seinfeld, N.L. Ng, J.H. Kroll, T-M. Fu, 
D.J. Jacob, C.L. Heald, 2008. Global modeling of secondary organic 
aerosol formation from aromatic hydrocarbons: high-vs. low-yield 
pathways. Atmos. Chem. Phys., 8, 2405-2420.
---------------------------------------------------------------------------

d. Model Performance Evaluation for Ozone and PM2.5
    The 2005 base year model predictions for ozone and fine particulate 
sulfate, nitrate, organic carbon, elemental carbon, and crustal 
material were compared to measured concentrations in order to evaluate 
the performance of the modeling platform for replicating observed 
concentrations. This evaluation was comprised principally of 
statistical assessments of paired modeled and observed data. Details on 
the evaluation methodology and the calculation of performance 
statistics are provided in the AQMTSD. The results indicate that, 
overall, the predicted patterns and day-to-day variations in regional 
ozone levels are similar to what was observed with measured data. The 
normalized mean bias for 8-hour daily maximum ozone concentrations was 
-2.9 percent and the normalized mean error was 13.2 percent for the 
months of May through September 2005, based on an aggregate of 
observed-predicted pairs within the 12 km modeling domain. The two 
PM2.5 species that are most relevant for this proposal are 
sulfate and nitrate. For the summer months of June though August, when 
observed sulfate concentrations are highest in the East, the model 
predictions of 24-hour average sulfate were lower than the 
corresponding measured values by 7 percent at urban sites and by 9 to 
10 percent at rural sites in the IMPROVE \32\ and CASTNET \33\ 
monitoring networks, respectively. For the winter months of December 
through February, when observed nitrate concentrations are highest in 
the East, the model predictions of 24-hour average particulate nitrate 
were lower than the corresponding measured values by 12 percent at 
urban sites and by 4 percent at rural sites in the IMPROVE monitoring 
network. The model performance statistics by season for ozone and 
PM2.5 component species are provided in the AQMTSD.
---------------------------------------------------------------------------

    \32\ Interagency Monitoring of PROtected Visual Environments 
(IMPROVE). Debell, L.J., et. al. Spatial and Seasonal Patterns and 
Temporal Variability of Haze and its Constituents in the United 
States: Report IV. November 2006.
    \33\ Clean Air Status and Trends Network (CASTNET) 2005 Annual 
Report. EPA Office of Air and Radiation, Clean Air Markets Division. 
Washington, DC. December 2006.
---------------------------------------------------------------------------

2. How did EPA project future nonattainment and maintenance for annual 
PM2.5, 25-Hour PM2.5, and 8-hour ozone?
    In this section we describe the approach for projecting future 
concentrations of ozone and PM2.5 to identify locations that 
are expected to be nonattainment or have a maintenance problem in 2012. 
The nonattainment and maintenance locations are based on projections of 
future air quality at existing ozone and PM2.5 monitoring 
sites. These sites are used as the ``receptors'' for quantifying the 
contributions of emissions in upwind states to nonattainment and 
maintenance in downwind locations. For this analysis we are using the 
air quality modeling results in a ``relative'' sense to project future 
concentrations. In this approach, the ratio of future year model 
predictions to base year model predictions are used to adjust ambient 
measured data up or down depending on the relative (percent) change in 
model predictions for each location.
a. How did EPA process ambient ozone and PM2.5 data for the 
purpose of projecting future year concentrations?
    In this analysis we use measurements of ambient ozone and 
PM2.5 data that come from monitoring networks consisting of 
more than one thousand ozone monitors and one thousand PM2.5 
monitors located across the country. The monitors are sited according 
to the spatial and temporal nature of ozone and PM2.5, and 
to best represent the actual air quality in the United States. The 
ambient data used in this analysis were obtained from EPA's Air Quality 
System (AQS).
    In order to use the ambient data, the raw measurements must be 
processed into a form pertinent for useful interpretations. For this 
action, the ozone data were processed consistent with the formats 
associated with the NAAQS for ozone. The resulting estimates are used 
to indicate the level of air quality relative to the NAAQS. For ozone 
air quality indicators, we developed estimates for the 1997 8-hour 
ozone standard. The level of the 1997 8-hour O3 NAAQS is 0.08 ppm. The 
8-hour ozone standard is not met if the 3-year average of the annual 
4th highest daily maximum 8-hour O3 concentration is greater than 0.08 
ppm (0.085 ppm when rounded up). This 3-year average is referred to as 
the design value.
    The PM2.5 ambient data were processed consistent with 
the formats associated with the NAAQS for PM2.5. The 
resulting estimates are used to

[[Page 45246]]

indicate the level of air quality relative to the NAAQS. For 
PM2.5, we evaluated concentrations of both the annual 
average PM2.5 NAAQS and the 24-hour PM2.5 NAAQS. 
The annual PM2.5 standard is met when the 3-year average of 
the annual mean concentration is 15.0 [mu]g/m \3\ or less. The 3-year 
average annual mean concentration is computed at each site by averaging 
the daily Federal Reference Method (FRM) samples by quarter, averaging 
these quarterly averages to obtain an annual average, and then 
averaging the three annual averages. The 3-year average annual mean 
concentration is referred to as the annual design value.
    The 24-hour average standard is met when the 3-year average of the 
annual 98th percentile PM2.5 concentration is 35 [mu]g/m \3\ 
or less. The 3-year average mean 98th percentile concentration is 
computed at each site by averaging the 3 individual annual 98th 
percentile values at each site. The 3-year average 98th percentile 
concentration is referred to as the 24-hour average design value.
    As described later, the approach for projecting future ozone and 
PM2.5 design values involved the projection of an average of 
up to 3 design value periods which include the years 2003-2007 (design 
values for 2003-2005, 2004-2006, and 2005-2007). The average of the 3 
design values creates a ``5-year weighted average'' value. The 5-year 
weighted average values were then projected to the future years that 
were analyzed for this proposed rule. The 2003-2005, 2004-2006, and 
2005-2007 design values are accessible at http://www.epagov/airtrends/
values.html.
    The procedures for projecting annual average PM2.5 and 
8-hour ozone conform to the methodology in the final attainment 
demonstration modeling guidance \34\. In the CAIR analysis, EPA did not 
project 24-hour PM2.5 design values \35\. The analysis for 
this proposed rule, in contrast, uses the 24-hour PM2.5 
methodology outlined in the modeling guidance.
---------------------------------------------------------------------------

    \34\ 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.
    \35\ CAIR was promulgated in 2005 before the 35 ug/m \3\ 
PM2.5 NAAQS was finalized in 2006. Since there were no 
violations in the eastern United States (base or future year) of the 
1997 65 ug/m3 NAAQS, it was not necessary to project 24 
PM2.5 values as part of the modeling for CAIR.
---------------------------------------------------------------------------

b. Projection of Future Annual and 24-Hour PM2.5 
Nonattainment and Maintenance
    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 (i.e., monitoring sites) 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.
    In general, the projection methodology involves using the model in 
a relative sense to estimate the change in PM2.5 between 
2005 and the future 2012 base case as recommended in the modeling 
guidance. Rather than use the absolute model-predicted future year 
ozone and PM2.5 concentrations, the base year and future 
year predictions are used to calculate a (relative) percent change in 
ozone and PM2.5 concentrations. For a particular location, 
the percent change in modeled concentration is multiplied by the 
corresponding observed base period ambient concentration to estimate 
the future year design value for that location. The use of observed 
ambient data as part of the calculation helps to constrain the future 
year design value predictions, even if the absolute model 
concentrations are over-predicted or under-predicted.
    Concentrations of PM2.5 in 2012 were estimated by 
applying the 2005 to 2012 relative change in model-predicted 
PM2.5 species to the (2003-2007) PM2.5 design 
values. The choice of base period design values is consistent with 
EPA's modeling guidance which recommends using the average of the three 
design value periods centered about the emissions projection year. 
Since 2005 was the base emissions year, we used the design value for 
2003-2005, 2004-2006, and 2005-2007 to represent the base period 
PM2.5 concentrations. For each FRM PM2.5 
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 concentration.
    The 5-year weighted average concentrations were used to project 
concentrations for the 2012 base case in order to determine which 
monitoring sites are expected to be nonattainment in this future year. 
We projected 2012 design values for each of 3 year periods (i.e., 2003-
2005, 2004-2006, and 2003-2007) and used the highest of these 
projections to determine which sites are expected to have maintenance 
problems in 2012.
    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.\36\ 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 736 
sites which met this criteria for the 24-hour NAAQS.\37\
---------------------------------------------------------------------------

    \36\ If there is only one complete design value, then the 
nonattainment and maintenance design values are the same.
    \37\ 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. The model predictions are 
used in a relative sense to estimate changes expected to occur in each 
of the major PM2.5 species. The PM2.5 species are 
sulfate, nitrate, ammonium, particle bound water, elemental carbon, 
salt, other primary PM2.5, and organic aerosol mass by 
difference. Organic aerosol mass by difference is defined as the 
difference between FRM PM2.5 and the sum of the other 
components. The procedure for calculating future year PM2.5 
design values is called the SMAT. The SMAT approach is codified in a 
software tool available from EPA called MATS. The software (including 
documentation) is available at: http://www.epa.gov/scram001/
modelingapps_mats.htm.
(1) Methodology for Projecting Future Annual PM2.5 
Nonattainment and Maintenance
    The following is a brief summary of the future year annual 
PM2.5 calculations. Additional details are provided in the 
modeling guidance, MATS documentation, and the AQMTSD.
    We are using the base period (i.e., 2003 2007) FRM data for 
projecting future design values since these data are used to determine 
attainment status. In order to apply SMAT to the FRM data, information 
on PM2.5 speciation is needed for the location of each FRM 
monitoring site. Since co-located PM2.5 speciation data are 
only available at about 15 percent of FRM monitoring sites, spatial 
interpolation techniques are used to calculate species concentrations 
for each FRM monitoring site. Speciation data from the IMPROVE and 
Chemical Speciation Network

[[Page 45247]]

(CSN) were interpolated to each FRM monitor location using the Voronoi 
Neighbor Averaging (VNA) technique (using MATS). Additional information 
on the VNA interpolation techniques and data handling procedures can be 
found in the MATS User's Guide. After the species fractions are 
calculated for each FRM site, the following procedures were used to 
estimate future year design values:
    Step 1: Calculate quarterly mean concentrations for each of the 
major species components of PM2.5 (i.e., sulfate, nitrate, 
ammonium, elemental carbon, organic carbon mass, particle bound water, 
salt, and blank mass). This is done by multiplying the monitored 
quarterly mean concentration of FRM-derived total PM2.5 by 
the monitored fractional composition of PM2.5 species for 
each quarter averaged over 3 years \38\ (e.g., 20 percent sulfate 
fraction multiplied by 15 [mu]g/m\3\ PM2.5 equals 3 [mu]g/
m\3\ sulfate).
---------------------------------------------------------------------------

    \38\ For this analysis, species fractions were calculated using 
an average of FRM and speciation data for the 2004-2006 time period. 
This was deemed to be representative of the 2005 base year.
---------------------------------------------------------------------------

    Step 2: For each quarter, calculate the ratio of future year to 
base year model predictions for each of the component species. The 
result is a set of species-specific relative response factors (RRF) 
(e.g., assume that the model-predicted 2005 base year sulfate for a 
particular location is 10.0 [mu]g/m\3\ and the 2012 future 
concentration is 8.0 [mu]g/m\3\, then RRF for sulfate is 0.8). The RRFs 
are calculated based on the modeled concentrations averaged over the 
nine grid cells \39\ centered at the location of the monitor.
---------------------------------------------------------------------------

    \39\ The modeling guidance recommends calculating annual 
PM2.5 RRFs using a 3 x 3 grid cell array (9 grid cells) 
for a model resolution of 12km.
---------------------------------------------------------------------------

    Step 3: For each quarter and each of the species, multiply the base 
year quarterly mean component concentration (Step 1) by the species-
specific RRF obtained in Step 2. This results in an estimated future 
year quarterly mean concentration for each species (e.g., 3 [mu]g/m\3\ 
sulfate multiplied by 0.8 equals a future sulfate concentration of 2.4 
[mu]g/m\3\).
    Step 4: The future year concentrations for the remaining species 
are then calculated.\40\ The future year ammonium is calculated based 
on the calculated future year sulfate and nitrate concentrations, using 
a constant value for the degree of neutralization of sulfate (from the 
ambient data). The future year particle bound water concentration is 
calculated from an empirical formula. The inputs to the formula are the 
future year concentrations of sulfate, nitrate, and ammonium (from step 
3).
---------------------------------------------------------------------------

    \40\ All of the calculations and assumptions are consistent with 
the default MATS settings (as described in the MATS user's guide and 
the photochemical modeling guidance). Additionally, we did not 
explicitly model salt and therefore the salt concentration was held 
constant from the base to future. Blank mass was assumed to be a 
constant mass of 0.5 [mu]g/m\3\ in both the base and future year.
---------------------------------------------------------------------------

    Step 5: Average the four quarterly mean future concentrations to 
obtain the future year annual design value concentration for each of 
the component species. Sum the species concentrations to obtain the 
future year annual average design value for PM2.5.
    Step 6: Calculate the maximum future design value by processing 
each of the three base design value periods (2003-2005, 2004-2006, and 
2005-2007) separately. The highest of the three future values is the 
maximum design value. The maximum design values are used to determine 
future year maintenance sites.
    The preceding procedures for determining future year 
PM2.5 concentrations were applied for each FRM site. The 
calculated annual PM2.5 design values are truncated (i.e., 
discarded) after the second decimal place.\41\ This is consistent with 
the truncation and rounding procedures for the annual PM2.5 
NAAQS. Any value that is greater than or equal to 15.05 [mu]g/m\3\ is 
rounded to 15.1 [mu]g/m\3\ and is considered to be violating the NAAQS. 
Thus, sites with future year annual PM2.5 design values of 
15.05 [mu]g/m\3\ or greater, based on the projection of 5-year weighted 
average concentrations, are predicted to be nonattainment sites. Sites 
with future year maximum design values of 15.05 [mu]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 as part of this proposal.
---------------------------------------------------------------------------

    \41\ For example, a calculated annual average concentration of 
14.94753 * * * becomes 14.94 when digits beyond two places to the 
right are truncated.
---------------------------------------------------------------------------

    Table IV.C-7 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 
IV.C-8 contains this same information for projected 2012 maintenance 
sites.

          Table IV.C-7--Average and Maximum 2003-2007 and 2012 Base Case Annual PM2.5 Design Values ([mu]g/m3) at Projected Nonattainment Sites
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                              Average         Maximum         Average         Maximum
              Monitor ID                         State                    County           design value    design value    design value    design value
                                                                                             2003-2007       2003-2007         2012            2012
--------------------------------------------------------------------------------------------------------------------------------------------------------
10730023.............................  Alabama.................  Jefferson..............           18.48           18.67           17.15           17.33
10732003.............................  Alabama.................  Jefferson..............           17.07           17.45           15.99           16.35
130210007............................  Georgia.................  Bibb...................           16.47           16.78           15.33           15.62
130630091............................  Georgia.................  Clayton................           16.47           16.71           15.07           15.29
131210039............................  Georgia.................  Fulton.................           17.43           17.47           16.01           16.04
170310052............................  Illinois................  Cook...................           15.75           16.02           15.16           15.43
171191007............................  Illinois................  Madison................           16.72           17.01           16.56           16.85
171630010............................  Illinois................  Saint Clair............           15.58           15.74           15.48           15.63
180190006............................  Indiana.................  Clark..................           16.40           16.60           15.96           16.16
180372001............................  Indiana.................  Dubois.................           15.18           15.68           15.07           15.57
180970078............................  Indiana.................  Marion.................           15.26           15.43           15.18           15.36

[[Page 45248]]


180970081............................  Indiana.................  Marion.................           16.05           16.36           15.93           16.25
180970083............................  Indiana.................  Marion.................           15.90           16.27           15.77           16.15
211110043............................  Kentucky................  Jefferson..............           15.53           15.75           15.19           15.41
261630015............................  Michigan................  Wayne..................           15.88           16.40           15.05           15.55
261630033............................  Michigan................  Wayne..................           17.50           18.16           16.57           17.19
390170016............................  Ohio....................  Butler.................           15.74           16.11           15.25           15.61
390350038............................  Ohio....................  Cuyahoga...............           17.37            18.1           16.26           16.95
390350045............................  Ohio....................  Cuyahoga...............           16.47           16.98           15.42           15.91
390350060............................  Ohio....................  Cuyahoga...............           17.11           17.66           16.02           16.55
390610014............................  Ohio....................  Hamilton...............           17.29           17.53           16.69           16.93
390610042............................  Ohio....................  Hamilton...............           16.85           17.25           16.33           16.71
390610043............................  Ohio....................  Hamilton...............           15.55           15.82           15.05           15.32
390617001............................  Ohio....................  Hamilton...............           16.17           16.56           15.65           16.03
390618001............................  Ohio....................  Hamilton...............           17.54           17.90           16.93           17.27
420030064............................  Pennsylvania............  Allegheny..............           20.31           20.75           18.90           19.31
420031301............................  Pennsylvania............  Allegheny..............           16.26           16.57           15.13           15.42
420070014............................  Pennsylvania............  Beaver.................           16.38           16.45           15.23           15.30
420710007............................  Pennsylvania............  Lancaster..............           16.55           17.46           15.19           16.01
421330008............................  Pennsylvania............  York...................           16.52           17.25           15.25           15.94
540110006............................  West Virginia...........  Cabell.................           16.30           16.57           15.25           15.50
540391005............................  West Virginia...........  Kanawha................           16.52           16.59           15.28           15.34
--------------------------------------------------------------------------------------------------------------------------------------------------------


         Table IV.C-8--Average and Maximum 2003-2007 and 2012 Base Case Annual PM2.5 Design Values ([mu]/m3) at Projected Maintenance-Only Sites
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                              Average         Maximum         Average         Maximum
              Monitor ID                         State                    County           design value    design value    design value    design value
                                                                                             2003-2007       2003-2007         2012            2012
--------------------------------------------------------------------------------------------------------------------------------------------------------
170313301............................  Illinois................  Cook...................           15.24           15.59           14.73           15.06
170316005............................  Illinois................  Cook...................           15.48           16.07           14.92           15.48
211110044............................  Kentucky................  Jefferson..............           15.31           15.47           14.93           15.09
360610056............................  New York................  New York...............           16.18           17.02           14.98           15.74
390350027............................  Ohio....................  Cuyahoga...............           15.46           16.13           14.50           15.13
390350065............................  Ohio....................  Cuyahoga...............           15.97           16.44           14.96           15.40
390610040............................  Ohio....................  Hamilton...............           15.50           15.88           15.03           15.40
390811001............................  Ohio....................  Jefferson..............           16.51           17.17           14.95           15.54
391130032............................  Ohio....................  Montgomery.............           15.54           15.92           15.01           15.37
391510017............................  Ohio....................  Stark..................           16.15           16.59           14.99           15.40
420110011............................  Pennsylvania............  Berks..................           15.82           16.19           14.77           15.11
482011035............................  Texas...................  Harris.................           15.42           15.84           14.74           15.14
540030003............................  West Virginia...........  Berkeley...............           15.93           16.19           14.95           15.20
540090005............................  West Virginia...........  Brooke.................           16.52           16.80           14.95           15.22
540291004............................  West Virginia...........  Hancock................           15.76           16.64           14.34           15.15
540490006............................  West Virginia...........  Marion.................           15.03           15.25           14.96           15.18
--------------------------------------------------------------------------------------------------------------------------------------------------------

(2) Methodology for Projecting Future 24-Hour PM2.5 
Nonattainment and Maintenance
    The following is a brief summary of the procedures used for 
calculating future year 24-hour PM2.5 design values. 
Additional details are provided in the modeling guidance, MATS 
documentation, and the AQMTSD. Similar to the annual PM2.5 
calculations, we are using the 2003-2007 base period FRM data for 
projecting future year design values. The 24-hour PM2.5 
calculations are computationally similar to the annual average 
calculations. The main difference is that the base period 24-hour 98th 
percentile PM2.5 concentrations are projected to the future 
year, instead of the annual average concentrations. Also, the 
PM2.5 species fractions and relative response factors are 
calculated from observed and modeled high concentration days, instead 
of quarterly average data.
    Both the annual PM2.5 and 24-hour PM2.5 
calculations are performed on a calendar quarter basis. Since all years 
and quarters are averaged together in the annual PM2.5 
calculations, the individual years can be averaged together early in 
the calculations. However, in the 24-hour PM2.5 
calculations, only the high quarter from each year is used in the final 
calculations. This represents the 98th percentile value, which can come 
from any of the 4 quarters in any year. Therefore all quarters and 
years must be carried through to near the end of the calculations when 
the individual future year high quarter values are selected. To 
calculate final future year design values, the high quarter for each 
year is identified and then a five year weighted average of the high 
quarters for each site was calculated to derive the future year design 
value.
    The following are the steps followed for calculating the 2012 base 
case 24-hour PM2.5 design values:
    Step 1: At each FRM monitoring site, we identify the maximum 24-
hour PM2.5 concentration in each quarter that is less

[[Page 45249]]

than or equal to the 98th percentile value over the entire year. This 
results in a data set for each year (for up to 5 years) for each site 
containing one quarter with the observed 98th percentile value and 
three quarters with the maximum highest values from each quarter that 
are less than or equal to the 98th percentile value for the year. All 
20 quarters (i.e., 4 quarters in each of 5 years) of data are carried 
through the calculations until the high future year quarter value is 
identified in step 6.
    Step 2: In this step we calculate quarterly ambient concentrations 
on ``high'' \42\ days for each of the major component species of 
PM2.5 (sulfate, nitrate, ammonium, elemental carbon, organic 
carbon mass, particle bound water, salt, and blank mass). This 
calculation is performed by multiplying the monitored concentrations of 
FRM-derived total PM2.5 mass on the 10 percent highest days 
from each quarter, by the monitored fractional composition of 
PM2.5 species on the 10 percent highest PM2.5 
days for each quarter, averaged over 3 years \43\ (e.g., 20 percent 
sulfate fraction multiplied by 40 [mu]g/m\3\ PM2.5 equals 8 
[mu]g/m\3\ sulfate).
---------------------------------------------------------------------------

    \42\ High ambient data and model days were defined as the top 10 
percent days in each quarter based on 24-hour concentrations of 
PM2.5.
    \43\ For this analysis, species fractions were calculated using 
an average of FRM and speciation data for the 2004-2006 time period. 
This was deemed to be representative of the 2005 modeling year.
---------------------------------------------------------------------------

    Step 3: For each quarter, we calculate the ratio of future year 
(i.e., 2012) to base year (i.e., 2005) predictions for each component 
species for the top 10 percent of days based on predicted 
concentrations of 24-hour PM2.5. The result is a set of 
species-specific relative response factors (RRF) for the high 
PM2.5 days in each quarter (e.g., assume that the 2005 
predicted sulfate concentration on the 10 percent highest 
PM2.5 days for a quarter for a particular location is 20 
[mu]g/m\3\ and the 2012 base case concentration is 16 [mu]g/m\3\, then 
RRF for sulfate is 0.8). The RRFs are calculated based on the modeled 
concentrations at the single grid cell where the monitor is located.
    Step 4: For each quarter, we multiply the quarterly species 
concentration (step 2) by the quarterly \44\ species-specific RRF 
obtained in step 3. This leads to an estimated future quarterly 
concentration for each component. (e.g., 21.0 [mu]g/m\3\ nitrate x 0.75 
= future nitrate of 15.75 [mu]g/m\3\).
---------------------------------------------------------------------------

    \44\ Since there is only one modeled base year, there are a 
single set of four quarterly RRFs. The modeled quarterly RRF for 
quarter 1 is multiplied by the ambient data for quarter 1 for each 
of the 5 years of ambient data. The same procedure is applied for 
the other 3 quarters.
---------------------------------------------------------------------------

    Step 5: The future year concentrations for the remaining species 
are then calculated.\45\ The future year ammonium is calculated based 
on the calculated future year sulfate and nitrate concentrations, using 
a constant value for the degree of neutralization of sulfate (from the 
ambient data). The future year particle bound water concentration is 
calculated from an empirical formula. The inputs to the formula are the 
calculated future year concentrations of sulfate, nitrate, and ammonium 
(from step 4).
---------------------------------------------------------------------------

    \45\ All of the calculations and assumptions are consistent with 
the default MATS settings (as described in the MATS user's guide and 
the photochemical modeling guidance). Additionally, we did not 
explicitly model salt and therefore the salt concentration was held 
constant from the base to future. Blank mass was assumed to be a 
constant mass of 0.5 ug/m\3\ in both the base and future year.
---------------------------------------------------------------------------

    Step 6: We sum the species concentrations to obtain quarterly 
PM2.5 values. This step is repeated for each quarter and for 
each of the 5 years of ambient data. The highest daily value (from the 
4 quarterly values) for each year at each monitor is considered to be 
the estimated future year 98th percentile 24-hour design value for that 
year.
    Step 7: The estimated 98th percentile values for each of the 5 
years are averaged over 3 year intervals to create the 3 year average 
design values. These design values are averaged to create a 5 year 
weighted average for each monitoring site.
    Step 8: The maximum future design value is calculated by following 
the previous steps for each of the three base design value 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 24-hour PM2.5 maintenance receptors.
    The preceding procedures for determining future year 24-hour 
PM2.5 concentrations were applied for each FRM site. The 24-
hour PM2.5 design values are truncated after the first 
decimal place. This approach is consistent with the truncation and 
rounding procedures for the 24-hour PM2.5 NAAQS. Any value 
that is greater than or equal to 35.5 [mu]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 [mu]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. 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 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 proposal.
    Table IV.C-9 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 IV.C-10 contains 
this same information for projected 2012 24-hour maintenance sites.

        Table IV.C-9--Average and Maximum 2003-2007 and 2012 Base Case 24-Hour PM2.5 Design Values ([mu]g/m\3\) at Projected Nonattainment Sites
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                          Average design  Maximum design
              Monitor ID                         State                    County            value 2003-     value 2003-   Average design  Maximum design
                                                                                               2007            2007         value 2012      value 2012
--------------------------------------------------------------------------------------------------------------------------------------------------------
10730023.............................  Alabama.................  Jefferson..............            44.0            44.2            40.0            40.7
10732003.............................  Alabama.................  Jefferson..............            40.3            40.8            38.1            38.9
90091123.............................  Connecticut.............  New Haven..............            38.3            40.3            35.7            36.6
170310052............................  Illinois................  Cook...................            40.2            41.4            38.5            39.7

[[Page 45250]]


170310057............................  Illinois................  Cook...................            37.3            38.6            35.7            37.0
170310076............................  Illinois................  Cook...................            38.0            39.1            36.3            37.3
170311016............................  Illinois................  Cook...................            43.0            46.3            41.0            44.1
170312001............................  Illinois................  Cook...................            37.7            40.6            35.6            38.2
170313103............................  Illinois................  Cook...................            39.6            40.3            38.1            38.7
170313301............................  Illinois................  Cook...................            40.2            43.3            38.2            41.0
170316005............................  Illinois................  Cook...................            39.1            41.8            37.4            39.8
171190023............................  Illinois................  Madison................            37.3            38.1            39.4            40.2
171191007............................  Illinois................  Madison................            39.1            40.1            40.0            40.6
171192009............................  Illinois................  Madison................            34.9            35.9            37.2            38.2
171193007............................  Illinois................  Madison................            34.0            34.6            36.5            37.3
180190006............................  Indiana.................  Clark..................            37.5            39.4            38.1            40.2
180372001............................  Indiana.................  Dubois.................            35.3            36.9            36.5            38.0
180830004............................  Indiana.................  Knox...................            35.9            36.3            35.9            36.5
180890022............................  Indiana.................  Lake...................            38.9            44.0            37.3            42.1
180890026............................  Indiana.................  Lake...................            38.4            41.3            36.3            39.3
180970042............................  Indiana.................  Marion.................            34.2            35.3            36.3            37.2
180970043............................  Indiana.................  Marion.................            38.4            39.9            40.5            42.0
180970066............................  Indiana.................  Marion.................            38.3            39.6            40.3            41.8
180970078............................  Indiana.................  Marion.................            36.6            37.6            38.7            39.7
180970079............................  Indiana.................  Marion.................            35.6            36.7            37.2            38.3
180970081............................  Indiana.................  Marion.................            38.2            39.2            40.1            41.1
180970083............................  Indiana.................  Marion.................            36.6            37.0            39.0            39.3
181570008............................  Indiana.................  Tippecanoe.............            35.6            36.7            35.9            36.9
191630019............................  Iowa....................  Scott..................            37.1            37.1            36.8            36.8
210590005............................  Kentucky................  Daviess................            33.8            33.8            37.0            37.0
211110043............................  Kentucky................  Jefferson..............            35.4            36.1            35.8            36.4
211110044............................  Kentucky................  Jefferson..............            36.1            36.6            36.0            36.5
211110048............................  Kentucky................  Jefferson..............            36.4            37.2            35.6            36.4
245100040............................  Maryland................  Baltimore City.........            39.0            40.9            36.3            38.3
245100049............................  Maryland................  Baltimore City.........            38.1            38.1            35.5            35.5
261150005............................  Michigan................  Monroe.................            38.8            39.6            37.0            38.0
261250001............................  Michigan................  Oakland................            39.9            40.4            37.9            38.4
261470005............................  Michigan................  St. Clair..............            39.6            40.6            38.4            39.4
261610008............................  Michigan................  Washtenaw..............            39.4            40.8            38.1            39.8
261630015............................  Michigan................  Wayne..................            40.1            40.6            38.5            39.1
261630016............................  Michigan................  Wayne..................            42.9            45.4            40.6            43.0
261630019............................  Michigan................  Wayne..................            40.9            41.4            38.6            39.1
261630033............................  Michigan................  Wayne..................            43.8            44.2            42.1            42.6
261630036............................  Michigan................  Wayne..................            37.1            37.9            36.3            36.9
290990012............................  Missouri................  Jefferson..............            33.4            34.2            35.7            36.5
291831002............................  Missouri................  Saint Charles..........            33.1            34.7            35.5            37.1
295100007............................  Missouri................  St. Louis City.........            33.1            33.5            36.0            36.3
295100087............................  Missouri................  St. Louis City.........            34.3            34.7            36.4            36.9
340171003............................  New Jersey..............  Hudson.................            39.0            40.5            35.7            36.1
340172002............................  New Jersey..............  Hudson.................            41.4            41.4            38.2            38.2
340390004............................  New Jersey..............  Union..................            40.4            41.4            36.7            37.2
360050080............................  New York................  Bronx..................            38.8            40.2            35.9            36.2
360610056............................  New York................  New York...............            39.7            40.6            37.1            38.0
360610128............................  New York................  New York...............            39.4            41.8            36.2            38.0
390170003............................  Ohio....................  Butler.................            39.2            41.1            40.3            42.3
390170016............................  Ohio....................  Butler.................            37.1            37.7            37.5            37.8
390170017............................  Ohio....................  Butler.................            37.9            37.9            38.5            38.5
390171004............................  Ohio....................  Butler.................            37.1            38.1            37.8            38.6
390350038............................  Ohio....................  Cuyahoga...............            44.2            47.0            41.2            44.0
390350045............................  Ohio....................  Cuyahoga...............            38.5            41.5            36.0            39.0
390350060............................  Ohio....................  Cuyahoga...............            42.1            45.7            39.4            42.8
390350065............................  Ohio....................  Cuyahoga...............            38.6            41.0            36.5            38.9
390490024............................  Ohio....................  Franklin...............            38.5            39.7            36.6            37.6
390490025............................  Ohio....................  Franklin...............            38.4            39.1            36.1            36.4
390610006............................  Ohio....................  Hamilton...............            37.6            37.6            38.0            38.0
390610014............................  Ohio....................  Hamilton...............            38.2            39.4            37.5            38.5
390610040............................  Ohio....................  Hamilton...............            36.7            37.7            35.8            36.8
390610042............................  Ohio....................  Hamilton...............            37.3            38.2            37.2            38.0
390610043............................  Ohio....................  Hamilton...............            35.9            36.2            36.0            36.4
390617001............................  Ohio....................  Hamilton...............            38.8            39.6            37.7            38.1
390618001............................  Ohio....................  Hamilton...............            40.6            40.9            39.6            40.3
390811001............................  Ohio....................  Jefferson..............            41.9            45.5            36.5            39.9
391130032............................  Ohio....................  Montgomery.............            37.8            40.0            36.3            38.5

[[Page 45251]]


391530017............................  Ohio....................  Summit.................            38.0            39.6            35.6            37.2
420030008............................  Pennsylvania............  Allegheny..............            39.4            39.9            35.9            36.3
420030064............................  Pennsylvania............  Allegheny..............            64.2            68.2            58.8            62.3
420030093............................  Pennsylvania............  Allegheny..............            45.6            51.5            41.1            46.2
420030116............................  Pennsylvania............  Allegheny..............            42.5            42.5            37.1            37.1
420031008............................  Pennsylvania............  Allegheny..............            41.3            42.8            38.0            39.3
420031301............................  Pennsylvania............  Allegheny..............            40.3            42.4            36.6            38.6
420070014............................  Pennsylvania............  Beaver.................            43.4            44.6            37.7            39.1
420110011............................  Pennsylvania............  Berks..................            37.7            39.1            35.8            37.0
420210011............................  Pennsylvania............  Cambria................            39.0            39.4            40.3            40.7
420430401............................  Pennsylvania............  Dauphin................            38.0            39.0            35.7            37.1
420710007............................  Pennsylvania............  Lancaster..............            40.8            44.0            37.7            40.1
421330008............................  Pennsylvania............  York...................            38.2            40.7            35.9            38.8
471251009............................  Tennessee...............  Montgomery.............            36.3            37.5            36.6            37.9
540090011............................  West Virginia...........  Brooke.................            43.9            44.9            39.9            40.8
550790010............................  Wisconsin...............  Milwaukee..............            38.6            40.0            37.7            39.0
550790026............................  Wisconsin...............  Milwaukee..............            37.3            41.3            36.3            40.1
550790043............................  Wisconsin...............  Milwaukee..............            39.9            40.8            38.8            39.7
550790099............................  Wisconsin...............  Milwaukee..............            37.7            38.7            36.8            37.7
--------------------------------------------------------------------------------------------------------------------------------------------------------


      Table IV.C-10--Average and Maximum 2003-2007 and 2012 Base Case 24-Hour PM2.5 Design Values ([mu]g/m\3\) at Projected Maintenance-Only Sites
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                              Average         Maximum         Average         Maximum
              Monitor ID                         State                    County           design value    design value    design value    design value
                                                                                             2003-2007       2003-2007         2012            2012
--------------------------------------------------------------------------------------------------------------------------------------------------------
110010041............................  Washington DC...........  Washington DC..........            36.3            37.8            34.0            35.6
110010042............................  Washington DC...........  Washington DC..........            34.9            37.0            33.0            35.6
170310022............................  Illinois................  Cook...................            36.6            38.6            34.9            36.6
170310050............................  Illinois................  Cook...................            36.1            38.0            34.1            35.8
170314007............................  Illinois................  Cook...................            34.3            36.4            33.6            35.7
171630010............................  Illinois................  Saint Clair............            33.7            34.1            35.3            35.9
171971002............................  Illinois................  Will...................            36.4            37.1            35.1            35.8
180390003............................  Indiana.................  Elkhart................            34.4            36.3            33.8            35.6
180431004............................  Indiana.................  Floyd..................            33.2            34.5            34.3            35.7
181670023............................  Indiana.................  Vigo...................            34.8            36.1            35.1            36.5
191390015............................  Iowa....................  Muscatine..............            36.0            37.7            34.5            36.0
210290006............................  Kentucky................  Bullitt................            34.6            35.8            35.0            36.3
211451004............................  Kentucky................  McCracken..............            33.6            35.9            34.4            36.8
212270007............................  Kentucky................  Warren.................            33.1            35.1            33.7            36.3
240031003............................  Maryland................  Anne Arundel...........            35.5            37.4            33.8            36.7
245100035............................  Maryland................  Baltimore (City).......            37.7            39.2            34.7            35.5
261630001............................  Michigan................  Wayne..................            37.8            40.1            35.4            37.8
295100085............................  Missouri................  St. Louis City.........            33.2            33.8            35.3            35.7
360610062............................  New York................  New York...............            38.8            41.6            35.3            37.0
360610079............................  New York................  New York...............            37.9            40.2            34.2            36.4
390350027............................  Ohio....................  Cuyahoga...............            36.6            38.8            34.5            36.6
390350034............................  Ohio....................  Cuyahoga...............            36.5            37.9            33.7            35.7
390810017............................  Ohio....................  Jefferson..............            40.7            42.4            35.3            36.8
390950024............................  Ohio....................  Lucas..................            36.3            38.6            34.2            36.5
390950026............................  Ohio....................  Lucas..................            34.9            36.7            33.6            35.6
390990014............................  Ohio....................  Mahoning...............            36.8            38.2            34.2            35.8
391130031............................  Ohio....................  Montgomery.............            35.7            37.1            34.3            35.6
391351001............................  Ohio....................  Preble.................            32.8            33.9            34.3            35.5
391550007............................  Ohio....................  Trumbull...............            36.2            37.8            33.9            35.6
420030095............................  Pennsylvania............  Allegheny..............            38.7            40.7            34.3            36.6
420033007............................  Pennsylvania............  Allegheny..............            37.5            43.1            33.8            38.5
420410101............................  Pennsylvania............  Cumberland.............            38.0            40.2            35.3            37.0
421255001............................  Pennsylvania............  Washington.............            38.1            39.9            33.9            35.5
471650007............................  Tennessee...............  Sumner.................            33.6            34.5            35.1            36.0
540090005............................  West Virginia...........  Brooke.................            39.4            41.5            33.9            36.1
550250047............................  Wisconsin...............  Dane...................            35.5            36.9            35.1            36.1
550790059............................  Wisconsin...............  Milwaukee..............            35.5            37.0            34.8            36.3
551330027............................  Wisconsin...............  Waukesha...............            35.4            36.2            34.9            35.6
--------------------------------------------------------------------------------------------------------------------------------------------------------


[[Page 45252]]

(3) Methodology for Projecting Future 8-Hour Ozone Nonattainment and 
Maintenance
    The following is a brief summary of the future year 8-hour average 
ozone calculations. Additional details are provided in the modeling 
guidance, MATS documentation, and the AQMTSD.
    We are using the base period 2003-2007 ambient ozone design value 
data for projecting future year design values. The ozone projection 
procedure is relatively simple, since ozone is a single species. It is 
not necessary to interpolate ambient ozone data, since ambient ozone 
design values and gridded, modeled ozone is all that is needed for the 
projections.
    To project 8-hour ozone design values we used the 2005 base year 
and 2012 future base case model-predicted ozone concentrations to 
calculate relative response factors. The methodology we followed is 
consistent with the attainment demonstration modeling guidance. The 
RRFs were applied to the 2003-2007 ozone design values through the 
following steps:
    Step 1: For each monitoring site we calculate the average 
concentration across all days with 8-hour daily maximum predictions 
greater than or equal to 85 ppb \46\ using the predictions in the nine 
grid cells that include or surround the location of the monitoring 
site. The RRF for a site is the ratio of the mean prediction in the 
future year to the mean prediction in the 2005 base year. The RRFs were 
calculated on a site-by-site basis.
---------------------------------------------------------------------------

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

    Step 2: The RRF for each site is then multiplied by the 2003-2007 
5-year weighted average ambient design value for that site, yielding an 
estimate of the future year design value at that particular monitoring 
location.
    Step 3: We calculate the maximum future design value 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 preceding procedures for determining future year 8-hour average 
ozone design values were applied for each ozone monitoring site. The 
future year design values are truncated to integers in units of ppb. 
This approach is consistent with the 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. 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 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 as part of this proposal.
    Table IV.C-11 contains the 2003-2007 base period average and 
maximum 8[dash]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 IV.C-12 contains this same 
information for projected 2012 8-hour ozone maintenance sites.

            Table IV.C-11--Average and Maximum 2003-2007 and 2012 Base Case 8-Hour Ozone Design Values (ppb) at Projected Nonattainment Sites
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                        Average  design      Maximum         Average
             Monitor ID                        State                    County            value  2003-    design value    design value   Maximum  design
                                                                                              2007          2003-2007         2012         value  2012
--------------------------------------------------------------------------------------------------------------------------------------------------------
220330003...........................  Louisiana..............  East Baton Rouge.......             92                96            87.8             91.6
361030002...........................  New York...............  Suffolk................             90                91            86.3             87.2
361030009...........................  New York...............  Suffolk................             90.3              91            85.1             85.8
421010024...........................  Pennsylvania...........  Philadelphia...........             90.3              91            85.3             86
480391004...........................  Texas..................  Brazoria...............             94.7              97            88.8             91
482010051...........................  Texas..................  Harris.................             93                98            88.4             93.1
482010055...........................  Texas..................  Harris.................            100.7             103            95.7             97.9
482010062...........................  Texas..................  Harris.................             95.7              99            90.5             93.7
482010066...........................  Texas..................  Harris.................             92.3              96            89.9             93.5
482011039...........................  Texas..................  Harris.................             96.3             100            90.5             93.9
484391002...........................  Texas..................  Tarrant................             93.3              95            85.1             86.7
--------------------------------------------------------------------------------------------------------------------------------------------------------


          Table IV.C-12--Average and Maximum 2003-2007 and 2012 Base Case 8-Hour Ozone Design Values (ppb) at Projected Maintenance-Only Sites
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                       Average  design      Maximum
             Monitor ID                        State                   County            value  2003-    design  value  Average  design  Maximum  design
                                                                                             2007          2003-2007       value  2012      value  2012
--------------------------------------------------------------------------------------------------------------------------------------------------------
90010017............................  Connecticut............  Fairfield.............             88                90             83.1             85
90011123............................  Connecticut............  Fairfield.............             92.3              94             84.8             86.4
90013007............................  Connecticut............  Fairfield.............             90                92             84.5             86.4

[[Page 45253]]


90093002............................  Connecticut............  New Haven.............             90.3              93             82.9             85.4
130890002...........................  Georgia................  DeKalb................             88.7              93             81.6             85.6
131210055...........................  Georgia................  Fulton................             91.7              94             84.4             86.5
361192004...........................  New York...............  Westchester...........             87.7              90             84.7             86.9
420170012...........................  Pennsylvania...........  Bucks.................             88                92             81.8             85.6
481130069...........................  Texas..................  Dallas................             87                90             82.9             85.8
481130087...........................  Texas..................  Dallas................             87                88             84.6             85.6
482010024...........................  Texas..................  Harris................             88                92             83.3             87.1
482010029...........................  Texas..................  Harris................             91.7              93             84.4             85.6
482011015...........................  Texas..................  Harris................             89                96             83.7             90.3
482011035...........................  Texas..................  Harris................             86.3              95             82               90.3
482011050...........................  Texas..................  Harris................             89.3              92             83.9             86.5
484392003...........................  Texas..................  Tarrant...............             93.7              95             84               85.2
--------------------------------------------------------------------------------------------------------------------------------------------------------

3. How did EPA assess interstate contributions to nonattainment and 
maintenance?
    This section documents the procedures used by EPA to quantify the 
impact of emissions in specific upwind states on air quality 
concentrations in projected downwind nonattainment and maintenance 
locations for annual PM2.5, 24-hour PM2.5, and 8-
hour ozone. These procedures are the first of the two-step approach for 
determining significant contribution, as described previously in 
section IV.A.3.
    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. Details of the modeling techniques 
and post-processing procedures are described in this section.
    CAMx employs enhanced source apportionment techniques which track 
the formation and transport of ozone and particulate matter from 
specific emissions sources and calculates the contribution of sources 
and precursors to ozone and PM2.5 for individual receptor 
locations. The strength of the photochemical model source apportionment 
technique is that all modeled ozone and/or PM2.5 mass at a 
given receptor location in the modeling domain is tracked back to 
specific sources of emissions and boundary conditions to fully 
characterize culpable sources. This type of emissions apportionment is 
useful to understand the types of sources or regions that are 
contributing to ozone and PM2.5 estimated by the model.
    Source apportionment is an alternative approach to zero-out 
modeling \47\ and other methods to track pollutant formation in 
photochemical models. Source apportionment completely characterizes 
source contributions to model-estimated ozone and PM2.5, 
which is not possible with an emissions sensitivity approach such as 
zero-out, since the change in emissions leads to changes in pollutant 
concentrations, meaning the sum of estimated ozone or PM2.5 
in all zero-out simulations may not exactly match the ozone or 
PM2.5 estimated in the base model simulation. Photochemical 
model source apportionment has the additional advantage over emissions 
sensitivity-based approaches of being more computationally efficient. 
There is currently no technical evidence showing that one technique is 
clearly superior to the other for evaluating contributions to ozone and 
PM2.5 from various emission sources. However, since source 
apportionment explicitly tracks the formation and transport of all 
ozone and PM2.5 mass, it is particularly well suited for 
quantifying interstate contributions as part of this proposal. More 
details on the implementation of photochemical source apportionment in 
CAMx can be found in the CAMx user's guide. In the analysis performed 
for CAIR, EPA conducted zero-out modeling for PM2.5, and 
both zero-out and source apportionment modeling for ozone. The CAIR 
modeling was conducted at 36 km resolution for PM2.5 and 12 
km resolution for ozone. In contrast, the analysis for the Transport 
Rule was performed at 12 km resolution for both ozone and 
PM2.5. When choosing the modeling techniques to use for the 
Transport Rule, we carefully considered all of the pros and cons of 
each technique, including the lengthy model run times and large file 
sizes of the 12 km eastern U.S. modeling domain. Due to the scientific 
credibility of the source apportionment technique and significant time 
and resource savings compared to zero-out modeling, we chose to perform 
the modeled contribution analyses for PM2.5 and ozone with 
photochemical source apportionment.
---------------------------------------------------------------------------

    \47\ Zero-out modeling is a technique in which all emissions are 
removed (e.g., NOX and VOC emissions from a particular 
state) in a model run and then compared to the results of a second 
model run in which the same emissions have not been removed. The 
difference between the two model runs represents sensitivity or 
contribution from the emissions that were removed.
---------------------------------------------------------------------------

    The EPA performed source apportionment modeling for both ozone and 
PM2.5 for the 2012 base case emissions. In this modeling we 
tracked the ozone and PM2.5 formed from emissions from 
sources in each upwind state in the 12 km modeling domain. The results 
were used to calculate the contributions of these upwind emissions to 
downwind nonattainment and maintenance receptors. The states EPA 
analyzed using source apportionment for ozone and for PM2.5 
are: Alabama, Arkansas, Connecticut, Delaware, Florida, Georgia, 
Illinois, Indiana, Iowa, Kansas, Kentucky, Louisiana, Maine, Maryland, 
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, Washington 
DC, and Wisconsin. 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

[[Page 45254]]

or assess the contribution from emissions in these states.
    In contrast to CAIR, all contributions to downwind nonattainment 
and maintenance receptors for the Transport Rule were calculated using 
a relative approach. This is similar to the approach used to calculate 
future year design values, as described in section IV.C.2.a. In CAIR we 
used absolute and relative metrics to examine air quality 
contributions. Although absolute contributions are useful for certain 
applications, there are advantages of examining the relative 
contributions for both ozone and PM2.5. The main advantage 
of relative contributions is that they help to minimize biases 
introduced by model over-predictions and under-predictions. Also, the 
relative approach constrains the total contributions to the 
measurements of ozone and PM2.5 species concentrations at 
each downwind receptor. Since model performance is variable across the 
domain, EPA judged the relative approach to be the most appropriate 
technique for the Transport Rule.
a. Annual and 24-Hour PM2.5 Contribution Modeling Approach
    EPA used the CAMx Particulate Source Apportionment Technique (PSAT) 
to calculate downwind PM2.5 contributions to nonattainment 
and maintenance. The CAMx PSAT is capable of ``tagging'' (i.e., 
tracking) source category emissions for certain PM species and 
precursor emissions. For this proposal, we ran PSAT to tag emissions of 
NOX, SO2, and primary PM2.5 from the 
individual states listed previously. Due to small modeled 
concentrations of secondary organic aerosols (SOA), and the relatively 
large runtime penalty of the SOA PSAT mechanism, we chose not to track 
SOA. Through emissions pre-processing procedures, EPA tagged all of the 
anthropogenic NOX, SO2, and primary 
PM2.5 emissions in each upwind state. Each state was a 
separate tag, and the tagged emissions followed state boundaries (not 
grid cells).
    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 IV.B., 
the nitrate and sulfate contributions were combined and used to 
evaluate interstate contributions of PM2.5, as described in 
section IV.C.4, later.
    We developed and applied several post-processing steps to transform 
the PSAT modeling outputs to PM2.5 downwind contributions. 
The approach involved processing the PSAT model outputs using MATS 
along with other post-processing software to calculate the contribution 
of each upwind state to each downwind nonattainment and/or maintenance 
receptor. This process involved calculating a ratio which uses the 
PSAT-predicted absolute contribution for each species (e.g., sulfate) 
coupled with the CAMx-predicted absolute 2012 base case concentration 
of the same species. The PSAT-derived ratios were then multiplied by 
the corresponding species component concentrations comprising the 2012 
base case PM2.5 design value. For calculating annual 
contributions, we included the PSAT data for each day of the modeled 
year. For 24-hour calculations, the contributions are based on the 10 
percent highest of the days in each quarter, as predicted for each 
receptor in the 2012 base case. In the 24-hour calculations, only the 
upwind contribution to the highest quarter at each receptor was used 
(i.e., highest quarter based on 2012 PM2.5 mass). For both 
annual and 24-hour PM2.5, the total PM2.5 mass 
contribution was calculated by summing the contributions of sulfate, 
nitrate, ammonium, and particle bound water. \48\ Details on the 
procedures for calculating the contribution metrics are provided in the 
AQMTSD.
---------------------------------------------------------------------------

    \48\ The water and ammonium contributions are calculated by MATS 
using the default assumptions that were used to calculate future 
year 2012 PM2.5 concentrations. The ammonium contribution 
is calculated assuming that all particulate nitrate is in the form 
of ammonium nitrate and the ammonium associated with sulfate is 
based on the degree of neutralization of the base year ambient data. 
In this way, the ammonium contribution is attributed to sulfate and 
nitrate precursors, not ammonia emissions. The water concentration 
is calculated based on an empirical formula that uses sulfate, 
nitrate, and ammonium concentrations.
---------------------------------------------------------------------------

b. 8-Hour Ozone Contribution Modeling Approach
    EPA used the CAMX Ozone Source Apportionment Technique 
(OSAT) in order to calculate downwind 8-hour ozone contributions to 
nonattainment and maintenance. OSAT tracks the formation of ozone from 
NOX and VOC emissions. Through emissions pre-processing 
procedures, EPA tagged all of the NOX and VOC emissions in 
each upwind state. A separate tag was created for each state, and the 
tagged emissions followed state boundaries (not grid cells).
    All anthropogenic sources of NOX and VOC were tracked in 
the OSAT simulation. Upwind NOX and VOC emissions were 
tracked to downwind ozone concentrations. There are several post-
processing steps needed to transform the raw model outputs to ozone 
downwind contributions. We developed and applied several post-
processing steps to transform the OSAT modeling outputs to ozone 
contributions at downwind receptors. The approach for ozone was similar 
to the approach for PM2.5 in that the OSAT model outputs 
were processed using MATS along with other post-processing software to 
calculate the contribution of each upwind state to each downwind 
nonattainment and/or maintenance receptor. This process involved 
calculating a ratio which uses the OSAT-predicted absolute contribution 
of ozone coupled with the CAMx-predicted absolute 2012 base case ozone 
concentration. The OSAT-derived ratios were then multiplied by the 
corresponding 2012 base case ozone design value. The contributions to 
each downwind receptor are averaged across all days with modeled 2012 
base case concentrations greater than 85 ppb \49\ (at the given 
receptor). Details on the procedures for calculating the contribution 
metrics are provided in the AQMTSD.
---------------------------------------------------------------------------

    \49\ Ozone contributions are averaged over a minimum of 5 days. 
If there are fewer than 5 days greater than 85 ppb at a receptor, 
then the 85 ppb criterion is lowered in 1 ppb increments until there 
are 5 days of data for use in the calculations. If there are fewer 
than 5 modeled days greater than 70 ppb at the receptor, then the 
receptor is not used in the contribution calculations.
---------------------------------------------------------------------------

c. Use of Projected Nonattainment and Maintenance Contributions
    The previous steps provide the details for calculating 8-hour ozone 
and annual and 24-hour PM2.5 contributions to all downwind 
receptors. After the post-processing of the model results is complete, 
we then evaluate the contributions of each upwind state to 
nonattainment and maintenance receptors. The nonattainment receptors 
are those monitoring sites which are projected to exceed the NAAQS in 
the 2012 base case, based on 5-year weighted average design values. The 
maintenance receptors are those monitoring sites which are projected to 
exceed the NAAQS in the 2012 base case based on the highest design 
value period. The upwind ozone and PM2.5 contributions from 
each state are calculated for each downwind receptor. Contributions to 
nonattainment and maintenance receptors are evaluated independently for 
each state to determine if they are above the 1 percent threshold 
criteria.
    For each upwind state, the maximum contribution to nonattainment is 
calculated based on the single largest

[[Page 45255]]

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.
4. What are the estimated interstate contributions to annual 
PM2.5, 24-Hour PM2.5, and 8-Hour ozone 
nonattainment and maintenance?
a. Contributions to Annual and 24-Hour PM2.5 Nonattainment 
and Maintenance
    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. We also present the 
interstate contributions from emissions in upwind states to downwind 
nonattainment and maintenance sites for the 24-hour PM2.5 
NAAQS. As described previously in section IV.B., 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 to downwind attainment and maintenance sites 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 attainment and 
maintenance sites large enough to warrant further analysis. As 
described previously in section IV.C.3, we performed air quality 
modeling to quantify the contributions to annual and 24-hour 
PM2.5 from emissions in each of the following 37 states 
individually: Alabama, Arkansas, Connecticut, Delaware, Florida, 
Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky, Louisiana, Maine, 
Maryland combined with the District of Columbia, Massachusetts, 
Michigan, Minnesota, Mississippi, Missouri, Nebraska, New Hampshire, 
New Jersey, New York, North Carolina, North Dakota, Ohio, Oklahoma, 
Pennsylvania, Rhode Island, South Carolina, South Dakota, Tennessee, 
Texas, Vermont, Virginia, West Virginia, and Wisconsin.
    For annual PM2.5, we calculated each state's 
contribution to each of the 32 monitoring sites that are projected to 
be nonattainment and each of the 16 sites that are projected to have 
maintenance problems for the annual PM2.5 NAAQS in the 2012 
base case. The largest contribution from each state to annual 
PM2.5 nonattainment in downwind sites is provided in Table 
IV.C-13. The largest contribution from each state to annual 
PM2.5 maintenance in downwind sites is also provided in 
Table IV.C-13. The contributions from each state to all projected 2012 
nonattainment and maintenance sites for the annual PM2.5 
NAAQS are provided in the AQMTSD.

  Table IV.C-13--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 ([mu]g/ annual PM2.5 ([mu]g/
                                       m\3\)                m\3\)
------------------------------------------------------------------------
Alabama.......................                0.46                 0.18
Arkansas......................                0.09                 0.04
Connecticut...................                0.04                 0.09
Delaware......................                0.20                 0.14
Florida.......................                0.29                 0.07
Georgia.......................                0.63                 0.18
Illinois......................                1.01                 0.63
Indiana.......................                2.09                 1.78
Iowa..........................                0.31                 0.30
Kansas........................                0.09                 0.05
Kentucky......................                1.68                 1.01
Louisiana.....................                0.11                 0.34
Maine.........................                0.01                 0.02
Maryland/Washington, D.C......                0.63                 0.56
Massachusetts.................                0.07                 0.13
Michigan......................                0.72                 0.71
Minnesota.....................                0.19                 0.17
Mississippi...................                0.07                 0.03
Missouri......................                1.38                 0.27
Nebraska......................                0.08                 0.06
New Hampshire.................                0.01                 0.02
New Jersey....................                0.34                 0.68
New York......................                0.49                 0.47
North Carolina................                0.19                 0.11
North Dakota..................                0.05                 0.05
Ohio..........................                1.49                 2.03
Oklahoma......................                0.08                 0.05
Pennsylvania..................                0.83                 1.60
Rhode Island..................                0.01                 0.01
South Carolina................                0.26                 0.04
South Dakota..................                0.02                 0.02
Tennessee.....................                0.68                 0.64
Texas.........................                0.13                 0.06
Vermont.......................                0.00                 0.00
Virginia......................                0.36                 0.37

[[Page 45256]]


West Virginia.................                0.98                 1.17
Wisconsin.....................                0.46                 0.42
------------------------------------------------------------------------

    Based on the state-by-state contribution analysis, there are 22 
states and the District of Columbia \50\ which contribute 0.15 [mu]g/
m\3\ or more to downwind annual PM2.5 nonattainment. These 
states are: Alabama, Delaware, the District of Columbia, Florida, 
Georgia, Illinois, Indiana, Iowa, Kentucky, Maryland, Michigan, 
Minnesota, Missouri, New Jersey, New York, North Carolina, Ohio, 
Pennsylvania, South Carolina, Tennessee, Virginia, West Virginia, and 
Wisconsin. In Table IV.C-14, 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'').
---------------------------------------------------------------------------

    \50\ EPA combined Maryland and the District of Columbia as a 
single entity in our contribution modeling. This is a logical 
approach because of the small size of the District of Columbia and, 
hence, its emissions and its close proximity to Maryland.
---------------------------------------------------------------------------

    There are 19 states and the District of Columbia \51\ which 
contribute 0.15 [mu]g/m\3\ or more to downwind annual PM2.5 
maintenance. These states are: Alabama, the District of Columbia, 
Georgia, Illinois, Indiana, Iowa, Kentucky, Louisiana, Maryland, 
Michigan, Minnesota, Missouri, New Jersey, New York, Ohio, 
Pennsylvania, Tennessee, Virginia, West Virginia, and Wisconsin. In 
Table IV.C-15, 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'').
---------------------------------------------------------------------------

    \51\ As noted above, we combined Maryland and the District of 
Columbia as a single entity in our contribution modeling. This is a 
logical approach because of the small size of the District of 
Columbia and, hence, its emissions and its close proximity to 
Maryland.

[[Page 45257]]



                                                                        Table IV.C-14--Upwind State to Downwind Nonattainment Site ``Linkages'' for Annual PM2.5
----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                    Number of
           Upwind State             linkages
---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                   ..........                                        Counties containing downwind 24-hour PM2.5 nonattainment sites (monitoring site ID)
                                              ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama..........................           6  Bibb, GA                   Clayton, GA                Fulton, GA                 Clark, IN                  Dubois, IN                 Jefferson, KY
                                               (130210007)                (130630091)                (131210039)                (180190006)                (180372001)                (211110043)
Delaware.........................           2  Lancaster, PA              York, PA
                                               (420710007)                (421330008)
Florida..........................           3  Jefferson, AL              Bibb, GA                   Clayton, GA
                                               (10730023)                 (130210007)                (130630091)
Georgia..........................           7  Jefferson, AL              Jefferson, AL              Clark, IN                  Dubois, IN                 Jefferson, KY              Kanawha, WV               Cabell, WV
                                               (10730023)                 (10732003)                 (180190006)                (180372001)                (211110043)                (540391005)               (540110006)
Illinois.........................          29  Jefferson, AL              Jefferson, AL              Fulton, GA                 Bibb, GA                   Clayton, GA                Clark, IN                 Dubois, IN
                                               (10730023)                 (10732003)                 (131210039)                (130210007)                (130630091)                (180190006)               (180372001)
                                   ..........  Marion, IN                 Marion, IN                 Marion, IN                 Jefferson, KY              Wayne, MI                  Wayne, MI                 Butler, OH
                                               (180970078)                (180970081)                (180970083)                (211110043)                (261630015)                (261630033)               (390170016)
                                   ..........  Cuyahoga, OH               Cuyahoga, OH               Cuyahoga, OH               Hamilton, OH               Hamilton, OH               Hamilton, OH              Hamilton, OH
                                               (390350038)                (390350045)                (390350060)                (390610014)                (390610042)                (390610043)               (390617001)
                                   ..........  Hamilton, OH               Allegheny, PA              Allegheny, PA              Beaver, PA                 Lancaster, PA              York, PA                  Cabell, WV
                                               (390618001)                (420030064)                (420031301)                (420070014)                (420710007)                (421330008)               (540110006)
                                   ..........  Kanawha, WV
                                               (540391005)
Indiana..........................          27  Jefferson, AL              Jefferson, AL              Bibb, GA                   Clayton, GA                Fulton, GA                 Cook, IL                  Madison, IL
                                               (10730023)                 (10732003)                 (130210007)                (130630091)                (131210039)                (170310052)               (171191007)
                                   ..........  Saint Clair, IL            Jefferson, KY              Wayne, MI                  Wayne, MI                  Butler, OH                 Cuyahoga, OH              Cuyahoga, OH
                                               (171630010)                (211110043)                (261630015)                (261630033)                (390170016)                (390350038)               (390350045)
                                   ..........  Cuyahoga, OH               Hamilton, OH               Hamilton, OH               Hamilton, OH               Hamilton, OH               Hamilton, OH              Allegheny, PA
                                               (390350060)                (390618001)                (390610014)                (390610042)                (390610043)                (390617001)               (420030064)
                                   ..........  Allegheny, PA              Beaver, PA                 Lancaster, PA              York, PA                   Cabell, WV                 Kanawha, WV
                                               (420031301)                (420070014)                (420710007)                (421330008)                (540110006)                (540391005)
Iowa.............................           4  Cook, IL                   Madison, IL                Saint Clair, IL            Dubois, IN
                                               (170310052)                (171191007)                (171630010)                (180372001)
Kentucky.........................          31  Jefferson, AL              Jefferson, AL              Bibb, GA                   Clayton, GA                Fulton, GA                 Cook, IL                  Madison, IL
                                               (10730023)                 (10732003)                 (130210007)                (130630091)                (131210039)                (170310052)               (171191007)
                                   ..........  Saint Clair, IL            Clark, IN                  Dubois, IN                 Marion, IN                 Marion, IN                 Marion, IN                Wayne, MI
                                               (171630010)                (180190006)                (180372001)                (180970078)                (180970081)                (180970083)               (261630015)
                                   ..........  Wayne, MI                  Butler, OH                 Cuyahoga, OH               Cuyahoga, OH               Cuyahoga, OH               Hamilton, OH              Hamilton, OH
                                               (261630033)                (390170016)                (390350038)                (390350045)                (390350060)                (390610014)               (390610042)
                                   ..........  Hamilton, OH               Hamilton, OH               Hamilton, OH               Allegheny, PA              Allegheny, PA              Beaver, PA                Lancaster, PA
                                               (390610043)                (390617001)                (390618001)                (420030064)                (420031301)                (420070014)               (420710007)
                                   ..........  York, PA                   Cabell, WV                 Kanawha, WV
                                               (421330008)                (540110006)                (540391005)
Maryland.........................           2  Lancaster, PA              York, PA
                                               (420710007)                (421330008)
Michigan.........................          25  Cook, IL                   Madison, IL                Saint Clair, IL            Clark, IN                  Dubois, IN                 Marion, IN                Marion, IN
                                               (170310052)                (171191007)                (171630010)                (180190006)                (180372001)                (180970078)               (180970081)
                                   ..........  Marion, IN                 Jefferson, KY              Butler, OH                 Cuyahoga, OH               Cuyahoga, OH               Cuyahoga, OH              Hamilton, OH
                                               (180970083)                (211110043)                (390170016)                (390350038)                (390350045)                (390350060)               (390610014)
                                   ..........  Hamilton, OH               Hamilton, OH               Hamilton, OH               Hamilton, OH               Allegheny, PA              Allegheny, PA             Beaver, PA
                                               (390610042)                (390610043)                (390617001)                (390618001)                (420030064)                (420031301)               (420070014)
                                   ..........  Lancaster, PA              York, PA                   Cabell, WV                 Kanawha, WV
                                               (420710007)                (421330008)                (540110006)                (540391005)
Minnesota........................           1  Cook, IL
                                               (170310052)
Missouri.........................          17  Cook, IL                   Madison, IL                Saint Clair, IL            Clark, IN                  Dubois, IN                 Marion, IN                Marion, IN
                                               (170310052)                (171191007)                (171630010)                (180190006)                (180372001)                (180970078)               (180970081)
                                   ..........  Marion, IN                 Jefferson, KY              Butler, OH                 Hamilton, OH               Hamilton, OH               Hamilton, OH              Hamilton, OH
                                               (180970083)                (211110043)                (390170016)                (390610014)                (390610042)                (390610043)               (390617001)
                                   ..........  Hamilton, OH               Cabell, WV                 Kanawha, WV
                                               (390618001)                (540110006)                (540391005)
New Jersey.......................           2  Lancaster, PA              York, PA
                                               (420710007)                (421330008)

[[Page 45258]]


New York.........................           8  Cuyahoga, OH               Cuyahoga, OH               Cuyahoga, OH               Allegheny, PA              Allegheny, PA              Beaver, PA                Lancaster, PA
                                               (390350038)                (390350045)                (390350060)                (420030064)                (420031301)                (420070014)               (420710007)
                                   ..........  York, PA
                                               (421330008)
North Carolina...................           3  Bibb, GA                   Clayton, GA                Fulton, GA
                                               (130210007)                (130630091)                (131210039)
Ohio.............................          23  Jefferson, AL              Jefferson, AL              Bibb, GA                   Clayton, GA                Fulton, GA                 Cook, IL                  Madison, IL
                                               (10730023)                 (10732003)                 (130210007)                (130630091)                (131210039)                (170310052)               (171191007)
                                   ..........  Saint Clair, IL            Clark, IN                  Dubois, IN                 Marion, IN                 Marion, IN                 Marion, IN                Jefferson, KY
                                               (171630010)                (180190006)                (180372001)                (180970078)                (180970081)                (180970083)               (211110043)
                                   ..........  Wayne, MI                  Wayne, MI                  Allegheny, PA              Allegheny, PA              Beaver, PA                 Lancaster, PA             York, PA
                                               (261630015)                (261630033)                (420030064)                (420031301)                (420070014)                (420710007)               (421330008)
                                   ..........  Cabell, WV                 Kanawha, WV
                                               (540110006)                (540391005)
Pennsylvania.....................          25  Bibb, GA                   Clayton, GA                Fulton, GA                 Cook, IL                   Madison, IL                Saint Clair, IL           Clark, IN
                                               (130210007)                (130630091)                (131210039)                (170310052)                (171191007)                (171630010)               (180190006)
                                   ..........  Dubois, IN                 Marion, IN                 Marion, IN                 Marion, IN                 Jefferson, KY              Wayne, MI                 Wayne, MI
                                               (180372001)                (180970078)                (180970081)                (180970083)                (211110043)                (261630015)               (261630033)
                                   ..........  Butler, OH                 Cuyahoga, OH               Cuyahoga, OH               Cuyahoga, OH               Hamilton, OH               Hamilton, OH              Hamilton, OH
                                               (390170016)                (390350038)                (390350045)                (390350060)                (390610014)                (390610042)               (390610043)
                                   ..........  Hamilton, OH               Hamilton, OH               Cabell, WV                 Kanawha, WV
                                               (390617001)                (390618001)                (540110006)                (540391005)
South Carolina...................           3  Bibb, GA                   Clayton, GA                Fulton, GA
                                               (130210007)                (130630091)                (131210039)
Tennessee........................          29  Jefferson, AL              Jefferson, AL              Bibb, GA                   Clayton, GA                Fulton, GA                 Clark, IN                 Madison, IL
                                               (10730023)                 (10732003)                 (130210007)                (130630091)                (131210039)                (180190006)               (171191007)
                                   ..........  Saint Clair, IL            Dubois, IN                 Marion, IN                 Marion, IN                 Marion, IN                 Jefferson, KY             Wayne, MI
                                               (171630010)                (180372001)                (180970078)                (180970081)                (180970083)                (211110043)               (261630015)
                                   ..........  Wayne, MI                  Butler, OH                 Cuyahoga, OH               Cuyahoga, OH               Cuyahoga, OH               Hamilton, OH              Hamilton, OH
                                               (261630033)                (390170016)                (390350038)                (390350045)                (390350060)                (390610014)               (390610042)
                                   ..........  Hamilton, OH               Hamilton, OH               Hamilton, OH               Allegheny, PA              Allegheny, PA              Beaver, PA                Cabell, WV
                                               (390610043)                (390617001)                (390618001)                (420030064)                (420031301)                (420070014)               (540110006)
                                   ..........  Kanawha, WV
                                               (540391005)
Virginia.........................           4  Lancaster, PA              York, PA                   Cabell, WV                 Kanawha, WV
                                               (420710007)                (421330008)                (540110006)                (540391005)
West Virginia....................          25  Fulton, GA                 Bibb, GA                   Clayton, GA                Clark, IN                  Marion, IN                 Marion, IN                Marion, IN
                                               (131210039)                (130210007)                (130630091)                (180190006)                (180970078)                (180970081)               (180970083)
                                   ..........  Dubois, IN                 Jefferson, KY              Wayne, MI                  Wayne, MI                  Butler, OH                 Cuyahoga, OH              Cuyahoga, OH
                                               (180372001)                (211110043)                (261630015)                (261630033)                (390170016)                (390350038)               (390350045)
                                   ..........  Cuyahoga, OH               Hamilton, OH               Hamilton, OH               Hamilton, OH               Hamilton, OH               Hamilton, OH              Allegheny, PA
                                               (390350060)                (390610014)                (390610042)                (390610043)                (390617001)                (390618001)               (420030064)
                                   ..........  Allegheny, PA              Beaver, PA                 Lancaster, PA              York, PA
                                               (420031301)                (420070014)                (420710007)                (421330008)
Wisconsin........................           8  Cook, IL                   Dubois, IN                 Marion, IN                 Marion, IN                 Marion, IN                 Wayne, MI                 Wayne, MI
                                               (170310052)                (180372001)                (180970078)                (180970081)                (180970083)                (261630015)               (261630033)
                                   ..........  Cuyahoga, OH
                                               (390350045)
----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

[[Page 45259]]


                                                                         Table IV.C-15--Upwind State to Downwind Maintenance Site ``Linkages'' for Annual PM2.5
----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                    Number of
           Upwind State             linkages
---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                   ..........                                        Counties containing downwind 24-hour PM2.5 nonattainment sites (monitoring site ID)
                                              ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama..........................           1  Jefferson, KY
                                               (211110044)
Georgia..........................           1  Jefferson, KY
                                               (211110044)
Illinois.........................          13  Jefferson, KY              Cuyahoga, OH               Cuyahoga, OH               Hamilton, OH               Jefferson, OH              Montgomery, OH            Stark, OH
                                               (211110044)                (390350027)                (390350065)                (390610040)                (390811001)                (391130032)               (391510017)
                                   ..........  Berks, PA                  Harris, TX                 Berkeley, WV               Brooke, WV                 Hancock, WV                Marion, WV
                                               (420110011)                (482011035)                (540030003)                (540090005)                (540291004)                (540490006)
Indiana..........................          16  Cook, IL                   Cook, IL                   Jefferson, KY              New York, NY               Cuyahoga, OH               Cuyahoga, OH              Hamilton, OH
                                               (170313301)                (170316005)                (211110044)                (360610056)                (390350027)                (390350065)               (390610040)
                                   ..........  Jefferson, OH              Montgomery, OH             Stark, OH                  Berks, PA                  Harris, TX                 Berkeley, WV              Brooke, WV
                                               (390811001)                (391130032)                (391510017)                (420110011)                (482011035)                (540030003)               (540090005)
                                   ..........  Hancock, WV                Marion, WV
                                               (540291004)                (540490006)
Iowa.............................           2  Cook, IL                   Cook, IL
                                               (170313301)                (170316005)
Kentucky.........................          12  Cook, IL                   Cook, IL                   Cuyahoga, OH               Cuyahoga, OH               Hamilton, OH               Jefferson, OH             Montgomery, OH
                                               (170313301)                (170316005)                (390350027)                (390350065)                (390610040)                (390811001)               (391130032)
                                   ..........  Stark, OH                  Berkeley, WV               Brooke, WV                 Hancock, WV                Marion, WV
                                               (391510017)                (540030003)                (540090005)                (540291004)                (540490006)
Louisiana........................           1  Harris, TX
                                               (482011035)
Maryland.........................           2  Berks, PA                  Berkeley, WV
                                               (420110011)                (540030003)
Michigan.........................          15  Cook, IL                   Cook, IL                   Jefferson, KY              New York, NY               Cuyahoga, OH               Cuyahoga, OH              Hamilton, OH
                                               (170313301)                (170316005)                (211110044)                (360610056)                (390350027)                (390350065)               (390610040)
                                   ..........  Jefferson, OH              Montgomery, OH             Stark, OH                  Berks, PA                  Berkeley, WV               Brooke, WV                Hancock, WV
                                               (390811001)                (391130032)                (391510017)                (420110011)                (540030003)                (540090005)               (540291004)
                                   ..........  Marion, WV
                                               (540490006)
Minnesota........................           1  Cook, IL
                                               (170316005)
Missouri.........................           6  Cook, IL                   Cook, IL                   Jefferson, KY              Hamilton, OH               Montgomery, OH             Stark, OH
                                               (170313301)                (170316005)                (211110044)                (390610040)                (391130032)                (391510017)
New Jersey.......................           2  New York, NY               Berks, PA
                                               (360610056)                (420110011)
New York.........................           9  Cuyahoga, OH               Cuyahoga, OH               Jefferson, OH              Stark, OH                  Berks, PA                  Berkeley, WV              Brooke, WV
                                               (390350027)                (390350065)                (390811001)                (391510017)                (420110011)                (540030003)               (540090005)
                                   ..........  Hancock, WV                Marion, WV
                                               (540291004)                (540490006)
Ohio.............................           9  Cook, IL                   Cook, IL                   Jefferson, KY              New York, NY               Berks, PA                  Berkeley, WV              Brooke, WV
                                               (170313301)                (170316005)                (211110044)                (360610056)                (420110011)                (540030003)               (540090005)
                                   ..........  Hancock, WV                Marion, WV
                                               (540291004)                (540490006)
Pennsylvania.....................          14  Cook, IL                   Cook, IL                   Jefferson, KY              New York, NY               Cuyahoga, OH               Cuyahoga, OH              Hamilton, OH
                                               (170313301)                (170316005)                (211110044)                (360610056)                (390350027)                (390350065)               (390610040)
                                   ..........  Jefferson, OH              Montgomery, OH             Stark, OH                  Berkeley, WV               Brooke, WV                 Hancock, WV               Marion, WV
                                               (390811001)                (391130032)                (391510017)                (540030003)                (540090005)                (540291004)               (540490006)
Tennessee........................          10  Jefferson, KY              Cuyahoga, OH               Cuyahoga, OH               Hamilton, OH               Jefferson, OH              Montgomery, OH            Stark, OH
                                               (211110044)                (390350027)                (390350065)                (390610040)                (390811001)                (391130032)               (391510017)
                                   ..........  Brooke, WV                 Hancock, WV                Marion, WV
                                               (540090005)                (540291004)                (540490006)
Virginia.........................           4  New York, NY               Berks, PA                  Berkeley, WV               Marion, WV
                                               (360610056)                (420110011)                (540030003)                (540490006)
West Virginia....................           9  Jefferson, KY              New York, NY               Cuyahoga, OH               Cuyahoga, OH               Hamilton, OH               Jefferson, OH             Montgomery, OH
                                               (211110044)                (360610056)                (390350027)                (390350065)                (390610040)                (390811001)               (391130032)
                                   ..........  Stark, OH                  Berks, PA
                                               (391510017)                (420110011)

[[Page 45260]]


Wisconsin........................           2  Cook, IL                   Cook, IL
                                               (170313301)                (170316005)
----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------


[[Page 45261]]

    For 24-hour PM2.5, we calculated each state's 
contribution to each of the 92 monitoring sites that are projected to 
be nonattainment and each of the 38 sites that are projected to have 
maintenance problems for the 24-hour PM2.5 NAAQS in the 2012 
base case. The largest contribution from each state to 24-hour 
PM2.5 nonattainment in downwind sites is provided in Table 
IV.C-16. The largest contribution from each state to 24-hour 
PM2.5 maintenance in downwind sites is also provided in 
Table IV.C-16. The contributions from each state to all projected 2012 
nonattainment and maintenance sites for the 24-hour PM2.5 
NAAQS are provided in the AQMTSD.

  Table IV.C-16--Largest Contribution to Downwind 24-Hour PM2.5 ([mu]g/
        m\3\) Nonattainment and Maintenance for Each of 37 States
------------------------------------------------------------------------
                                              Largest
                                             downwind         Largest
                                           contribution      downwind
                                                to         contribution
              Upwind State                 nonattainment  to maintenance
                                            for 24-hour     for 24-hour
                                           PM2.5 ([mu]g/   PM2.5 ([mu]g/
                                               m\3\)           m\3\)
------------------------------------------------------------------------
Alabama.................................            0.48            0.32
Arkansas................................            0.20            0.17
Connecticut.............................            0.41            0.70
Delaware................................            0.50            0.36
Florida.................................            0.08            0.08
Georgia.................................            0.95            0.41
Illinois................................            7.28            6.57
Indiana.................................            9.91            8.94
Iowa....................................            1.87            1.67
Kansas..................................            0.77            0.45
Kentucky................................            6.53            6.91
Louisiana...............................            0.23            0.18
Maine...................................            0.19            0.19
Maryland/Washington, DC.................            2.63            1.82
Massachusetts...........................            0.67            0.71
Michigan................................            2.35            3.35
Minnesota...............................            0.91            0.86
Mississippi.............................            0.09            0.04
Missouri................................            5.03            4.82
Nebraska................................            0.62            0.39
New Hampshire...........................            0.21            0.23
New Jersey..............................            2.69            4.74
New York................................            5.82            1.17
North Carolina..........................            0.50            0.45
North Dakota............................            0.27            0.15
Ohio....................................            5.84            5.56
Oklahoma................................            0.16            0.21
Pennsylvania............................            3.67            4.86
Rhode Island............................            0.05            0.06
South Carolina..........................            0.19            0.19
South Dakota............................            0.13            0.09
Tennessee...............................            3.92            4.70
Texas...................................            0.21            0.28
Vermont.................................            0.06            0.07
Virginia................................            1.32            2.26
West Virginia...........................            3.51            4.83
Wisconsin...............................            0.80            1.01
------------------------------------------------------------------------

    Based on the state-by-state contribution analysis, there are 24 
states and the District of Columbia \52\ which contribute 0.35 [mu]g/
m\3\ or more to downwind 24-hour PM2.5 nonattainment. These 
states are: Alabama, the District of Columbia, Georgia, Illinois, 
Indiana, Iowa, Kansas, Kentucky, Maryland, Massachusetts, Michigan, 
Minnesota, Missouri, Nebraska, New Jersey, New York, North Carolina, 
Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and Wisconsin. 
In Table IV.C-17, 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'').
---------------------------------------------------------------------------

    \52\ As noted above, we combined Maryland and the District of 
Columbia as a single entity in our contribution modeling. This is a 
logical approach because of the small size of the District of 
Columbia and, hence, its emissions and its close proximity to 
Maryland.
---------------------------------------------------------------------------

    There are 23 states and the District of Columbia which contribute 
0.35 [mu]g/m\3\ or more to downwind 24-hour PM2.5 
maintenance. These states are: Connecticut, Delaware, the District of 
Columbia, Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky, Maryland, 
Massachusetts, Michigan, Minnesota, Missouri, Nebraska, New Jersey, New 
York, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West 
Virginia, and Wisconsin. In Table IV.C-18, 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'').

[[Page 45262]]



                                                    Table IV.C-17--Upwind State to Downwind Nonattainment Site ``Linkages'' for 24-Hour PM2.5
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                  Number of
          Upwind State            linkages
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                 ..........                                  Counties containing downwind 24-hour PM2.5 nonattainment sites (monitoring site ID)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama........................           5  Monroe, MI               Wayne, MI                Hamilton, OH             Hamilton, OH             Hamilton, OH             ......................
                                             (261150005)              (261630015)              (390610006)              (390610014)              (390618001)
Connecticut....................           3  Hudson, NJ               New York, NY             New York, NY             .......................  .......................  ......................
                                             (340172002)              (360610056)              (360610128)
Delaware.......................           2  Union, NJ                Dauphin, PA              .......................  .......................  .......................  ......................
                                             (340390004)              (420430401)
Georgia........................          12  Jefferson, AL            Jefferson, AL            Baltimore City, MD       Baltimore City, MD       Union, NJ                Butler, OH
                                             (10730023)               (10732003)               (245100040)              (245100049)              (340390004)              (390170016)
                                             Butler, OH               Hamilton, OH             Hamilton, OH             Hamilton, OH             Montgomery, OH           York, PA
                                             (390171004)              (390610006)              (390610014)              (390618001)              (391130032)              (421330008)
Illinois.......................          70  Jefferson, AL            Jefferson, AL            New Haven, CT            Clark, IN                Dubois, IN               Knox, IN
                                             (10730023)               (10732003)               (90091123)               (180190006)              (180372001)              (180830004)
                                             Lake, IN                 Lake, IN                 Marion, IN               Marion, IN               Marion, IN               Marion, IN
                                             (180890022)              (180890026)              (180970042)              (180970043)              (180970066)              (180970078)
                                             Marion, IN               Marion, IN               Marion, IN               Tippecanoe, IN           Scott, IA                Daviess, KY
                                             (180970079)              (180970081)              (180970083)              (181570008)              (191630019)              (210590005)
                                             Jefferson, KY            Jefferson, KY            Jefferson, KY            Monroe, MI               Oakland, MI              St. Clair, MI
                                             (211110043)              (211110044)              (211110048)              (261150005)              (261250001)              (261470005)
                                             Washtenaw, MI            Wayne, MI                Wayne, MI                Wayne, MI                Wayne, MI                Wayne, MI
                                             (261610008)              (261630015)              (261630016)              (261630019)              (261630033)              (261630036)
                                             Jefferson, MO            Saint Charles, MO        St. Louis City, MO       St. Louis City, MO       Union, NJ                New York, NY
                                             (290990012)              (291831002)              (295100007)              (295100087)              (340390004)              (360610128)
                                             Butler, OH               Butler, OH               Butler, OH               Butler, OH               Cuyahoga, OH             Cuyahoga, OH
                                             (390170003)              (390170016)              (390170017)              (390171004)              (390350038)              (390350045)
                                             Cuyahoga, OH             Cuyahoga, OH             Franklin, OH             Franklin, OH             Hamilton, OH             Hamilton, OH
                                             (390350060)              (390350065)              (390490024)              (390490025)              (390610006)              (390610014)
                                             Hamilton, OH             Hamilton, OH             Hamilton, OH             Hamilton, OH             Hamilton, OH             Jefferson, OH
                                             (390610040)              (390610042)              (390610043)              (390617001)              (390618001)              (390811001)
                                             Montgomery, OH           Summit, OH               Allegheny, PA            Allegheny, PA            Allegheny, PA            Allegheny, PA
                                             (391130032)              (391530017)              (420030064)              (420030093)              (420030116)              (420031008)
                                             Allegheny, PA            Beaver, PA               Berks, PA                Cambria, PA              Montgomery, TN           Brooke, WV
                                             (420031301)              (420070014)              (420110011)              (420210011)              (471251009)              (540090011)
                                             Milwaukee, WI            Milwaukee, WI            Milwaukee, WI            Milwaukee, WI            .......................  ......................
                                             (550790010)              (550790026)              (550790043)              (550790099)
Indiana........................          75  Jefferson, AL            Jefferson, AL            New Haven, CT            Cook, IL                 Cook, IL                 Cook, IL
                                             (10730023)               (10732003)               (90091123)               (170310052)              (170310057)              (170310076)
                                             Cook, IL                 Cook, IL                 Cook, IL                 Cook, IL                 Cook, IL                 Madison, IL
                                             (170311016)              (170312001)              (170313103)              (170313301)              (170316005)              (171190023)
                                             Madison, IL              Madison, IL              Madison, IL              Scott, IA                Daviess, KY              Jefferson, KY
                                             (171191007)              (171192009)              (171193007)              (191630019)              (210590005)              (211110043)
                                             Jefferson, KY            Jefferson, KY            Monroe, MI               Oakland, MI              St. Clair, MI            Washtenaw, MI
                                             (211110044)              (211110048)              (261150005)              (261250001)              (261470005)              (261610008)
                                             Wayne, MI                Wayne, MI                Wayne, MI                Wayne, MI                Wayne, MI                Jefferson, MO
                                             (261630015)              (261630016)              (261630019)              (261630033)              (261630036)              (290990012)
                                             Saint Charles, MO        St. Louis City, MO       St. Louis City, MO       Hudson, NJ               Union, NJ                Bronx, NY
                                             (291831002)              (295100007)              (295100087)              (340171003)              (340390004)              (360050080)
                                             New York, NY             New York, NY             Butler, OH               Butler, OH               Butler, OH               Butler, OH
                                             (360610056)              (360610128)              (390170003)              (390170016)              (390170017)              (390171004)
                                             Cuyahoga, OH             Cuyahoga, OH             Cuyahoga, OH             Cuyahoga, OH             Franklin, OH             Franklin, OH
                                             (390350038)              (390350045)              (390350060)              (390350065)              (390490024)              (390490025)
                                             Hamilton, OH             Hamilton, OH             Hamilton, OH             Hamilton, OH             Hamilton, OH             Hamilton, OH
                                             (390610006)              (390610014)              (390610040)              (390610042)              (390610043)              (390617001)
                                             Hamilton, OH             Jefferson, OH            Montgomery, OH           Summit, OH               Allegheny, PA            Allegheny, PA
                                             (390618001)              (390811001)              (391130032)              (391530017)              (420030008)              (420030064)
                                             Allegheny, PA            Allegheny, PA            Allegheny, PA            Allegheny, PA            Beaver, PA               Berks, PA
                                             (420030093)              (420030116)              (420031008)              (420031301)              (420070014)              (420110011)
                                             Cambria, PA              Dauphin, PA              York, PA                 Montgomery, TN           Brooke, WV               Milwaukee, WI
                                             (420210011)              (420430401)              (421330008)              (471251009)              (540090011)              (550790010)
                                             Milwaukee, WI            Milwaukee, WI            Milwaukee, WI            .......................  .......................  ......................
                                             (550790026)              (550790043)              (550790099)
Iowa...........................          17  Cook, IL                 Cook, IL                 Cook, IL                 Cook, IL                 Cook, IL                 Cook, IL
                                             (170310052)              (170310057)              (170310076)              (170311016)              (170312001)              (170313103)
                                             Cook, IL                 Cook, IL                 Madison, IL              Lake, IN                 Lake, IN                 Jefferson, MO
                                             (170313301)              (170316005)              (171191007)              (180890022)              (180890026)              (290990012)
                                             St. Louis City, MO       Milwaukee, WI            Milwaukee, WI            Milwaukee, WI            Milwaukee, WI            ......................
                                             (295100007)              (550790010)              (550790026)              (550790043)              (550790099)
Kansas.........................           3  Milwaukee, WI            Milwaukee, WI            Milwaukee, WI            .......................  .......................  ......................
                                             (550790010)              (550790026)              (550790099)
Kentucky.......................          81  Jefferson, AL            Jefferson, AL            New Haven, CT            Cook, IL                 Cook, IL                 Cook, IL
                                             (10730023)               (10732003)               (90091123)               (170310052)              (170310057)              (170310076)
                                             Cook, IL                 Cook, IL                 Cook, IL                 Cook, IL                 Cook, IL                 Madison, IL
                                             (170311016)              (170312001)              (170313103)              (170313301)              (170316005)              (171190023)
                                             Madison, IL              Madison, IL              Madison, IL              Clark, IN                Dubois, IN               Knox, IN
                                             (171191007)              (171192009)              (171193007)              (180190006)              (180372001)              (180830004)
                                             Lake, IN                 Marion, IN               Marion, IN               Marion, IN               Marion, IN               Marion, IN
                                             (180890026)              (180970042)              (180970043)              (180970066)              (180970078)              (180970079)
                                             Marion, IN               Marion, IN               Tippecanoe, IN           Scott, IA                Monroe, MI               Oakland, MI
                                             (180970081)              (180970083)              (181570008)              (191630019)              (261150005)              (261250001)

[[Page 45263]]


                                             St. Clair, MI            Washtenaw, MI            Wayne, MI                Wayne, MI                Wayne, MI                Wayne, MI
                                             (261470005)              (261610008)              (261630015)              (261630016)              (261630019)              (261630033)
                                             Wayne, MI                Jefferson, MO            Saint Charles, MO        St. Louis City, MO       St. Louis City, MO       Hudson, NJ
                                             (261630036)              (290990012)              (291831002)              (295100007)              (295100087)              (340171003)
                                             Union, NJ                Bronx, NY                New York, NY             Butler, OH               Butler, OH               Butler, OH
                                             (340390004)              (360050080)              (360610128)              (390170003)              (390170016)              (390170017)
                                             Butler, OH               Cuyahoga, OH             Cuyahoga, OH             Cuyahoga, OH             Cuyahoga, OH             Franklin, OH
                                             (390171004)              (390350038)              (390350045)              (390350060)              (390350065)              (390490024)
                                             Franklin, OH             Hamilton, OH             Hamilton, OH             Hamilton, OH             Hamilton, OH             Hamilton, OH
                                             (390490025)              (390610006)              (390610014)              (390610040)              (390610042)              (390610043)
                                             Hamilton, OH             Hamilton, OH             Jefferson, OH            Montgomery, OH           Summit, OH               Allegheny, PA
                                             (390617001)              (390618001)              (390811001)              (391130032)              (391530017)              (420030008)
                                             Allegheny, PA            Allegheny, PA            Allegheny, PA            Allegheny, PA            Allegheny, PA            Beaver, PA
                                             (420030064)              (420030093)              (420030116)              (420031008)              (420031301)              (420070014)
                                             Berks, PA                Cambria, PA              York, PA                 Montgomery, TN           Brooke, WV               Milwaukee, WI
                                             (420110011)              (420210011)              (421330008)              (471251009)              (540090011)              (550790010)
                                             Milwaukee, WI            Milwaukee, WI            Milwaukee, WI            .......................  .......................  ......................
                                             (550790026)              (550790043)              (550790099)
Maryland.......................          11  New Haven, CT            Hudson, NJ               Hudson, NJ               Union, NJ                Bronx, NY                New York, NY
                                             (90091123)               (340171003)              (340172002)              (340390004)              (360050080)              (360610056)
                                             New York, NY             Berks, PA                Dauphin, PA              Lancaster, PA            York, PA                 ......................
                                             (360610128)              (420110011)              (420430401)              (420710007)              (421330008)
Massachusetts..................           3  New Haven, CT            New York, NY             New York, NY             .......................  .......................  ......................
                                             (90091123)               (360610056)              (360610128)
Michigan.......................          48  Cook, IL                 Cook, IL                 Cook, IL                 Cook, IL                 Cook, IL                 Cook, IL
                                             (170310052)              (170310057)              (170310076)              (170311016)              (170312001)              (170313103)
                                             Cook, IL                 Cook, IL                 Madison, IL              Madison, IL              Madison, IL              Madison, IL
                                             (170313301)              (170316005)              (171190023)              (171191007)              (171192009)              (171193007)
                                             Knox, IN                 Lake, IN                 Lake, IN                 Scott, IA                Jefferson, MO            Saint Charles, MO
                                             (180830004)              (180890022)              (180890026)              (191630019)              (290990012)              (291831002)
                                             St. Louis City, MO       St. Louis City, MO       New York, NY             Cuyahoga, OH             Cuyahoga, OH             Cuyahoga, OH
                                             (295100007)              (295100087)              (360610128)              (390350038)              (390350045)              (390350060)
                                             Cuyahoga, OH             Franklin, OH             Franklin, OH             Hamilton, OH             Hamilton, OH             Hamilton, OH
                                             (390350065)              (390490024)              (390490025)              (390610014)              (390617001)              (390618001)
                                             Jefferson, OH            Montgomery, OH           Summit, OH               Allegheny, PA            Allegheny, PA            Allegheny, PA
                                             (390811001)              (391130032)              (391530017)              (420030008)              (420030064)              (420030093)
                                             Allegheny, PA            Allegheny, PA            Allegheny, PA            Beaver, PA               Cambria, PA              Dauphin, PA
                                             (420030116)              (420031008)              (420031301)              (420070014)              (420210011)              (420430401)
                                             Montgomery, TN           Brooke, WV               Milwaukee, WI            Milwaukee, WI            Milwaukee, WI            ......................
                                             (471251009)              (540090011)              (550790010)              (550790026)              (550790043)
                                             Milwaukee, WI
                                             (550790099)
Minnesota......................           4  Milwaukee, WI            Milwaukee, WI            Milwaukee, WI            Milwaukee, WI            .......................  ......................
                                             (550790010)              (550790026)              (550790043)              (550790099)
Missouri.......................          56  Cook, IL                 Cook, IL                 Cook, IL                 Cook, IL                 Cook, IL                 Cook, IL
                                             (170310052)              (170310057)              (170310076)              (170311016)              (170312001)              (170313103)
                                             Cook, IL                 Cook, IL                 Madison, IL              Madison, IL              Madison, IL              Madison, IL
                                             (170313301)              (170316005)              (171190023)              (171191007)              (171192009)              (171193007)
                                             Clark, IN                Dubois, IN               Knox, IN                 Lake, IN                 Lake, IN                 Marion, IN
                                             (180190006)              (180372001)              (180830004)              (180890022)              (180890026)              (180970042)
                                             Marion, IN               Marion, IN               Marion, IN               Marion, IN               Marion, IN               Marion, IN
                                             (180970043)              (180970066)              (180970078)              (180970079)              (180970081)              (180970083)
                                             Tippecanoe, IN           Scott, IA                Daviess, KY              Jefferson, KY            Jefferson, KY            Jefferson, KY
                                             (181570008)              (191630019)              (210590005)              (211110043)              (211110044)              (211110048)
                                             Monroe, MI               Oakland, MI              Washtenaw, MI            Wayne, MI                Wayne, MI                Wayne, MI
                                             (261150005)              (261250001)              (261610008)              (261630015)              (261630033)              (261630036)
                                             Butler, OH               Butler, OH               Butler, OH               Butler, OH               Franklin, OH             Franklin, OH
                                             (390170003)              (390170016)              (390170017)              (390171004)              (390490024)              (390490025)
                                             Hamilton, OH             Hamilton, OH             Hamilton, OH             Hamilton, OH             Hamilton, OH             Hamilton, OH
                                             (390610006)              (390610014)              (390610040)              (390610042)              (390610043)              (390617001)
                                             Hamilton, OH             Montgomery, OH           Allegheny, PA            Montgomery, TN           Milwaukee, WI            Milwaukee, WI
                                             (390618001)              (391130032)              (420030116)              (471251009)              (550790010)              (550790026)
                                             Milwaukee, WI            Milwaukee, WI            .......................  .......................  .......................  ......................
                                             (550790043)              (550790099)
Nebraska.......................           3  Milwaukee, WI            Milwaukee, WI            Milwaukee, WI            .......................  .......................  ......................
                                             (550790010)              (550790026)              (550790099)
New Jersey.....................           9  New Haven, CT            Baltimore City, MD       Bronx, NY                New York, NY             New York, NY             Berks, PA
                                             (90091123)               (245100049)              (360050080)              (360610056)              (360610128)              (420110011)
                                             Dauphin, PA              Lancaster, PA            York, PA                 .......................  .......................  ......................
                                             (420430401)              (420710007)              (421330008)
New York.......................          23  New Haven, CT            Baltimore City, MD       Baltimore City, MD       St. Clair, MI            Washtenaw, MI            Wayne, MI
                                             (90091123)               (245100040)              (245100049)              (261470005)              (261610008)              (261630016)
                                             Wayne, MI                Wayne, MI                Wayne, MI                Hudson, NJ               Hudson, NJ               Union, NJ
                                             (261630019)              (261630033)              (261630036)              (340171003)              (340172002)              (340390004)
                                             Cuyahoga, OH             Cuyahoga, OH             Cuyahoga, OH             Cuyahoga, OH             Franklin, OH             Franklin, OH
                                             (390350038)              (390350045)              (390350060)              (390350065)              (390490024)              (390490025)
                                             Summit, OH               Berks, PA (420110011)    Dauphin, PA              Lancaster, PA            York, PA                 ......................
                                             (391530017)                                       (420430401)              (420710007)              (421330008)

[[Page 45264]]


North Carolina.................          11  Baltimore City, MD       Baltimore City, MD       Hudson, NJ               Hudson, NJ               Union, NJ                Bronx, NY
                                             (245100040)              (245100049)              (340171003)              (340172002)              (340390004)              (360050080)
                                             New York, NY             Berks, PA                Dauphin, PA              Lancaster, PA            York, PA                 ......................
                                             (360610056)              (420110011)              (420430401)              (420710007)              (421330008)
Ohio...........................          72  Jefferson, AL            Jefferson, AL            New Haven, CT            Cook, IL                 Cook, IL                 Cook, IL
                                             (10730023)               (10732003)               (90091123)               (170310052)              (170310057)              (170310076)
                                             Cook, IL                 Cook, IL                 Cook, IL                 Cook, IL                 Cook, IL                 Madison, IL
                                             (170311016)              (170312001)              (170313103)              (170313301)              (170316005)              (171190023)
                                             Madison, IL              Madison, IL              Madison, IL              Clark, IN                Dubois, IN               Knox, IN
                                             (171191007)              (171192009)              (171193007)              (180190006)              (180372001)              (180830004)
                                             Lake, IN                 Lake, IN                 Marion, IN               Marion, IN               Marion, IN               Marion, IN
                                             (180890022)              (180890026)              (180970042)              (180970043)              (180970066)              (180970078)
                                             Marion, IN               Marion, IN               Marion, IN               Tippecanoe, IN           Scott, IA                Daviess, KY
                                             (180970079)              (180970081)              (180970083)              (181570008)              (191630019)              (210590005)
                                             Jefferson, KY            Jefferson, KY            Jefferson, KY            Baltimore City, MD       Baltimore City, MD       Monroe, MI
                                             (211110043)              (211110044)              (211110048)              (245100040)              (245100049)              (261150005)
                                             Oakland, MI              St. Clair, MI            Washtenaw, MI            Wayne, MI                Wayne, MI                Wayne, MI
                                             (261250001)              (261470005)              (261610008)              (261630015)              (261630016)              (261630019)
                                             Wayne, MI                Wayne, MI                Jefferson, MO            Saint Charles, MO        St. Louis City, MO       St. Louis City, MO
                                             (261630033)              (261630036)              (290990012)              (291831002)              (295100007)              (295100087)
                                             Hudson, NJ               Hudson, NJ               Union, NJ                Bronx, NY                New York, NY             New York, NY
                                             (340171003)              (340172002)              (340390004)              (360050080)              (360610056)              (360610128)
                                             Allegheny, PA            Allegheny, PA            Allegheny, PA            Allegheny, PA            Allegheny, PA            Allegheny, PA
                                             (420030008)              (420030064)              (420030093)              (420030116)              (420031008)              (420031301)
                                             Beaver, PA               Berks, PA                Cambria, PA              Dauphin, PA              Lancaster, PA            York, PA
                                             (420070014)              (420110011)              (420210011)              (420430401)              (420710007)              (421330008)
                                             Montgomery, TN           Brooke, WV               Milwaukee, WI            Milwaukee, WI            Milwaukee, WI            Milwaukee, WI
                                             (471251009)              (540090011)              (550790010)              (550790026)              (550790043)              (550790099)
Pennsylvania...................          77  Jefferson, AL            Jefferson, AL            New Haven, CT            Cook, IL                 Cook, IL                 Cook, IL
                                             (10730023)               (10732003)               (90091123)               (170310052)              (170310057)              (170310076)
                                             Cook, IL                 Cook, IL                 Cook, IL                 Cook, IL                 Cook, IL                 Madison, IL
                                             (170311016)              (170312001)              (170313103)              (170313301)              (170316005)              (171191007)
                                             Madison, IL              Madison, IL              Madison, IL              Clark, IN                Dubois, IN               Knox, IN
                                             (171192009)              (171193007)              (171190023)              (180190006)              (180372001)              (180830004)
                                             Lake, IN                 Marion, IN               Marion, IN               Marion, IN               Marion, IN               Marion, IN
                                             (180890026)              (180970042)              (180970043)              (180970066)              (180970078)              (180970079)
                                             Marion, IN               Marion, IN               Tippecanoe, IN           Scott, IA                Jefferson, KY            Jefferson, KY
                                             (180970081)              (180970083)              (181570008)              (191630019)              (211110043)              (211110044)
                                             Jefferson, KY            Baltimore City, MD       Baltimore City, MD       Monroe, MI               Oakland, MI              St. Clair, MI
                                             (211110048)              (245100040)              (245100049)              (261150005)              (261250001)              (261470005)
                                             Washtenaw, MI            Wayne, MI                Wayne, MI                Wayne, MI                Wayne, MI                Wayne, MI
                                             (261610008)              (261630015)              (261630016)              (261630019)              (261630033)              (261630036)
                                             Jefferson, MO            Saint Charles, MO        St. Louis City, MO       St. Louis City, MO       Hudson, NJ               Hudson, NJ
                                             (290990012)              (291831002)              (295100007)              (295100087)              (340171003)              (340172002)
                                             Union, NJ                Bronx, NY                New York, NY             New York, NY             Butler, OH               Butler, OH
                                             (340390004)              (360050080)              (360610056)              (360610128)              (390170003)              (390170016)
                                             Butler, OH               Butler, OH               Cuyahoga, OH             Cuyahoga, OH             Cuyahoga, OH             Cuyahoga, OH
                                             (390170017)              (390171004)              (390350038)              (390350045)              (390350060)              (390350065)
                                             Franklin, OH             Franklin, OH             Hamilton, OH             Hamilton, OH             Hamilton, OH             Hamilton, OH
                                             (390490024)              (390490025)              (390610006)              (390610014)              (390610040)              (390610042)
                                             Hamilton, OH             Hamilton, OH             Hamilton, OH             Jefferson, OH            Montgomery, OH           Summit, OH
                                             (390610043)              (390617001)              (390618001)              (390811001)              (391130032)              (391530017)
                                             Montgomery, TN           Brooke, WV               Milwaukee, WI            Milwaukee, WI            Milwaukee, WI            ......................
                                             (471251009)              (540090011)              (550790026)              (550790043)              (550790099)
Tennessee......................          61  Jefferson, AL            Jefferson, AL            New Haven, CT            Madison, IL              Madison, IL              Madison, IL
                                             (10730023)               (10732003)               (90091123)               (171190023)              (171191007)              (171192009)
                                             Madison, IL              Clark, IN                Dubois, IN               Knox, IN                 Marion, IN               Marion, IN
                                             (171193007)              (180190006)              (180372001)              (180830004)              (180970042)              (180970043)
                                             Marion, IN               Marion, IN               Marion, IN               Marion, IN               Marion, IN               Tippecanoe, IN
                                             (180970066)              (180970078)              (180970079)              (180970081)              (180970083)              (181570008)
                                             Scott, IA                Daviess, KY              Jefferson, KY            Jefferson, KY            Jefferson, KY            Monroe, MI
                                             (191630019)              (210590005)              (211110043)              (211110044)              (211110048)              (261150005)
                                             Oakland, MI              St. Clair, MI            Washtenaw, MI            Wayne, MI                Wayne, MI                Wayne, MI
                                             (261250001)              (261470005)              (261610008)              (261630015)              (261630033)              (261630036)
                                             Jefferson, MO            Saint Charles, MO        St. Louis City, MO       St. Louis City, MO       Union, NJ                New York, NY
                                             (290990012)              (291831002)              (295100007)              (295100087)              (340390004)              (360610128)
                                             Butler, OH               Butler, OH               Butler, OH               Butler, OH               Cuyahoga, OH             Cuyahoga, OH
                                             (390170003)              (390170016)              (390170017)              (390171004)              (390350038)              (390350045)
                                             Cuyahoga, OH             Franklin, OH             Franklin, OH             Hamilton, OH             Hamilton, OH             Hamilton, OH
                                             (390350065)              (390490024)              (390490025)              (390610006)              (390610014)              (390610040)
                                             Hamilton, OH             Hamilton, OH             Hamilton, OH             Hamilton, OH             Jefferson, OH            Montgomery, OH
                                             (390610042)              (390610043)              (390617001)              (390618001)              (390811001)              (391130032)
                                             Summit, OH               Allegheny, PA            Allegheny, PA            Allegheny, PA            Allegheny, PA            Cambria, PA
                                             (391530017)              (420030093)              (420030116)              (420031008)              (420031301)              (420210011)
                                             York, PA                 .......................  .......................  .......................  .......................  ......................
                                             (421330008)
Virginia.......................          13  New Haven, CT            Baltimore City, MD       Baltimore City, MD       Hudson, NJ               Hudson, NJ               Union, NJ
                                             (90091123)               (245100040)              (245100049)              (340171003)              (340172002)              (340390004)

[[Page 45265]]


                                             Bronx, NY                New York, NY             New York, NY             Berks, PA                Dauphin, PA              Lancaster, PA
                                             (360050080)              (360610056)              (360610128)              (420110011)              (420430401)              (420710007)
                                             York, PA                 .......................  .......................  .......................  .......................  ......................
                                             (421330008)
West Virginia..................          84  Jefferson, AL            Jefferson, AL            New Haven, CT            Cook, IL                 Cook, IL                 Cook, IL
                                             (10730023)               (10732003)               (90091123)               (170310052)              (170310057)              (170310076)
                                             Cook, IL                 Cook, IL                 Cook, IL                 Cook, IL                 Madison, IL              Madison, IL
                                             (170311016)              (170312001)              (170313301)              (170316005)              (171190023)              (171191007)
                                             Madison, IL              Madison, IL              Clark, IN                Dubois, IN               Lake, IN                 Marion, IN
                                             (171192009)              (171193007)              (180190006)              (180372001)              (180890026)              (180970042)
                                             Marion, IN               Marion, IN               Marion, IN               Marion, IN               Marion, IN               Marion, IN
                                             (180970043)              (180970066)              (180970078)              (180970079)              (180970081)              (180970083)
                                             Tippecanoe, IN           Scott, IA                Jefferson, KY            Jefferson, KY            Jefferson, KY            Baltimore City, MD
                                             (181570008)              (191630019)              (211110043)              (211110044)              (211110048)              (245100040)
                                             Baltimore City, MD       Monroe, MI               Oakland, MI              St. Clair, MI            Washtenaw, MI            Wayne, MI
                                             (245100049)              (261150005)              (261250001)              (261470005)              (261610008)              (261630015)
                                             Wayne, MI                Wayne, MI                Wayne, MI                Wayne, MI                Jefferson, MO            Saint Charles, MO
                                             (261630016)              (261630019)              (261630033)              (261630036)              (290990012)              (291831002)
                                             St. Louis City, MO       St. Louis City, MO       Hudson, NJ               Hudson, NJ               Union, NJ                Bronx, NY
                                             (295100007)              (295100087)              (340171003)              (340172002)              (340390004)              (360050080)
                                             New York, NY             New York, NY             Butler, OH               Butler, OH               Butler, OH               Butler, OH
                                             (360610056)              (360610128)              (390170003)              (390170016)              (390170017)              (390171004)
                                             Cuyahoga, OH             Cuyahoga, OH             Cuyahoga, OH             Cuyahoga, OH             Franklin, OH             Franklin, OH
                                             (390350038)              (390350045)              (390350060)              (390350065)              (390490024)              (390490025)
                                             Hamilton, OH             Hamilton, OH             Hamilton, OH             Hamilton, OH             Hamilton, OH             Hamilton, OH
                                             (390610006)              (390610014)              (390610040)              (390610042)              (390610043)              (390617001)
                                             Hamilton, OH             Jefferson, OH            Montgomery, OH           Summit, OH               Allegheny, PA            Allegheny, PA
                                             (390618001)              (390811001)              (391130032)              (391530017)              (420030008)              (420030064)
                                             Allegheny, PA            Allegheny, PA            Allegheny, PA            Allegheny, PA            Beaver, PA               Berks, PA
                                             (420030093)              (420030116)              (420031008)              (420031301)              (420070014)              (420110011)
                                             Cambria, PA              Dauphin, PA              Lancaster, PA            York, PA                 Montgomery, TN           Milwaukee, WI
                                             (420210011)              (420430401)              (420710007)              (421330008)              (471251009)              (550790043)
Wisconsin......................          12  Cook, IL                 Cook, IL                 Cook, IL                 Cook, IL                 Cook, IL                 Cook, IL
                                             (170310052)              (170310057)              (170310076)              (170311016)              (170312001)              (170313103)
                                             Cook, IL                 Cook, IL                 Lake, IN                 Lake, IN                 Scott, IA                Wayne, MI
                                             (170313301)              (170316005)              (180890022)              (180890026)              (191630019)              (261630016)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------


                                                     Table IV.C-18--Upwind State to Downwind Maintenance Site ``Linkages'' for 24-Hour PM2.5
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                  Number of
          Upwind State            linkages
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                 ..........                                  Counties containing downwind 24-hour PM2.5 nonattainment sites (monitoring site ID)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Connecticut....................           1  New York, NY
                                             (360610062)
Delaware.......................           2  Cumberland, PA           New York, NY             .......................  .......................  .......................  ......................
                                             (420410101)              (360610079)
Georgia........................           3  Baltimore City, MD       Lucas, OH                Preble, OH               .......................  .......................  ......................
                                             (245100035)              (390950026)              (391351001)
Illinois.......................          29  District of Columbia     District of Columbia     Elkhart, IN              Floyd, IN                Vigo, IN                 Muscatine, IA
                                             (110010041)              (110010042)              (180390003)              (180431004)              (181670023)              (191390015)
                                             Bullitt, KY              McCracken, KY            Warren, KY               Wayne, MI                St. Louis City, MO       New York, NY
                                             (210290006)              (211451004)              (212270007)              (261630001)              (295100085)              (360610079)
                                             Cuyahoga, OH             Cuyahoga, OH             Jefferson, OH            Lucas, OH                Lucas, OH                Mahoning, OH
                                             (390350027)              (390350034)              (390810017)              (390950024)              (390950026)              (390990014)
                                             Montgomery, OH           Preble, OH               Trumbull, OH             Allegheny, PA            Allegheny, PA            Washington, PA
                                             (391130031)              (391351001)              (391550007)              (420030095)              (420033007)              (421255001)
                                             Sumner, TN               Brooke, WV               Dane, WI                 Milwaukee, WI            Waukesha, WI             ......................
                                             (471650007)              (540090005)              (550250047)              (550790059)              (551330027)
Indiana........................          34  District of Columbia     District of Columbia     Cook, IL                 Cook, IL                 Cook, IL                 Saint Clair, IL
                                             (110010041)              (110010042)              (170310022)              (170310050)              (170314007)              (171630010)
                                             Will, IL                 Muscatine, IA            Bullitt, KY              McCracken, KY            Warren, KY               Anne Arundel, MD
                                             (171971002)              (191390015)              (210290006)              (211451004)              (212270007)              (240031003)
                                             Wayne, MI                St. Louis City, MO       New York, NY             New York, NY             Cuyahoga, OH             Cuyahoga, OH
                                             (261630001)              (295100085)              (360610062)              (360610079)              (390350027)              (390350034)
                                             Jefferson, OH            Lucas, OH                Lucas, OH                Mahoning, OH             Montgomery, OH           Preble, OH
                                             (390810017)              (390950024)              (390950026)              (390990014)              (391130031)              (391351001)
                                             Trumbull, OH             Allegheny, PA            Allegheny, PA            Cumberland, PA           Washington, PA           Sumner, TN
                                             (391550007)              (420030095)              (420033007)              (420410101)              (421255001)              (471650007)
                                             Brooke, WV               Dane, WI                 Milwaukee, WI            Waukesha, WI             .......................  ......................
                                             (540090005)              (550250047)              (550790059)              (551330027)
Iowa...........................           9  Cook, IL                 Cook, IL                 Cook, IL                 Will, IL                 Elkhart, IN              St. Louis City, MO
                                             (170310022)              (170310050)              (170314007)              (171971002)              (180390003)              (295100085)

[[Page 45266]]


                                             Dane, WI                 Milwaukee, WI            Waukesha, WI             .......................  .......................  ......................
                                             (550250047)              (550790059)              (551330027)
Kansas.........................           2  Muscatine, IA            Milwaukee, WI            .......................  .......................  .......................  ......................
                                             (191390015)              (550790059)
Kentucky.......................          33  District of Columbia     District of Columbia     Cook, IL                 Cook, IL                 Cook, IL                 Saint Clair, IL
                                             (110010041)              (110010042)              (170310022)              (170310050)              (170314007)              (171630010)
                                             Will, IL                 Elkhart, IN              Floyd, IN                Vigo, IN                 Muscatine, IA            Anne Arundel, MD
                                             (171971002)              (180390003)              (180431004)              (181670023)              (191390015)              (240031003)
                                             Wayne, MI                St. Louis City, MO       New York, NY             New York, NY             Cuyahoga, OH             Cuyahoga, OH
                                             (261630001)              (295100085)              (360610062)              (360610079)              (390350027)              (390350034)
                                             Jefferson, OH            Lucas, OH                Lucas, OH                Mahoning, OH             Montgomery, OH           Preble, OH
                                             (390810017)              (390950024)              (390950026)              (390990014)              (391130031)              (391351001)
                                             Trumbull, OH             Allegheny, PA            Allegheny, PA            Washington, PA           Sumner, TN               Brooke, WV
                                             (391550007)              (420030095)              (420033007)              (421255001)              (471650007)              (540090005)
                                             Dane, WI                 Milwaukee, WI            Waukesha, WI             .......................  .......................  ......................
                                             (550250047)              (550790059)              (551330027)
Maryland.......................           5  District of Columbia     District of Columbia     New York, NY             New York, NY             Cumberland, PA           ......................
                                             (110010041)              (110010042)              (360610062)              (360610079)              (420410101)
Massachusetts..................           1  New York, NY             .......................  .......................  .......................  .......................  ......................
                                             (360610062)
Michigan.......................          28  District of Columbia     Cook, IL                 Cook, IL                 Cook, IL                 Saint Clair, IL          Will, IL
                                             (110010041)              (170310022)              (170310050)              (170314007)              (171630010)              (171971002)
                                             Elkhart, IN              Vigo, IN                 Muscatine, IA            Warren, KY               St. Louis City, MO       Cuyahoga, OH
                                             (180390003)              (181670023)              (191390015)              (212270007)              (295100085)              (390350027)
                                             Cuyahoga, OH             Jefferson, OH            Lucas, OH                Lucas, OH                Mahoning, OH             Montgomery, OH
                                             (390350034)              (390810017)              (390950024)              (390950026)              (390990014)              (391130031)
                                             Preble, OH               Trumbull, OH             Allegheny, PA            Allegheny, PA            Washington, PA           Sumner, TN
                                             (391351001)              (391550007)              (420030095)              (420033007)              (421255001)              (471650007)
                                             Brooke, WV               Dane, WI                 Milwaukee, WI            Waukesha, WI             .......................  ......................
                                             (540090005)              (550250047)              (550790059)              (551330027)
Minnesota......................           4  Muscatine, IA            Dane, WI                 Milwaukee, WI            Waukesha, WI             .......................  ......................
                                             (191390015)              (550250047)              (550790059)              (551330027)
Missouri.......................          20  Cook, IL                 Cook, IL                 Cook, IL                 Saint Clair, IL          Will, IL                 Elkhart, IN
                                             (170310022)              (170310050)              (170314007)              (171630010)              (171971002)              (180390003)
                                             Floyd, IN                Vigo, IN                 Muscatine, IA            Bullitt, KY              McCracken, KY            Warren, KY
                                             (180431004)              (181670023)              (191390015)              (210290006)              (211451004)              (212270007)
                                             Jefferson, OH            Lucas, OH                Montgomery, OH           Preble, OH               Sumner, TN               Dane, WI
                                             (390810017)              (390950026)              (391130031)              (391351001)              (471650007)              (550250047)
                                             Milwaukee, WI            Waukesha, WI             .......................  .......................  .......................  ......................
                                             (550790059)              (551330027)
Nebraska.......................           2  Muscatine, IA            Milwaukee, WI            .......................  .......................  .......................  ......................
                                             (191390015)              (550790059)
New Jersey.....................           5  District of Columbia     Anne Arundel, MD         New York, NY             New York, NY             Cumberland, PA           ......................
                                             (110010041)              (240031003)              (360610062)              (360610079)              (420410101)
New York.......................           9  District of Columbia     District of Columbia     Anne Arundel, MD         Baltimore City, MD       Cuyahoga, OH             Cuyahoga, OH
                                             (110010041)              (110010042)              (240031003)              (245100035)              (390350027)              (390350034)
                                             Lucas, OH                Lucas, OH                Cumberland, PA           .......................  .......................  ......................
                                             (390950024)              (390950026)              (420410101)
North Carolina.................           3  Baltimore City, MD       New York, NY             New York, NY             .......................  .......................  ......................
                                             (245100035)              (360610062)              (360610079)
Ohio...........................          29  District of Columbia     District of Columbia     Cook, IL                 Cook, IL                 Cook, IL                 Saint Clair, IL
                                             (110010041)              (110010042)              (170310022)              (170310050)              (170314007)              (171630010)
                                             Will, IL                 Elkhart, IN              Floyd, IN                Vigo, IN                 Muscatine, IA            Bullitt, KY
                                             (171971002)              (180390003)              (180431004)              (181670023)              (191390015)              (210290006)
                                             McCracken, KY            Warren, KY               Anne Arundel, MD         Baltimore City, MD       Wayne, MI                St. Louis City, MO
                                             (211451004)              (212270007)              (240031003)              (245100035)              (261630001)              (295100085)
                                             New York, NY             New York, NY             Allegheny, PA            Allegheny, PA            Cumberland, PA           Washington, PA
                                             (360610062)              (360610079)              (420030095)              (420033007)              (420410101)              (421255001)
                                             Sumner, TN               Brooke, WV               Dane, WI                 Milwaukee, WI            Waukesha, WI             ......................
                                             (471650007)              (540090005)              (550250047)              (550790059)              (551330027)
Pennsylvania...................          32  District of Columbia     District of Columbia     Cook, IL                 Cook, IL                 Cook, IL                 Saint Clair, IL
                                             (110010041)              (110010042)              (170310022)              (170310050)              (170314007)              (171630010)
                                             Will, IL                 Elkhart, IN              Floyd, IN                Vigo, IN                 Muscatine, IA            Bullitt, KY
                                             (171971002)              (180390003)              (180431004)              (181670023)              (191390015)              (210290006)
                                             Warren, KY               Anne Arundel, MD         Baltimore City, MD       Wayne, MI                New York, NY             New York, NY
                                             (212270007)              (240031003)              (245100035)              (261630001)              (360610062)              (360610079)
                                             Cuyahoga, OH             Cuyahoga, OH             Jefferson, OH            Lucas, OH                Lucas, OH                Mahoning, OH
                                             (390350027)              (390350034)              (390810017)              (390950024)              (390950026)              (390990014)
                                             Montgomery, OH           Preble, OH               Trumbull, OH             Sumner, TN               Brooke, WV               Dane, WI
                                             (391130031)              (391351001)              (391550007)              (471650007)              (540090005)              (550250047)

[[Page 45267]]


                                             Milwaukee, WI            Waukesha, WI             .......................  .......................  .......................  ......................
                                             (550790059)              (551330027)
Tennessee......................          21  Cook, IL                 Saint Clair, IL          Will, IL                 Elkhart, IN              Floyd, IN                Vigo, IN
                                             (170314007)              (171630010)              (171971002)              (180390003)              (180431004)              (181670023)
                                             Muscatine, IA            Bullitt, KY              McCracken, KY            Warren, KY               Wayne, MI                St. Louis City, MO
                                             (191390015)              (210290006)              (211451004)              (212270007)              (261630001)              (295100085)
                                             Jefferson, OH            Lucas, OH                Lucas, OH                Mahoning, OH             Montgomery, OH           Preble, OH
                                             (390810017)              (390950024)              (390950026)              (390990014)              (391130031)              (391351001)
                                             Trumbull, OH             Allegheny, PA            Washington, PA           .......................  .......................  ......................
                                             (391550007)              (420033007)              (421255001)
Virginia.......................           7  District of Columbia     District of Columbia     Anne Arundel, MD         Baltimore City, MD       New York, NY             New York, NY
                                             (110010041)              (110010042)              (240031003)              (245100035)              (360610062)              (360610079)
                                             Cumberland, PA           .......................  .......................  .......................  .......................  ......................
                                             (420410101)
West Virginia..................          35  District of Columbia     District of Columbia     Cook, IL                 Cook, IL                 Saint Clair, IL          Will, IL
                                             (110010041)              (110010042)              (170310050)              (170314007)              (171630010)              (171971002)
                                             Elkhart, IN              Floyd, IN                Vigo, IN                 Muscatine, IA            Bullitt, KY              Warren, KY
                                             (180390003)              (180431004)              (181670023)              (191390015)              (210290006)              (212270007)
                                             Anne Arundel, MD         Baltimore City, MD       Wayne, MI                St. Louis City, MO       New York, NY             New York, NY
                                             (240031003)              (245100035)              (261630001)              (295100085)              (360610062)              (360610079)
                                             Cuyahoga, OH             Cuyahoga, OH             Jefferson, OH            Lucas, OH                Lucas, OH                Mahoning, OH
                                             (390350027)              (390350034)              (390810017)              (390950024)              (390950026)              (390990014)
                                             Montgomery, OH           Preble, OH               Trumbull, OH             Allegheny, PA            Allegheny, PA            Cumberland, PA
                                             (391130031)              (391351001)              (391550007)              (420030095)              (420033007)              (420410101)
                                             Washington, PA           Sumner, TN               Dane, WI                 Milwaukee, WI            Waukesha, WI             ......................
                                             (421255001)              (471650007)              (550250047)              (550790059)              (551330027)
Wisconsin......................           6  Cook, IL                 Cook, IL                 Cook, IL                 Will, IL                 Elkhart, IN              Muscatine, IA
                                             (170310022)              (170310050)              (170314007)              (171971002)              (180390003)              (191390015)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

b. Results of 8-Hour Ozone Contribution Modeling
    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 IV.B., 
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 performed air quality modeling to 
quantify the contributions to 8-hour ozone from emissions in each of 
the following 37 states individually: Alabama, Arkansas, Connecticut, 
Delaware, Florida, Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky, 
Louisiana, Maine, Maryland combined with the District of Columbia, 
Massachusetts, Michigan, Minnesota, Mississippi, Missouri, Nebraska, 
New Hampshire, New Jersey, New York, North Carolina, North Dakota, 
Ohio, Oklahoma, Pennsylvania, Rhode Island, South Carolina, South 
Dakota, Tennessee, Texas, Vermont, Virginia, West Virginia, and 
Wisconsin.
    We calculated each state's contribution to each of the 11 
monitoring sites that are projected to be nonattainment and each of 14 
\53\ sites that are projected to have maintenance problems for the 8-
hour ozone NAAQS in the 2012 Base Case. The largest contribution from 
each state to 8-hour ozone nonattainment in downwind sites is provided 
in Table IV.C-19. The largest contribution from each state to 8-hour 
ozone maintenance in downwind sites is also provided in Table IV.C-19. 
The contributions from each state to all projected 2012 nonattainment 
and maintenance sites for the 8-hour ozone NAAQS are provided in the 
AQMTSD.
---------------------------------------------------------------------------

    \53\ For two of the 16 projected maintenance sites (Harris Co., 
Texas sites 482011015 and 482011035) there were less than 5 days 
with 8-hour ozone predictions of at least 70 ppb. Thus, we did not 
calculate contributions for these two maintenance sites.

      Table IV.C-19--Largest Contribution to Downwind 8-Hour Ozone
           Nonattainment and Maintenance for Each of 37 States
------------------------------------------------------------------------
                                              Largest
                                             downwind         Largest
                                           contribution      downwind
              Upwind State                      to         contribution
                                           nonattainment  to maintenance
                                             for ozone       for ozone
                                               (ppb)           (ppb)
------------------------------------------------------------------------
Alabama.................................             4.7             4.7
Arkansas................................             1.4             1.8
Connecticut.............................             1.7             1.6
Delaware................................             3.3             2.5
Florida.................................             0.8             2.1
Georgia.................................             2.1             1.7

[[Page 45268]]


Illinois................................             0.8             0.6
Indiana.................................             1.1             1.0
Iowa....................................             0.3             0.3
Kansas..................................             0.6             0.8
Kentucky................................             2.3             1.8
Louisiana...............................            11.4            10.6
Maine...................................             0.0             0.0
Maryland/Washington, DC.................             6.1             4.2
Massachusetts...........................             0.6             0.5
Michigan................................             0.9             0.5
Minnesota...............................             0.1             0.2
Mississippi.............................             5.2             2.5
Missouri................................             0.7             0.6
Nebraska................................             0.2             0.2
New Hampshire...........................             0.1             0.1
New Jersey..............................            16.8            15.8
New York................................             0.4            22.7
North Carolina..........................             1.7             2.0
North Dakota............................             0.1             0.0
Ohio....................................             2.8             2.6
Oklahoma................................             2.1             2.7
Pennsylvania............................             8.9             8.1
Rhode Island............................             0.1             0.1
South Carolina..........................             0.6             0.8
South Dakota............................             0.0             0.0
Tennessee...............................             1.6             3.0
Texas...................................             1.6             0.6
Vermont.................................             0.0             0.1
Virginia................................             4.2             4.5
West Virginia...........................             2.7             2.3
Wisconsin...............................             0.3             0.2
------------------------------------------------------------------------

    Based on the state-by-state contribution analysis, there are 22 
states and the District of Columbia \54\ which contribute 0.8 ppb or 
more to downwind 8-hour ozone nonattainment. These states are: Alabama, 
Arkansas, Connecticut, Delaware, the District of Columbia, Florida, 
Georgia, Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, 
Mississippi, New Jersey, North Carolina, Ohio, Oklahoma, Pennsylvania, 
Tennessee, Texas, Virginia, and West Virginia. In Table IV.C-20, 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'').
---------------------------------------------------------------------------

    \54\ As noted above, we combined Maryland and the District of 
Columbia as a single entity in our contribution modeling. This is a 
logical approach because of the small size of the District of 
Columbia and, hence, its emissions and its close proximity to 
Maryland. Under our analysis, Maryland and the District of Columbia 
are linked as significant contributors to the same downwind 
nonattainment counties.
---------------------------------------------------------------------------

    There are 22 states and the District of Columbia which contribute 
0.8 ppb or more to downwind 8-hour ozone maintenance. These states are: 
Alabama, Arkansas, Connecticut, Delaware, the District of Columbia, 
Florida, Georgia, Indiana, Kansas, Kentucky, Louisiana, Maryland, 
Mississippi, New Jersey, New York, North Carolina, Ohio, Oklahoma, 
Pennsylvania, South Carolina, Tennessee, Virginia, and West Virginia. 
In Table IV.C-21, 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'').

                                                       Table IV.C-20--Upwind State to Downwind Nonattainment ``Linkages'' for 8-Hour Ozone
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                  Number of
          Upwind State            linkages
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                 ..........                                  Counties containing downwind 24-hour PM2.5 nonattainment sites (monitoring site ID)
                                            ----------------------------------------------------------------------------------------------------------------------------------------------------
Alabama........................           8  East Baton Rouge, LA     Brazoria, TX             Harris, TX               Harris, TX               Harris, TX               Harris, TX
                                             (220330003)              (480391004)              (482010051)              (482010055)              (482010062)              (482010066)
                                 ..........  Harris, TX               Tarrant, TX
                                             (482011039)              (484391002)
Arkansas.......................           3  East Baton Rouge, LA     Brazoria, TX             Tarrant, TX
                                             (220330003)              (480391004)              (484391002)

[[Page 45269]]


Connecticut....................           1  Suffolk, NY
                                             (361030009)
Delaware.......................           3  Suffolk, NY              Suffolk, NY              Philadelphia, PA
                                             (361030002)              (361030009)              (421010024)
Florida........................           2  Harris, TX               Tarrant, TX
                                             (482010062)              (484391002)
Georgia........................           7  Brazoria, TX             Harris, TX               Harris, TX               Harris, TX               Harris, TX               Harris, TX
                                             (480391004)              (482010051)              (482010055)              (482010062)              (482010066)              (482011039)
                                 ..........  Tarrant, TX
                                             (484391002)
Illinois.......................           2  Suffolk, NY              Harris, TX
                                             (361030009)              (482010055)
Indiana........................           3  Suffolk, NY              Suffolk, NY              Philadelphia, PA
                                             (361030002)              (361030009)              (421010024)
Kentucky.......................           6  Suffolk, NY              Philadelphia, PA         Harris, TX               Harris, TX               Harris, TX               Harris, TX
                                             (361030002)              (421010024)              (482010051)              (482010055)              (482010062)              (482011039)
Louisiana......................           7  Brazoria, TX             Harris, TX               Harris, TX               Harris, TX               Harris, TX               Harris, TX
                                             (480391004)              (482010051)              (482010055)              (482010062)              (482010066)              (482011039)
                                 ..........  Tarrant, TX
                                             (484391002)
Maryland.......................           3  Suffolk, NY              Suffolk, NY              Philadelphia, PA
                                             (361030002)              (361030009)              (421010024)
Michigan.......................           1  Suffolk, NY
                                             (361030009)
Mississippi....................           8  East Baton Rouge, LA     Brazoria, TX             Harris, TX               Harris, TX               Harris, TX               Harris, TX
                                             (220330003)              (480391004)              (482010051)              (482010055)              (482010062)              (482010066)
                                 ..........  Harris, TX               Tarrant, TX
                                             (482011039)              (484391002)
New Jersey.....................           3  Suffolk, NY              Suffolk, NY              Philadelphia, PA
                                             (361030002)              (361030009)              (421010024)
North Carolina.................           3  Suffolk, NY              Suffolk, NY              Philadelphia, PA
                                             (361030002)              (361030009)              (421010024)
Ohio...........................           3  Suffolk, NY              Suffolk, NY              Philadelphia, PA
                                             (361030002)              (361030009)              (421010024)
Oklahoma.......................           1  Tarrant, TX
                                             (484391002)
Pennsylvania...................           2  Suffolk, NY              Suffolk, NY
                                             (361030002)              (361030009)
Tennessee......................           7  Philadelphia, PA         Brazoria, TX             Harris, TX               Harris, TX               Harris, TX               Harris, TX
                                             (421010024)              (480391004)              (482010051)              (482010055)              (482010062)              (482010066)
                                 ..........  Harris, TX
                                             (482011039)
Texas..........................           1  East Baton Rouge, LA
                                             (220330003)
Virginia.......................           3  Suffolk, NY              Suffolk, NY              Philadelphia, PA
                                             (361030002)              (361030009)              (421010024)
West Virginia..................           3  Suffolk, NY              Suffolk, NY              Philadelphia, PA
                                             (361030002)              (361030009)              (421010024)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------


                                                        Table IV.C-21--Upwind State to Downwind Maintenance ``Linkages'' for 8-Hour Ozone
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                  Number of
          Upwind State            linkages
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                 ..........                                  Counties containing downwind 24-hour PM2.5 nonattainment sites (monitoring site ID)
                                            ----------------------------------------------------------------------------------------------------------------------------------------------------
Alabama........................           6  DeKalb, GA               Fulton, GA               Harris, TX               Harris, TX               Harris, TX               Tarrant, TX.
                                             (130890002)              (131210055)              (482010024)              (482010029)              (482011050)              (484392003).
Arkansas.......................           4  Dallas, TX               Dallas, TX               Harris, TX               Tarrant, TX
                                             (481130069)              (481130087)              (482011050)              (484392003)
Connecticut....................           1  Westchester, NY
                                             (361192004)
Delaware.......................           1  Bucks, PA
                                             (420170012)
Florida........................           4  DeKalb, GA               Fulton, GA               Harris, TX               Harris, TX
                                             (130890002)              (131210055)              (482010024)              (482010029)
Georgia........................           4  Harris, TX               Harris, TX               Harris, TX               Tarrant, TX
                                             (482010024)              (482010029)              (482011050)              (484392003)
Indiana........................           4  Fairfield, CT            New Haven, CT            Westchester, NY          Bucks, PA
                                             (90010017)               (90093002)               (361192004)              (420170012)
Kansas.........................           1  Dallas, TX
                                             (481130069)
Kentucky.......................           6  Fairfield, CT            Fairfield, CT            Fairfield, CT            New Haven, CT            Westchester, NY          Bucks, PA.
                                             (90010017)               (90011123)               (90013007)               (90093002)               (361192004)              (420170012).

[[Page 45270]]


Louisiana......................           6  Dallas, TX               Dallas, TX               Harris, TX               Harris, TX               Harris, TX               Tarrant, TX.
                                             (481130069)              (481130087)              (482010024)              (482010029)              (482011050)              (484392003).
Maryland.......................           6  Fairfield, CT            Fairfield, CT            Fairfield, CT            New Haven, CT            Westchester, NY          Bucks, PA.
                                             (90010017)               (90011123)               (90013007)               (90093002)               (361192004)              (420170012).
Mississippi....................           7  DeKalb, GA               Fulton, GA               Dallas, TX               Harris, TX               Harris, TX               Harris, TX.
                                             (130890002)              (131210055)              (481130087)              (482010024)              (482010029)              (482011050).
                                 ..........  Tarrant, TX
                                             (484392003)
New Jersey.....................           6  Fairfield, CT            Fairfield, CT            Fairfield, CT            New Haven, CT            Westchester, NY          Bucks, PA.
                                             (90010017)               (90011123)               (90013007)               (90093002)               (361192004)              (420170012).
New York.......................           5  Fairfield, CT            Fairfield, CT            Fairfield, CT            New Haven, CT            Bucks, PA
                                             (90010017)               (90011123)               (90013007)               (90093002)               (420170012)
North Carolina.................           5  Fairfield, CT            Fairfield, CT            New Haven, CT            Westchester, NY          Bucks, PA
                                             (90011123)               (90013007)               (90093002)               (361192004)              (420170012)
Ohio...........................           6  Fairfield, CT            Fairfield, CT            Fairfield, CT            New Haven, CT            Westchester, NY          Bucks, PA.
                                             (90010017)               (90011123)               (90013007)               (90093002)               (361192004)              (420170012).
Oklahoma.......................           3  Dallas, TX               Dallas, TX               Tarrant, TX
                                             (481130069)              (481130087)              (484392003)
Pennsylvania...................           5  Fairfield, CT            Fairfield, CT            Fairfield, CT            New Haven, CT            Westchester, NY
                                             (90010017)               (90011123)               (90013007)               (90093002)               (361192004)
South Carolina.................           2  Fulton, GA               Harris, TX
                                             (131210055)              (482010029)
Tennessee......................           5  DeKalb, GA               Fulton, GA               Bucks, PA                Harris, TX               Harris, TX
                                             (130890002)              (131210055)              (420170012)              (482010024)              (482011050)
Virginia.......................           6  Fairfield, CT            Fairfield, CT            Fairfield, CT            New Haven, CT            Westchester, NY          Bucks, PA.
                                             (90010017)               (90011123)               (90013007)               (90093002)               (361192004)              (420170012).
West Virginia..................           6  Fairfield, CT            Fairfield, CT            Fairfield, CT            New Haven, CT            Westchester, NY          Bucks, PA.
                                             (90010017)               (90011123)               (90013007)               (90093002)               (361192004)              (420170012).
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

D. Proposed Methodology To Quantify Emissions That Significantly 
Contribute or Interfere With Maintenance

    In this section, EPA explains its general approach to quantifying 
the amount of emissions that represent significant contribution and 
interference with maintenance. EPA then applies that approach for the 
three different NAAQS being addressed in today's notice: The 1997 ozone 
NAAQS, the 1997 annual PM2.5 NAAQS and the 2006 24-hour 
PM2.5 NAAQS.
    With respect to the 1997 ozone NAAQS, we apply this methodology to 
fully quantify the significant contribution and interference with 
maintenance for 16 states. We also use the methodology to quantify, for 
10 additional states, NOX emissions reductions that are 
necessary to make measurable progress towards eliminating their 
significant contribution and interference with maintenance. Additional 
information gathering and analysis is needed to determine the extent to 
which further reductions from these states may be needed to fully 
eliminate significant contribution and interference with maintenance 
with the ozone NAAQS. As is further explained in section IV.D.2.b EPA 
will fully address this issue in a future rulemaking as quickly as 
possible.
    With respect to the annual PM2.5 NAAQS, this proposal 
finds that 24 eastern states have SO2 and NOX 
emission reduction responsibilities. We apply the proposed methodology 
to fully quantify the SO2 and NOX emissions from 
each of these states that significantly contribute to or interfere with 
maintenance in downwind areas.
    With respect to the 24-hour PM2.5 NAAQS, this proposal 
finds that 25 eastern states have emission reduction responsibilities. 
We use the proposed methodology to quantify emissions reductions that 
these states must achieve to make, at a minimum, measurable progress 
towards eliminating the state's significant contribution and 
interference with maintenance. Further analysis will be needed to 
determine if these reductions are sufficient to fully eliminate any or 
all of these states' significant contribution and interference with 
maintenance for purposes of the 24-hour PM2.5 standard. As 
is explained in greater detail in section IV.D.2.a, EPA intends to 
finalize, to the extent possible a determination of the complete amount 
of emissions that represents significant contribution and interference 
with maintenance. If further analysis shows that the amounts of 
emissions proposed in today's notice include all emissions that 
significantly contribute or interfere with maintenance of the 24-hour 
PM2.5 standard or that more SO2 emissions should 
be included, we believe that we will be able to issue a supplemental 
proposal and finalize a rule fully quantifying significant contribution 
and interference with maintenance with respect to the 24-hour 
PM2.5 standard. If further analysis shows that other 
reductions should be considered as part of significant contribution or 
interference with maintenance with respect to the 24-hour 
PM2.5 standard these emissions would be fully addressed in a 
separate rulemaking effort.
1. Explanation of Proposed Approach To Quantify Significant 
Contribution
    After using air quality analysis to identify upwind states that are 
``linked'' to downwind air quality monitoring sites with nonattainment 
and maintenance problems because the upwind states' emissions 
contribute one percent or more to the air quality value at the downwind 
site, EPA quantifies the portion of each state's contribution that 
constitutes its ``significant contribution'' and ``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 and interference with maintenance with respect 
to the PM2.5 NAAQS and the ozone NAAQS. For this portion of 
the analysis, EPA expands upon the methodology used in the 
NOX SIP Call and CAIR, but modifies it in significant 
respects. In the NOX SIP Call and CAIR, EPA's

[[Page 45271]]

methodology relied upon defining significant contribution as those 
emissions that could be removed with the use of ``highly cost 
effective'' controls. In this action, rather than relying solely on 
determining reductions based on ``highly cost effective'' controls, EPA 
uses a number of factors that account for both cost and air quality 
improvement. Furthermore, unlike the NOX SIP Call and CAIR 
where EPA only defined an amount of reductions needed to address 
significant contribution to nonattainment, EPA is proposing to define 
an amount of emissions reductions that addresses both significant 
contribution to nonattainment and interference with maintenance.
    The methodology takes into account both the DC 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.
    The methodology defines each state's significant contribution and 
interference with maintenance as the emissions that can be eliminated 
for a specific cost. Unlike the NOX SIP Call and CAIR, where 
EPA's significant contribution analysis had a regional focus, the 
methodology used in today's proposal 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.
    In step one, EPA identifies what emissions reductions are available 
at various costs, quantifying emissions reductions that would occur 
within each state at ascending costs per ton of emissions reductions. 
For purposes of this discussion, we refer to these as ``cost curves''.
    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 state, at different cost-per-ton 
levels, would have on air quality at downwind monitor sites that had 
nonattainment and/or maintenance problems.
    In step three, EPA examines cost and air quality information to 
identify cost ``breakpoints.'' Breakpoints are the places where there 
is a noticeable change on one of the cost curves, such as a point where 
a large reduction occurs because a certain type of emissions control 
becomes cost-effective. EPA then uses a multi-factor assessment to 
determine the amount of emissions that represents significant 
contribution to nonattainment and interference with maintenance. The 
factors considered include both the air quality and cost considerations 
used in developing the breakpoints along with additional air quality 
and cost considerations. This assessment is performed for each 
transported NAAQS pollutant or precursor which EPA has concluded must 
be regulated due to its impact on downwind receptors. In this rule, as 
discussed in section IV.B, EPA is proposing to regulate SO2 
and NOX. The methodology also allows EPA, where appropriate, 
to define multiple cost thresholds that vary for a particular pollutant 
for different upwind states.
    In step four, EPA quantifies the emissions reductions available in 
each ``linked'' state at the appropriate cost threshold. This 
information is then used to develop a state ``budget,'' representing 
the remaining emissions for the state in an average year, and to 
identify a variability limit associated with that budget. These budgets 
and variability limits are used to develop enforceable requirements 
under the proposed and two alternative remedy options. State emissions 
budgets are discussed in section IV.E and the variability limit is 
discussed in section IV.F.
    EPA's proposed methodology considers both cost and air quality 
factors to address complex circumstances. We believe it is important to 
consider both factors because circumstances related to different 
downwind receptors can vary and consideration of multiple factors can 
help EPA appropriately identify each state's significant contribution 
under different circumstances. For instance, there may be cases when 
upwind states contributing to a specific downwind nonattainment area 
have already done a great deal to reduce emissions while the downwind 
state in which the nonattainment area is located has done very little. 
Conversely, the downwind state may have made large reductions while one 
or more contributing upwind states may have done very little. There may 
be cases where some states (upwind or downwind) have large emissions 
(and a correspondingly large impact downwind) not because their sources 
are poorly controlled, but because they have a greater number of 
sources--the operation of which is critical to the reliability of the 
electric grid. Conversely, there may be cases where a state (upwind or 
downwind) contributes less in total emissions because it has a smaller 
number of plants, but those plants are poorly controlled and could be 
better controlled at a relatively low cost.
    Air quality factors alone are not able to discern these types of 
differences. 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. 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 emissions 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 interfere 
with maintenance in another state, but does not shift the 
responsibility for achieving or maintaining the NAAQS to the upwind 
state.
    In developing and implementing this methodology, EPA was cognizant 
of a number of factors. First, in many areas, transported emissions are 
a key component of the downwind air quality problem. Second, there are 
large amounts of low cost emission reduction opportunities in upwind 
states. Third, EPA recognizes that section 110(a)(2)(D) does not grant 
EPA authority to require emissions reductions solely because they 
provide large health and environmental benefits: reductions required 
pursuant to section 110(a)(2)(D)(i)(I) must be related to the goal of 
eliminating upwind state emissions that significantly contribute to 
nonattainment or interfere with maintenance of the NAAQS in downwind 
areas.
    Fourth, EPA is cognizant of the relationship between the upwind and 
downwind state requirements in the Act. The Act requires upwind states 
to eliminate significant interstate pollution transport under section 
110(a)(2)(D). It also requires each state to assure attainment and 
maintenance of the NAAQS within its borders. Thus, a downwind state 
must adopt controls to demonstrate timely attainment of the NAAQS 
despite any pollution transport from upwind states that is not 
eliminated under section 110(a)(2)(D).

[[Page 45272]]

Given this structure, interpreting significant contribution and 
interfere with maintenance inherently involves a policy decision on how 
much emissions control responsibility should be assigned to upwind 
states, and how much responsibility should be left to downwind states. 
In virtually all areas, PM2.5 and ozone problems result from 
a combination of local, in-state, and upwind state emissions. EPA's 
proposed methodology for determining what portion of a state's total 
contribution is its significant contribution and interference with 
maintenance is intended to assign a substantial but reasonable amount 
of responsibility to upwind states.
    There are several reasons that EPA believes upwind state sources 
contributing to air quality degradation in a downwind state should bear 
substantial responsibility to control their emissions. First, the plain 
language of this good neighbor provision requires upwind states to 
prohibit emissions that significantly contribute to nonattainment or 
interfere with maintenance in a downwind state. Second, interstate 
pollution transport increases pollution levels and health risks in the 
downwind state. Third, the influx of pollution from upwind states 
raises the pollution level in a downwind state, making it necessary for 
the downwind state to obtain deeper pollution reductions to attain and 
maintain air quality standards, which increases costs of control in the 
downwind state. Fourth, from the standpoint of a downwind state, the 
pollution contribution of each upwind state adds up to a larger, 
cumulative degradation of the downwind state's air quality. Fifth, 
reducing interstate pollution enhances prospects that attainment in 
downwind states can be achieved within the Act's deadlines and as 
expeditiously as practicable. All of these points support the position 
that upwind state sources should bear substantial responsibility to 
control their emissions.
    On the other hand, the proposed methodology ensures that upwind 
states are not required to shoulder the entire responsibility for the 
downwind state's attainment and maintenance of the NAAQS. Among other 
things, our methodology implicitly assumes controls at the same cost 
per ton level in the downwind state as in the upwind contributing 
states.\55\ In addition, in almost all cases, states with downwind 
nonattainment and maintenance areas are also required to reduce 
emissions based on the fact that they are also upwind states that are 
``linked'' to other downwind states with nonattainment and maintenance 
problems.
---------------------------------------------------------------------------

    \55\ We also recognize that there can be reasons to depart from 
an equal cost per ton allocation of responsibility before a 
receptor's attainment and maintenance problem is fully resolved, 
such as when a receptor's air quality problem has an unusually high 
local component.
---------------------------------------------------------------------------

    The proposed methodology also directly ties each state's reduction 
requirements to EPA's analysis of that state's significant contribution 
and interference with maintenance. The required reductions would 
provide very substantial air quality improvements. For the annual 
PM2.5 standard, EPA projects that this rule will help assure 
that all but one area in the East attain the standard by 2014. It will 
also help a number of areas achieve the standard earlier. The 
methodology provides similar assistance for ozone, assuring upwind 
reductions that will mitigate the amount that downwind states may need 
to do. It reduces ozone concentration levels in 2012 and helps assure 
that even absent this additional local control, all but 3 areas' 
nonattainment and maintenance problems are resolved by 2014. Air 
quality in the few areas with remaining problems will be improved, 
providing both health benefits and assistance for these local areas in 
meeting the NAAQS requirements.
a. Step 1. Emissions Reductions Cost Curves
    The first step in EPA's methodology for determining the quantity of 
emissions that represents each state's significant contribution is to 
identify reductions available at different costs. To do so, EPA 
developed a set of cost curves that show, at various cost increments, 
the available emissions reductions for EGUs in a state. In other words, 
EPA determined for specific cost per ton thresholds, the emissions 
reductions that would be achieved in a state if all EGUs in that state 
used all emission controls and emission reduction measures available at 
that cost threshold. The zero point of the curve shows what emissions 
would occur absent any additional investment in emissions reductions 
(i.e., the base case emissions). Additional points on the curves show 
the emissions that would occur after the installation of all controls 
that could be installed at specific cost levels (dollars per ton of 
emissions reduced). In developing these cost curves, EPA used IPM to 
identify costs for reducing emissions from EGUs by modeling emissions 
reductions available at multiple cost increments. EPA also applied the 
same cost constraint for each state in each modeling iteration. For 
example, in one iteration, all covered sources in the states examined 
were constrained to emit at levels achievable by the application of all 
controls available for $100/ton. In a second iteration, all states 
examined were assumed to achieve all reductions in each state that were 
available at $200/ton. The resulting cost curves for SO2 and 
annual NOX can be found in section IV.D.2.a of this preamble 
and the curves for ozone season NOX in section IV.D.2.b. For 
more detail on the development of the cost curves, see the TSD, 
``Analysis to Quantify Significant Contribution,'' in the docket for 
this rule.
    Although the cost curves presented in this proposal only include 
EGU reductions, EPA also conducted a preliminary assessment of 
reductions available for source categories other than EGUs. This 
preliminary assessment suggested that there likely would be very large 
emissions reductions available from EGUs before costs reach the point 
for which non-EGU sources have available reductions. EPA therefore 
initially created cost curves based solely on reductions from EGUs and 
determined appropriate cost thresholds based on that analysis. EPA then 
re-examined non-EGUs to determine the accuracy of its initial 
assumptions that there were little or no reductions available from non-
EGUs at costs lower than the thresholds that EPA had chosen. EPA's 
analysis of the costs of and opportunities for non-EGU emissions 
reductions is discussed in more detail in section IV.D.3, later. For 
the reasons explained in that section, EPA believes there are little or 
no non-EGU reductions available at the cost thresholds used in this 
rule. Therefore, EPA believes it is reasonable at this time to use cost 
curves that include only EGU reductions. However, EPA is continuing to 
conduct analyses and believes that it will be necessary to further 
consider non-EGU emission reduction opportunities in future transport 
rules.
    To develop cost curves, emissions available at various costs were 
assessed in 2012 for ozone season NOX and 2014 for annual 
NOX and SO2. As described in section V.C, EPA 
coordinated the deadlines for eliminating significant contribution and 
interference with maintenance with the NAAQS attainment deadlines for 
downwind states and determined that all significant contribution and 
interference with maintenance with respect to the 1997 and 2006 
PM2.5 NAAQS must be eliminated by 2014, or as expeditiously 
as practicable. The cost curves show, among other things, that the 
amount of emissions reductions that can be achieved for a given cost 
varies over

[[Page 45273]]

time. This is true because, among other things, control options that 
are available in a longer timeframe may not be available in a shorter 
timeframe. For instance, it takes approximately 27 months to build a 
flue gas desulfurization unit (FGD, or ``scrubber'') to reduce 
SO2 emissions (Boilermaker Labor Analysis and Installation 
Timing, USEPA, March 2005), so if this rule is finalized in mid-2011, 
emissions reductions from scrubbers by 2012 or 2013 can only reasonably 
be achieved if that scrubber either exists today, or if it is currently 
under construction. However, by 2014, additional reductions could be 
obtained from the construction of new scrubbers. It takes approximately 
21 months to construct a selective catalytic reduction (SCR) unit to 
reduce emissions of NOX. (Boilermaker Labor Analysis and 
Installation Timing, USEPA, March 2005).
    There are approximately 30 months between mid-2011 (when the Agency 
anticipates finalizing this rule) and January 2014 (the proposed Phase 
2 compliance deadline). EPA believes this is sufficient time for 
sources to install the advanced emissions controls projected to be 
retrofit. EPA expects about 14 GW of FGD and less than 1 GW of SCR 
capacity to be retrofit for Phase 2 of this rule. This is significantly 
less than the capacity that was retrofit in the same length of time 
after CAIR was finalized. EPA is not aware of problems or issues with 
sources meeting the CAIR compliance deadlines, either in equipment 
deliveries or labor availability. EPA believes the proposed Transport 
Rule compliance deadlines are reasonable, and will result in emissions 
reductions as quickly as practicable, delivering health benefits to the 
public and aiding states with NAAQS attainment deadlines.
    EPA requests comment on the schedule for scrubber and SCR 
installations, the availability of boilermaker labor, and any comment 
on whether there might be alternative post-combustion cost-effective 
technologies that could reduce SO2 and/or NOX 
emissions. We also solicit comment on whether advanced coal preparation 
processes might provide emissions reductions at the significant 
contribution cost levels identified in this proposal, whether such 
processes have been commercialized, and what the costs will be. In 
addition, EPA seeks comment on, whether other factors, such as other 
EPA regulatory actions, will create an increase in boilermaker demand 
earlier than today's proposal, in 2010 and beyond. We solicit comments 
on whether other factors might increase demand for boilermakers or 
control equipment, and what these factors would be. Comments in support 
of or opposed to the proposed compliance deadlines should include 
information to support the commenter's position.
    Unlike add-on pollution controls such as scrubbers and SCRs, EPA 
believes that low-NOX burners could be installed by 2012. 
See TSD, ``Installation Timing for Low NOX Burners,'' in the 
docket for this rule.
    EPA also believes that sources can switch coals by 2012. Eastern 
bituminous coals used for power generation typically have more than 
sufficient sulfur content to facilitate highly efficient collection of 
fly ash in 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. Relatively inexpensive 
practices to maintain high ESP performance on lower sulfur bituminous 
coals are available and are being used successfully where necessary. 
These include a range of upgrades to ESP components and flue gas 
conditioning.
    EPA assumes in the Transport Rule analysis that it will not be 
necessary for units that switch from higher to lower sulfur bituminous 
to make a costly replacement of the ESP. EPA's analysis therefore does 
not add capital or operations and maintenance costs for coal switching 
from higher to lower sulfur bituminous coals.
    EPA's analysis does not allow a unit designed for bituminous to 
switch to (very low sulfur) subbituminous coal unless the unit has 
demonstrated that capability in the past. EPA assumes units with that 
capability have already made any investments needed to handle a switch 
to subbituminous coals. EPA therefore assumes that any modeled coal 
switching from bituminous to subbituminous has no cost or schedule 
impact.
    EPA requests comment on the reasonableness of EPA's assumption that 
coal switching within the bituminous coal grades will have relatively 
little cost or schedule impact on most units.
b. Step 2. Performing the Air Quality Assessment
    In the second step, EPA uses an air quality assessment tool to 
estimate the impact of the upwind emissions reductions on downwind 
ambient concentrations.\56\ This tool is useful for identifying cost 
breakpoints for significant improvements in downwind air quality 
changes, including estimated effects on downwind attainment. While less 
rigorous than the air quality models used for attainment 
demonstrations, EPA believes this air quality assessment tool is 
acceptable for assessing the impact of numerous options on upwind 
reductions in the process of identifying upwind state significant 
contribution. It allows the Agency to analyze many more potential 
scenarios than the time- and resource-intensive more refined air 
quality modeling would permit. This tool assesses the impact that 
reductions at a given cost breakpoint from all of the contributing 
states (as well as the state with the nonattainment area itself) had on 
pollutant concentrations at that downwind area. The resulting 
information is used in step three. For each downwind area with a 
nonattainment and/or maintenance problem, it shows the total 
improvement in air quality for each cost level and associated pollutant 
reduction, the amount of the remaining problem caused by each upwind 
state (by constituent), and the amount of the remaining problem caused 
by sources within the state (by constituent). It also shows, overall, 
how much of the downwind air quality problem had been addressed at 
different cost levels. More detail on the tool itself, what EPA has 
done to verify the underlying assumptions, and the specific application 
of the tool to examining significant contribution for ozone and 
PM2.5 can be found in the TSD, ``Analysis to Quantify 
Significant Contribution,'' in the docket for this rule.
---------------------------------------------------------------------------

    \56\ 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 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.
---------------------------------------------------------------------------

    c. Step 3. Identifying Appropriate Cost Thresholds
    In the third step of this analysis, EPA examines the information 
developed in the first two steps to identify potential cost thresholds. 
It then uses a multi-factor assessment to identify which cost

[[Page 45274]]

threshold \57\ or thresholds should be used to quantify states' 
significant contribution and interference with maintenance. This new 
methodology responds to the Court's statements in North Carolina v. EPA 
both criticizing the manner in which cost was used in the CAIR rule and 
acknowledging its prior acceptance (in Michigan v. EPA, 213 F.3d 663) 
of EPA's use of a uniform cost threshold and the uniform control 
requirements associated with the use of such a cost threshold. See 
North Carolina v. EPA, 531 F.3d at 908, 917.920. In both the 
NOX SIP Call and CAIR, EPA evaluated the cost of controls 
relative to the cost of controls required by other CAA regulations to 
identify a single cost threshold referred to as the ``highly-cost-
effective'' threshold. In contrast, in this proposed rule, EPA 
considers multiple factors to identify appropriate cost thresholds, 
allowing EPA to give greater weight to air quality considerations and 
making it possible to tailor the significant contribution measurement 
more closely to different conditions in different groups of states.
---------------------------------------------------------------------------

    \57\ The cost thresholds identified in today's proposal are 
specific to the section 110(a)(2)(D) 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 step of the analysis begins with an examination of the cost 
and air quality data to identify breakpoints on the emissions 
reductions cost curves developed in steps 1 and 2 related to (1) air 
quality (e.g., points at which all areas (other than those with an 
unusually predominant local pollution problem) reach attainment and 
have maintenance fully addressed), and/or (2) cost (e.g., points at 
which significant reductions are available because a certain technology 
is widely deployed). EPA identifies potential breakpoints and then uses 
a multi-factor assessment to evaluate whether one or more of the 
potential breakpoints represent a reasonable cost at which to define 
significant contribution for some or all upwind states. The factors in 
this multi-factor assessment can be divided into two broad categories: 
Those that focus on air quality considerations and those that focus on 
cost considerations. Air quality considerations include, for example, 
how much air quality improvement in downwind states results from upwind 
state emissions reductions at different levels; whether, considering 
upwind emissions 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., is it a 
predominantly local or in-state problem, or does it still contain a 
large upwind component). Cost considerations include, for example, how 
the cost per ton compares with the cost per ton of existing federal and 
state rules for the same pollutant, and 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); the cost increase required to 
achieve the next increment of air quality improvement; and whether, 
given timing considerations, emissions reductions requirements could be 
more costly than indicated in the modeling because sources could choose 
one short-term solution and then switch to another long-term solution 
(e.g., switching coals can involve plant modifications. While these 
costs are low when amortized over a number of years, if a source 
quickly installs controls, and switches coals again, costs may be 
higher than projected).
    Because upwind state sources should bear substantial responsibility 
for controlling emissions that contribute to air quality degradation in 
downwind states, EPA believes that cost per ton levels that are 
consistent with widely deployed existing controls, or are within the 
cost per ton range of controls already required by existing and 
proposed Federal and State rules (i.e., similar to the highly cost 
effective concept in the NOX SIP Call and CAIR), are 
reasonable for upwind states from a cost standpoint. Higher cost per 
ton levels also may be reasonable for upwind states based on 
examination of air quality and cost factors. One reason is that 
achieving attainment and maintenance of the air quality standard may 
require controls in upwind and downwind states that are more costly 
than previous controls (particularly if it is a new standard).
    Based on this multi-factor assessment, EPA identifies a specific 
cost per ton threshold for quantifying the amount of significant 
contribution from each state for each precursor pollutant. While we 
continue to believe that under certain circumstances it may be 
appropriate for us to use a single uniform cost per ton threshold to 
quantify significant contribution for all states, we believe it is also 
important to retain the flexibility to use multiple cost thresholds. 
For example, we believe it is appropriate to use multiple thresholds 
where one group of states can, for a lower cost, eliminate 
nonattainment and maintenance for all the downwind nonattainment and 
maintenance areas to which they are linked.
d. Step 4. Identify Required Emissions Reductions
    In the final step of this analysis, EPA uses the cost thresholds 
identified in the previous step to determine, on a state-by-state 
basis, the amount of emissions that could be reduced at a specific 
cost. The results of this analysis are used to develop the state 
budgets and variability limits, which are in turn used to implement the 
requirements to eliminate significant contribution and interference 
with maintenance. See sections IV.E and IV.F.
2. Application
    The discussion that follows explains how the methodology described 
previously was applied to quantify significant contribution with 
respect to the 1997 and 2006 PM2.5 NAAQS and the 1997 ozone 
NAAQS. EPA also believes that the methodology proposed today could also 
be used to address transport concerns under other NAAQS, including 
revisions to the ozone and PM2.5 NAAQS.
    All of the air quality considerations included in the multi-factor 
assessment are based on analysis using the air quality assessment tool. 
EPA believes that it is appropriate to use this tool because of the 
advantages it has over more refined air quality modeling to perform 
analysis of a large number of scenarios very quickly (more refined air 
quality modeling can take several months, while multiple scenarios can 
be evaluated using the air quality assessment tool in a single day). 
EPA has done more refined air quality modeling of the proposed 
emissions budgets. The more refined air quality modeling confirms EPA's 
overall methodology, but does suggest that, in the case of daily 
PM2.5, the air quality assessment tool slightly over-
predicts the air quality benefit of the proposed reductions.
    For this reason, EPA is also requesting comment on whether we 
should modify our conclusions regarding the amount of specific states' 
significant contribution and interference with maintenance; whether 
there are ways to use our air quality modeling in conjunction with the 
air quality assessment tool to carry out the significant contribution 
analysis in a way that would not extend the time needed to complete 
this rulemaking; and whether there are ways to improve the air quality 
assessment tool.

[[Page 45275]]

a. Specific Application to PM2.5
(1) Year for Quantifying Significant Contribution
    EPA's significant contribution analysis for PM2.5 used a 
multi-factor assessment to identify cost thresholds for 2014. EPA 
believes this is the most appropriate year to consider because it is 
consistent with attainment dates for both the annual and daily 
PM2.5 standards. Furthermore, EPA believes that 2014 
provides sources sufficient lead time to install emissions controls or 
take other actions necessary to achieve the required reductions. After 
determining the amount of emissions that represents each state's 
significant contribution, EPA then considers whether it would be 
appropriate to establish an interim compliance deadline to ensure that 
the reductions are achieved as expeditiously as practicable. For this 
part of the analysis, EPA focused on determining what portion of each 
state's significant contribution could be eliminated by 2012, the first 
year in which it would be possible to get reductions following 
promulgation of this rule in 2011. EPA believes it is possible to 
achieve much of the required emissions reductions by 2012. EPA also 
believes that it is important to get the reductions as expeditiously as 
practicable and to coordinate the compliance dates both with the 
downwind states'' maximum attainment deadlines and with the requirement 
that they eliminate nonattainment as expeditiously as practicable.
(2) Step 1. Emissions Reductions Cost Curves
    This subsection provides more detail on the cost curves that EPA 
developed to assess the costs of reducing SO2 and 
NOX to address transport related to PM2.5. It 
summarizes the information from the curves and then provides EPA's 
interpretation of that information. EPA uses the information from the 
cost curves in step 3 to quantify the cost per ton of emissions 
reductions which should be used to calculate each state's significant 
contribution and interference with maintenance, and the resulting 
state-specific emissions budgets.
    To measure significant contribution and interference with 
maintenance with respect to the PM2.5 NAAQS, EPA developed 
cost curves showing the annual NOX and annual SO2 
reductions available in 2014 at different cost increments. 
Specifically, EPA developed cost curves that show reductions available 
in 2014 from EGUs at various costs (in 2006 $) up to $2,500/ton for 
annual NOX, $5,000/ton for ozone season NOX, and 
$2,400/ton for SO2. For example, this means that EPA 
examined reductions of annual NOX that are available at a 
cost of $2,500 per ton or less. For SO2, the projected cost 
considered for reducing a ton of emissions is $2,400 or less.
    Table IV.D-1 shows the annual NOX emissions from EGUs at 
various levels of control cost for 2014.

Table IV.D-1--2014 Annual NOX Emissions From Electric Generating Units for Each State in the Transport Region at
                                                  Various Costs
                                       [(2006 $) per ton (thousand tons)]
----------------------------------------------------------------------------------------------------------------
                                                               Base case
                    Marginal cost per ton                        level         $500        $1,500       $2,500
----------------------------------------------------------------------------------------------------------------
Alabama.....................................................          119           62           62           50
Connecticut.................................................            8            8            8            8
Delaware....................................................            6            6            6            6
Florida.....................................................          196          138          113           80
Georgia.....................................................           48           46           45           45
Illinois....................................................           80           56           56           56
Indiana.....................................................          201          114          114          107
Iowa........................................................           68           56           50           47
Kansas......................................................           79           38           36           35
Kentucky....................................................          149           72           72           71
Louisiana...................................................           46           37           37           28
Maryland....................................................           36           36           36           36
Massachusetts...............................................           13           13           13           13
Michigan....................................................           99           68           68           66
Minnesota...................................................           55           38           38           38
Missouri....................................................           83           82           61           55
Nebraska....................................................           53           34           28           28
New Jersey..................................................           27           23           23           20
New York....................................................           36           35           32           31
North Carolina..............................................           63           63           62           61
Ohio........................................................          165          104           98           88
Pennsylvania................................................          205          123          122           86
South Carolina..............................................           48           36           36           35
Tennessee...................................................           69           29           29           29
Virginia....................................................           38           37           37           36
West Virginia...............................................          100           54           49           45
Wisconsin...................................................           55           44           43           41
                                                             ---------------------------------------------------
    Total...................................................        2,144        1,455        1,375        1,241
----------------------------------------------------------------------------------------------------------------

    Before applying the information in the cost curves in step 3 of the 
analysis, EPA evaluated the cost curves to better understand how 
reductions at various cost levels reflect changes in the generation mix 
(e.g., dispatch changes, fuel use changes, or installation or operation 
of controls). From the cost curves, EPA concluded that in 2014, there 
are large NOX reductions available at approximately $500/
ton. At costs above $500/ton and up to at least $2,500/ton, potential 
reductions increase slowly. This is because the base case assumed that 
sources would not

[[Page 45276]]

run their SCR units unless they are required to run those SCR units 
pursuant to mandates other than CAIR (which will be replaced by this 
rule when it is finalized). This is especially relevant for winter use 
of SCRs. Even without CAIR, the NOX SIP Call will provide an 
incentive to run many SCRs during the ozone season.
    The cost curves demonstrate that many of these sources would 
operate their SCR units when emissions reductions that cost $500/ton 
are required. In addition, at this $500/ton level some additional units 
would likely install advanced combustion control technology. Below 
$500/ton, there are very few other NOX reductions. 
Significant additional reductions would not be achieved without 
application of controls costing more than $2,500/ton. In 2014, more 
reductions could be achieved with installation of additional add-on 
controls, such as SCR.
    The cost curves for SO2 show the same effect as those 
for NOX (large emissions reductions at relatively low costs 
and additional reductions at relatively high costs) but the effect was 
not as pronounced. In 2014, more than 1,000,000 tons of SO2 
reductions can be achieved at a cost of less than $200 per ton. Most of 
these reductions can be achieved by requiring companies to operate 
existing scrubbers that they would not have an incentive to run absent 
the requirements of CAIR. Additional reductions can be achieved at 
higher costs. For instance, in many cases, companies are currently 
using lower sulfur coals to comply with CAIR, but there is no guarantee 
they will continue to do so. Many, but not all, of these reduction 
opportunities (e.g., operating current equipment and continued use of 
low sulfur coal) are available at below $500/ton.
    Table IV.D-2 shows that in 2014 there are increased SO2 
emission reduction opportunities beyond just operating existing 
scrubbers and switching to low sulfur coal. Installation of new 
scrubbers becomes feasible by 2014, thus increasing reduction 
opportunities at costs between $500/ton and $2,000/ton (and above).

                 Table IV.D-2--2014 SO2 Emissions From Electric Generating Units for Each State in the Transport Region at Various Costs
                                                            [(2006$) per ton (thousand tons)]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                       Base case
                Marginal cost per ton                    level       $100       $200       $500      $1,000     $1,400     $1,800     $2,000     $2,400
--------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama..............................................        322        307        257        171        166        146        101         84         71
Connecticut..........................................          6          6          6          6          6          3          3          3          3
Delaware.............................................          8          9          9          9          9          9          9          8          8
Florida..............................................        195        178        171        117        113        111         79         74         70
Georgia..............................................        173        166        136        133        117        101         92         86         67
Illinois.............................................        200        185        165        165        164        165        161        155        143
Indiana..............................................        804        478        433        328        291        284        242        227        190
Iowa.................................................        164        140        130        106        105        104        102        101         70
Kansas...............................................         65         64         56         49         46         46         33         31         24
Kentucky.............................................        740        275        270        248        196        178        127        115        100
Louisiana............................................         95         95         95         95         95         95         95         82         36
Maryland.............................................         45         45         45         45         45         45         42         42         40
Massachusetts........................................         17         18         18         10         10         10          9          9          6
Michigan.............................................        276        254        253        214        209        207        177        163        116
Minnesota............................................         62         57         55         49         48         48         48         48         46
Missouri.............................................        501        289        238        213        212        212        196        183         94
Nebraska.............................................        116        119        113         74         73         71         69         45         33
New Jersey...........................................         40         40         27         21         21         20         18         17         14
New York.............................................        143        142        143        135        118        114        100         70         63
North Carolina.......................................        141        141        141        130        114        104         99         91         63
Ohio.................................................        841        583        553        408        294        260        236        221        203
Pennsylvania.........................................        975        825        441        337        202        175        154        145        125
South Carolina.......................................        156        138        137        134        125         83         78         57         42
Tennessee............................................        600        154        131        127        126        108        108        100         79
Virginia.............................................        137        134        134        109        106         93         65         54         45
West Virginia........................................        496        179        170        161        160        143        132        119         98
Wisconsin............................................        117        111        108         97         92         89         87         81         64
                                                      --------------------------------------------------------------------------------------------------
    Total............................................      7,436      5,133      4,435      3,692      3,263      3,025      2,660      2,410      1,912
--------------------------------------------------------------------------------------------------------------------------------------------------------

(3) Step 2. Air Quality Assessment of Potential Emissions Reductions
    After developing cost curves to show the state-by-state cost-
effective emissions reductions available, EPA used the air quality 
assessment tool to evaluate the impact these upwind reductions would 
have on air quality in ``linked'' downwind nonattainment and 
maintenance areas. This section summarizes the results of that 
evaluation and provides analysis that informs EPA's multi-factor 
assessment, explained in step 3, later.
    EPA performed air quality analysis for each downwind receptor with 
a nonattainment and/or maintenance problem. For each receptor, EPA 
assessed the air quality improvement resulting when a group of states, 
consisting of the upwind states that are ``linked'' to the downwind 
receptor (i.e., EPA modeling showed that they exceeded the one percent 
contribution threshold, based on it's 2012 linkage analysis), and the 
downwind state where the receptor is located, all made the emissions 
reductions that EPA identified as available at each cost threshold (as 
described previously). This analysis did not assume any reductions in 
upwind states covered by this rule but not ``linked'' to the downwind 
receptor (even if the state was ``linked'' to a different receptor), 
beyond those assumed in the base case.
    The percent emissions reductions (and percent air quality 
improvement)

[[Page 45277]]

that could be made by each upwind state in 2014 at different cost per 
ton levels are shown in Figures IV.D-1 through IV.D-4, later. These 
figures show the percent reduction in SO2 emissions as a 
function of cost (using the emissions at zero dollars per ton in 2014 
as the baseline reference). A percentage reduction of zero means that 
emissions are not reduced from the levels that exist at the 2014 zero 
dollar per ton (base case) cost level. It is assumed that reductions in 
SO2 emissions are linearly and directly proportional to 
downwind sulfate contributions. In other words, it is assumed that a 
specific percent reduction in SO2 emissions would lead to 
the same percent reduction in air quality sulfate contribution from 
that upwind state. For example, if a state made a 50 percent reduction 
in SO2 emissions, its sulfate contribution to any monitor 
downwind is assumed to be reduced by 50 percent.
    EPA determines the cumulative air quality improvement that could be 
expected at a particular downwind receptor by multiplying each upwind 
state's percent reduction by its air quality contribution and summing 
the results for all upwind states. In EPA's air quality analysis of 
each downwind receptor, all air quality improvements are measured 
relative to baseline emissions and air quality contributions in 2012.
    Figures IV.D-1 through IV.D-4 show that at increased costs, there 
are substantial increased emissions reductions. As explained 
previously, each decrease in emissions is assumed to lead to a 
corresponding improvement in downwind air quality. These changes apply 
to both the daily and annual PM2.5 NAAQS. While the pattern 
differs from state to state, many states see noticeable decreases in 
sulfate contribution for costs of $500/ton or less. Reductions in 
downwind contribution level off, then many states start to see an 
additional decrease in contribution at higher costs (in general about 
$1,500/ton).
[GRAPHIC] [TIFF OMITTED] TP02AU10.000


[[Page 45278]]


[GRAPHIC] [TIFF OMITTED] TP02AU10.001

[GRAPHIC] [TIFF OMITTED] TP02AU10.002


[[Page 45279]]


[GRAPHIC] [TIFF OMITTED] TP02AU10.003


[[Page 45280]]


    EPA also identified the overall air quality reductions projected by 
the air quality assessment tool at downwind nonattainment and 
maintenance receptor locations. As explained previously, the multi-
factor assessment in step 3 analyzed the results from the downwind 
receptor analysis in step 2 for the annual and daily PM2.5 
standards. Tables IV.D-3 and IV.D-4 show the air quality improvements 
in 2014 from the emissions reductions projected to occur at various 
costs. Table IV.D-4 also shows the average decrease in ambient daily 
PM2.5 for different sets of downwind sites for various 
reductions in SO2.

   Table IV.D-3--Estimated Number of Nonattainment and/or Maintenance
                 Monitor Sites in 2014 for Annual PM2.5
               [As a function of SO2 cost-per-ton levels]
------------------------------------------------------------------------
                                               2014            2014
                                         -------------------------------
                                                             Number of
                                             Number of       remaining
          Marginal cost per ton              remaining     nonattainment
                                           nonattainment        and
                                           monitor sites    maintenance
                                                           monitor sites
------------------------------------------------------------------------
>$0.....................................              12              19
>$100...................................               3               6
>$200...................................               2               3
>$300...................................               2               3
>$400...................................               1               2
>$500...................................               1               2
>$600...................................               1               1
>$800...................................               1               1
>$1,000.................................               1               1
>$1,200.................................               1               1
>$1,400.................................               1               1
>$1,600.................................               1               1
>$1,800.................................               0               1
>$2,000.................................               0               1
>$2,400.................................               0               1
------------------------------------------------------------------------


                   Table IV.D-4--Daily Air Quality Impacts vs. SO2 Cost per Ton Levels in 2014
----------------------------------------------------------------------------------------------------------------
                                                                              Air quality improvement (average
                                                              Number of     [mu]g/m[caret]3 Reduction)  relative
                                                              remaining     to 2014 base case (zero dollars/ton)
                 Marginal SO2 cost per ton                  nonattainment --------------------------------------
                                                                 and        All sites
                                                             maintenance     in 2012     6 selected   3 selected
                                                            monitor sites      base       sites *      sites **
----------------------------------------------------------------------------------------------------------------
>$0.......................................................            64           0.0          0.0          0.0
>$100.....................................................            16           3.7          2.0          1.8
>$200.....................................................            12           4.4          2.4          2.1
>$300.....................................................             8           4.7          2.6          2.3
>$400.....................................................           * 6           5.0          2.9          2.6
>$500.....................................................             6           5.1          3.0          2.6
>$600.....................................................             6           5.3          3.1          2.8
>$800.....................................................             6           5.4          3.3          2.9
>$1,000...................................................             6           5.6          3.4          3.0
>$1,200...................................................             6           5.7          3.4          3.0
>$1,400...................................................             6           5.8          3.5          3.1
>$1,600...................................................             5           6.0          3.6          3.2
>$1,800...................................................             4           6.2          3.7          3.3
>$2,000...................................................          ** 3           6.4          3.9          3.4
>$2,400...................................................             1           6.8          4.1         3.7
----------------------------------------------------------------------------------------------------------------
* The six sites are: Allegheny County, PA (2 sites); Baltimore County, MD; Wayne County, MI; Lake County, IN;
  Cook County, IL.
** The three sites are: Lake County, IN; Cook County, IL; Allegheny County, PA.

    A number of conclusions can be drawn from Tables IV.D-3 and IV.D-4. 
Very low cost SO2 reductions result in significant air 
quality benefits.\58\ As explained previously, this is because there 
are significant reductions available from sources that operate existing 
scrubbers and, in a number of cases, use relatively low cost, lower 
sulfur coal. At the same time, in 2014 enough lead time exists for 
considerable emission reduction opportunities from new scrubber 
installations. Other programs are also achieving reductions (for 
example, some state rules and enforcement consent decrees require 
SO2 and NOX reductions in 2013 and 2014). The 
analysis also shows that higher cost reductions continue to provide 
downwind air quality improvements.
---------------------------------------------------------------------------

    \58\ Measured in terms of downwind area nonattainment and/or 
maintenance concerns being addressed. This is also true in terms of 
improvements in air concentrations of PM2.5.

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

[[Page 45281]]

(4) Identifying Cost Thresholds
(a) Considerations for 2014
    For PM2.5, EPA considered three cost breakpoints for 
SO2 and one for NOX. First EPA looked at a point 
at which EGUs operated all installed controls, continued to burn coals 
with sulfur contents consistent with what they were burning in 2009, 
and operated any additional controls they are currently planning to 
install by 2014. For NOX, this point is similar to the $500/
ton cost. For SO2, it is similar to the $300 to $400 cost. 
EPA believes this is an appropriate starting point, because if a state 
is ``linked'' to a downwind state (i.e., if our air quality analysis 
showed it was contributing above the 1 percent threshold), EPA believes 
it is appropriate to prohibit that state from increasing its emissions 
which could worsen downwind air quality problems. EPA then considered 
what additional cost thresholds should be considered. For 
SO2 EPA considered two breakpoints: (1) $2,000/ton 
SO2 and (2) $2,400/ton SO2. EPA's state-by-state 
cost modeling at that point indicates that scrubbers would be installed 
on units generating about 20 GW of electricity. Since slightly over 21 
GWs of scrubbers were installed in both 2008 and 2009 (see EPA Analysis 
of Alternative SO2 and NOX Caps for Senator 
Carper--July 31, 2009 Appendix B, page 15), EPA believes that it is 
clearly possible for the power sector to install at least that quantity 
of scrubbers by 2014. The $2,400/ton SO2 breakpoint 
represents the point where analysis from the air quality assessment 
tool projects that both nonattainment and maintenance concerns would be 
fully addressed in all areas, except for Allegheny County, 
Pennsylvania, when considering reductions from only states that 
contribute more than 1 percent.\59\ As is explained later in this 
section, EPA believes that the monitor in Allegheny County that remains 
in nonattainment is in an area where the air quality problem is 
primarily local. Since EPA's analysis suggests that the only remaining 
nonattainment problem is primarily local, EPA did not consider higher 
cost thresholds.
---------------------------------------------------------------------------

    \59\ When considering all reductions made, including those by 
states that contribute less than 1 percent, the air quality 
assessment tool projects that both nonattainment and maintenance 
will be fully addressed in all areas except for Allegheny County, PA 
at $2,000/ton.
---------------------------------------------------------------------------

    EPA did not consider additional cost thresholds for NOX 
beyond $500/ton because there are minimal additional NOX 
reductions until one considers cost levels higher than $2,400/ton, and 
SO2 reductions are generally more effective than 
NOX reductions at reducing PM2.5. EPA did not 
consider lower cost thresholds than $2,000/ton for SO2 
because: There are clearly continued air quality benefits at higher 
costs (as evidenced by increases in average air quality improvements in 
downwind sites); there is very little change in the number of downwind 
nonattainment and/or maintenance sites, indicating that the number of 
upwind states contributing would not be expected to change much; and 
costs of up to $2,000/ton of SO2 are reasonable in 
comparison to other existing regulations.
    First EPA assessed $2,000/ton. Reductions at $2,000/ton would 
improve air quality at several locations with nonattainment and/or 
maintenance problems. We also believe that, as explained in the 
introduction to this section, it is reasonable to require a substantial 
level of control of upwind state emissions that significantly 
contribute to nonattainment or maintenance problems in another state. 
We believe that $2,000/ton is reasonable for SO2 considering 
that this cost per ton level is based on EGU control technologies that 
are proven and already widely deployed. Furthermore, compared to other 
control measures that address SO2, this cost per ton level 
is relatively low. A survey of the control options that EPA examined in 
the PM2.5 RIA shows that non-EGU SO2 reduction 
opportunities cost from $2,270/ton to over $16,000/ton.
    While analysis with the air quality assessment tool shows that a 
site in Allegheny County, Pennsylvania would be in nonattainment and 
two other sites--Lake County, Indiana and Cook County, Illinois--would 
have maintenance problems, if we assume reductions at $2,000/ton and 
additional reductions made by states because of their contribution to 
other downwind sites that do not contribute to these three problem 
areas, the maintenance problems in Lake County, Indiana and Cook 
County, Illinois would be resolved and only Allegheny County, 
Pennsylvania, would continue to have a nonattainment/maintenance 
problem. Because reductions at $2,000/ton continue to have significant 
air quality benefit for downwind sites with nonattainment and/or 
maintenance problems, it has been demonstrated historically that the 
amount of control equipment that is projected to be needed at $2,000/
ton could be installed in the timeframe required and these costs are 
reasonable when compared to other options to reduce SO2. 
Therefore, EPA believes that requiring a cost threshold of at least 
$2,000/ton would be appropriate for determining significant 
contribution.
    Because our analysis shows that one area (Allegheny County, 
Pennsylvania) would have continuing nonattainment and maintenance 
problems, EPA continued to perform its multi-factor assessment for the 
higher $2,400/ton breakpoint to see if any additional emissions should 
also be considered significant. For this receptor monitor, EPA 
considered the local circumstances in the Liberty-Clairton area in 
Allegheny County that were leading to continued nonattainment. It is 
well-established that, in addition to being impacted by regional 
sources, the Liberty-Clairton area is significantly affected by a large 
increment of local emissions from a sizable coke production facility 
and other nearby sources. (See http://www.epa.gov/pmdesignations/
2006standards/final/TSD/tsd_4.0_4.3_4.3.3_r03_PA_2.pdf). High 
concentrations of organic carbon indicate the unique local problem for 
this location.
    Because the remaining PM2.5 problem is more local in 
nature than the problem at other receptors, EPA does not believe that 
it is appropriate to establish a higher cost threshold solely for 
states that are ``linked'' to this monitor.
(b) Amount of Reductions That Could Be Achieved by 2012
    After determining that the amount of emissions that could be 
reduced for $2,000/ton in 2014 is an appropriate quantification of a 
state's significant contribution, EPA considered whether any of these 
emissions 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. While EPA believes that it is not possible to require the 
installation of post-combustion SO2 controls (scrubbers) or 
post-combustion NOX controls (SCRs) before 2014 (because it 
takes about 27 months to install a scrubber and 21 months to install an 
SCR), EPA believes that there are significant reductions that can occur 
earlier. For SO2, reductions from operating existing 
scrubbers up to their design removal efficiencies and from the use of 
lower sulfur coals are possible by 2012. For NOX, reductions 
from operating existing SCRs on a year-round basis and up to their 
design removal efficiencies and the installation of limited amounts of 
low NOX burners are possible by 2012. For this reason, EPA 
believes it is appropriate to require these emissions to be removed in 
2012,

[[Page 45282]]

consistent with the Act's requirement that downwind states attain the 
NAAQS as expeditiously as practicable. Section IV.E explains how these 
2012 emissions reductions requirements are defined.
(c) Off-Ramp for States That Eliminate Their Significant Contribution 
for Less Than $2,000/Ton
    Table IV.D.4, previously, shows that for large numbers of 
monitoring sites where there are nonattainment and or maintenance 
problems, those problems are fully resolved before all states achieve 
all of the emissions reductions that could be achieved at or below 
$2,000/ton. EPA used the air quality assessment tool to analyze the 
impact of requiring all states linked to the downwind state site with 
an air quality problem, as well as the downwind state, to reduce 
emissions consistent with the levels discussed for 2012 in section 
IV.D.2.a(2), previously. The air quality assessment tool shows that 
those 2012 reductions will resolve the nonattainment and maintenance 
problems for all of the areas to which the following states are linked: 
Alabama, Connecticut, Delaware, the District of Columbia, Florida, 
Kansas, Louisiana, Maryland, Massachusetts, Minnesota, Nebraska, New 
Jersey and South Carolina (referred to as group 2 states). EPA also 
assessed whether, in 2014, the combination of this level of reduction 
from the group 2 states and the remaining states (referred to as group 
1 states) continued to result in all downwind areas--except for 
Allegheny County, Pennsylvania--fully addressing their nonattainment 
and or/maintenance problems, and determined that it did.
    The states in group 1 and group 2 are rationally grouped 
considering air quality and cost. EPA proposes that it would not be 
appropriate to assign the same cost per ton to group 2 and group 1 
states because a significantly lower cost per ton 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, our analysis indicated that the cost per ton needed 
to resolve downwind air quality problems varied only to a limited 
extent among states within group 1 and among states within group 2. The 
cost per ton did vary greatly between the group 1 and group 2 states. 
Limitations on the accuracy of our cost and air quality analyses, and 
the ruling in the Michigan decision accepting EPA's prior use of a 
uniform cost approach, support the decision to use uniform costs for a 
group of states.
(d) Proposed Cost Thresholds for PM2.5
    Summary of methodology. In summary, EPA determined that 
SO2 emissions that could be reduced for $2,000/ton in 2014 
should be considered a state's significant contribution, unless EPA 
determined that a lesser reduction would fully resolve the 
nonattainment and/or maintenance problem for all the downwind 
monitoring sites 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. EPA also determined 
that all states linked to downwind PM2.5 nonattainment and 
maintenance problems should be required to achieve those emissions 
reductions that can be reasonably achieved by 2012. Finally, EPA 
determined that all states linked to downwind PM2.5 
nonattainment (see Table IV.D-5) and maintenance problems should, by 
2012, remove all NOX emissions that can be reduced for $500/
ton in 2012.

                    Table IV.D-5--States Covered for SO2 Group 1, SO2 Group 2, and NOX Annual
----------------------------------------------------------------------------------------------------------------
                        States covered                           SO2 group 1      SO2 group 2       NOX annual
----------------------------------------------------------------------------------------------------------------
Alabama......................................................  ...............               X                X
Connecticut..................................................  ...............               X                X
Delaware.....................................................  ...............               X                X
District of Columbia.........................................  ...............               X                X
Florida......................................................  ...............               X                X
Georgia......................................................               X   ...............               X
Illinois.....................................................               X   ...............               X
Indiana......................................................               X   ...............               X
Iowa.........................................................               X   ...............               X
Kansas.......................................................  ...............               X                X
Kentucky.....................................................               X   ...............               X
Louisiana....................................................  ...............               X                X
Maryland.....................................................  ...............               X                X
Massachusetts................................................  ...............               X                X
Michigan.....................................................               X   ...............               X
Minnesota....................................................  ...............               X                X
Missouri.....................................................               X   ...............               X
Nebraska.....................................................  ...............               X                X
New Jersey...................................................  ...............               X                X
New York.....................................................               X   ...............               X
North Carolina...............................................               X   ...............               X
Ohio.........................................................               X   ...............               X
Pennsylvania.................................................               X   ...............               X
South Carolina...............................................  ...............               X                X
Tennessee....................................................               X   ...............               X
Virginia.....................................................               X   ...............               X
West Virginia................................................               X   ...............               X
Wisconsin....................................................               X   ...............               X
                                                              --------------------------------------------------
    Totals...................................................              15               13               28
----------------------------------------------------------------------------------------------------------------


[[Page 45283]]

    After completing the process to propose appropriate state-by-state 
cost thresholds, EPA used these thresholds to develop the specific 
state-by-state budgets. This step in the process is fully described in 
section IV.E.
(e) Request for Comment on Issues Related to EPA's Modeling Methods
    EPA believes that the methodology described previously is a sound 
and analytically efficient approach to addressing the requirements of 
110(a)(2)(D)(i)(I) for the PM2.5 standards. While it would 
be possible for EPA to add additional analytical steps to the 
methodology, and such analyses would provide more information, EPA 
believes that the methodology selected strikes an appropriate balance 
between the competing requirements of comprehensive analysis and timely 
action. EPA believes that the technical analysis completed provides a 
sound basis for action. EPA also seeks to avoid burdensome technical 
analyses which could prevent EPA from fulfilling our obligation to the 
Court to act in a timely way. In this section, EPA generally requests 
comment on issues related to its efforts to strike an appropriate 
balance. EPA identifies several areas of recognized limitations on our 
methodology, and requests comments both on the implications of these 
limitations and on possible options for addressing these limitations 
without unduly delaying necessary action.
(f) Use of Air Quality Assessment Tool; Results of More Detailed Air 
Quality Modeling Used To Evaluate the Tool
    As discussed previously, EPA uses a simplified air quality 
assessment tool, rather than actual air quality modeling, to identify 
air quality impacts of the options considered. This assessment tool 
enables efficient evaluation of multiple options quickly. We did, 
however, conduct more refined air quality modeling of the select 
emissions budgets and this more detailed modeling serves as a check on 
the appropriateness of the method. This check confirmed the directional 
conclusions of the air quality assessment tool and largely confirmed 
the more detailed results of the air quality assessment tool, but 
raised several issues on which EPA is requesting comment.
    For the annual PM2.5 standard, the air quality 
assessment tool projected that, after implementation of the proposed 
FIPs, only one area (Allegheny County, PA) would have a continuing 
NAAQS air quality problem under the maintenance criteria. The results 
of the refined air quality modeling are very similar. This modeling 
projects similar annual PM2.5 reductions in downwind states 
and projects that Allegheny County, PA would remain in nonattainment 
and that Birmingham, AL would exceed the threshold for ``maintenance'' 
by a slight amount (less than 0.1 ug/m \3\). Given the unique local 
nature of the Allegheny County, PA receptor (see discussion 
previously), EPA does not believe that the fact that the air quality 
assessment tool projects the area to have only a maintenance problem, 
while the refined air quality modeling suggests that the area would 
remain in nonattainment, raises any serious issues about the 
conclusions regarding significant contribution to nonattainment and 
interference with maintenance with the annual PM2.5 
standard. Similarly, because the refined air quality modeling projects 
that Birmingham, AL will exceed the maintenance criteria by only an 
extremely slight amount and because reductions from nearby point 
sources will reduce local emissions in the area, EPA does not believe 
the refined air quality modeling demonstrates that upwind reductions 
beyond those in the proposed FIPs are required to address significant 
contribution and interference with maintenance of the annual 
PM2.5 NAAQS in Birmingham. For these reasons, EPA does not 
believe that the more refined air quality modeling for the annual 
PM2.5 standard changes any of EPA's conclusions with respect 
to reductions required to eliminate significant contribution and 
interference with maintenance with respect to this standard. EPA is, 
however, taking comment on whether Florida, the one group 2 state that 
was identified as linked to Birmingham, should be moved from group 2 to 
group 1. EPA notes that no group 2 states are linked to Allegheny 
County, PA.
    For the 24-hour PM2.5 standard, the simplified air 
quality assessment tool results suggest that under EPA's proposed FIPs, 
only one problem site, Allegheny County, PA, would remain. In contrast, 
the more refined CAMx air quality modeling results show a greater 24-
hour PM2.5 problem, with 10 nonattainment and 4 maintenance 
areas. As described later, EPA is evaluating the impact of this refined 
air quality modeling on the methodology used and the conclusions it has 
reached regarding significant contribution and interference with 
maintenance with regard to the 24-hour PM2.5 NAAQS.
    EPA has completed some preliminary analysis of the difference 
between the air quality assessment tool and CAMx results (see the TSDs 
``Analysis to Quantify Significant Contribution'' and ``Air Quality 
Modeling''). This analysis suggests that the main difference is that in 
the winter months, the CAMx modeling shows smaller air quality 
reductions compared to the assessment tool. This is because the CAMx 
air quality modeling more accurately reflects the complex nature of the 
winter portion of the 24-hour PM2.5 problem. Unlike summer 
days, for which sulfate is the dominant contributor to 
PM2.5, sulfate concentrations are typically a lesser 
contributor to the overall PM2.5 concentrations on winter 
days. Moreover, for winter days, reductions in this already reduced 
amount of sulfate appear to be less responsive to reductions in 
SO2 emissions than for summer days. That is, while for the 
summer a 50 percent reduction in SO2 emissions would likely 
yield a nearly 50 percent reduction in sulfate concentrations, in the 
winter such a reduction in SO2 would reduce sulfate by less 
than 50 percent. Thus, EPA believes that more study of the winter 
portion of the problem is warranted to address the issues raised by the 
CAMx modeling. EPA believes it is important to understand the degree to 
which these winter exceedances are transport-related or locally 
generated, and the degree to which upwind states' emissions of 
NOX, SO2, and other transported pollutants are 
significantly contributing to these winter exceedances.
    Because the CAMx results indicate additional nonattainment and 
maintenance areas compared to the air quality assessment tool, EPA 
requests comment on whether the $2,000/ton cost cutoff for 
SO2 resulting from the assessment tool should be raised to a 
higher cost cutoff. While the CAMx results may suggest that it would be 
appropriate to use a cutoff greater than $2,000/ton, the results do not 
suggest that the cutoff could be less than $2,000/ton. Instead, the 
results confirm the importance of achieving, at a minimum, all 
reductions available at the $2,000/ton cost threshold.
    Additionally, EPA is requesting comment on whether some group 2 
states should be moved to group 1. These group 2 states are: 
Connecticut, Kansas, Maryland, Massachusetts, Minnesota, Nebraska, and 
New Jersey. These states were all placed in group two because the air 
quality assessment tool indicates that the 2012 reductions will resolve 
the nonattainment or maintenance problems at all areas to which they 
are linked. However, for these states, the CAMx modeling indicates that 
one or more of the states to which they are linked will have continuing 
nonattainment and

[[Page 45284]]

maintenance problems after the implementation of the 2012 reductions.
    EPA also notes that during the winter, PM2.5 contains a 
larger nitrate component than in summer months. One reason for this is 
that some nitrates that are particles in cooler weather volatize and 
exist as gases during warmer weather. Given this larger contribution 
from nitrates in the winter, EPA is also taking comment on whether 
there should be a higher cost threshold for annual nitrogen oxides. 
This may be appropriate for states that have been identified as 
contributing significantly to sites that the CAMx air quality modeling 
continues to show as having a residual nonattainment and/or maintenance 
concern in 2014.
    Finally, EPA requests comment on how and whether EPA should 
incorporate the use of detailed models such as CAMx into our 
methodology for significant contribution and interference with 
maintenance.
(g) Possibility for Emissions Increases in Noncontributing States
    EPA also evaluated whether the proposed rule could cause changes in 
operation of electric generating units in states not regulated under 
the proposal (that is states not listed in table IV.D-5). Specifically, 
EPA evaluated whether such changes could lead to increases in emissions 
in those states, potentially affecting whether they would exceed the 1 
percent contribution thresholds used to identify linkages between 
upwind and downwind states. (See sections IV.B and IV.C previously for 
more discussion of the 1 percent thresholds). Such changes are possible 
in part because of the interconnected nature of the country's energy 
system (including both the electricity grid and coal and natural gas 
supplies). In addition, our models project that the rule affects the 
cost of coal (generally lowering the cost of higher sulfur coals and 
raising the cost of lower sulfur coals). If these price effects took 
place and if the rule is finalized as proposed, sources in states not 
covered by the proposed rule might choose to use higher sulfur coals. 
Increased use of such coals could thus increase SO2 
emissions in those states. EPA's modeling confirms this, projecting 
that, after the proposed rule is implemented in states regulated for 
SO2, emissions in some states not covered by the proposed 
rule would increase (i.e., their emissions are greater in the control 
case modeling than in the base case modeling). As shown in table IV.D-
6, Arkansas, Mississippi, North Dakota, South Dakota, and Texas all 
exhibit 2012 SO2 emissions increases over the base case and 
above 5,000 tons.\60\ For reference, we also include the statewide 2012 
base case emissions from all sources within the state.
---------------------------------------------------------------------------

    \60\ While Colorado is also a state that may see projected 
increases in emissions, it was not within the domain the EPA 
analyzed.

 Table IV.D-6--Unregulated States With More Than 5,000 Tons of Projected
             SO2 Increases Under the Proposed Transport Rule
------------------------------------------------------------------------
                                                           2012 SO2 base
                                              2012 SO2    case emissions
                                           increase from     from all
                  State                      base case        sources
                                             (thousand       (thousand
                                               tons)           tons)
------------------------------------------------------------------------
Arkansas................................              32             127
Mississippi.............................              18              80
North Dakota............................              11              94
South Dakota............................               6              26
Texas...................................             136             640
------------------------------------------------------------------------

    Further analysis with the air quality assessment tool indicates 
that these projected increases in the Texas SO2 emissions 
would increase Texas's contribution to an amount that would exceed the 
0.15 [mu]g/m\3\ threshold for annual PM2.5. For this reason, 
EPA takes comment on whether Texas should be included in the program as 
a group 2 state.
(h) Providing Downwind States Full Relief From Upwind Emissions
    EPA takes very seriously its responsibility to ensure that upwind 
reductions are made in a timely way so that downwind states can meet 
their attainment obligations.
    EPA recognizes, as discussed previously, that while this proposal 
fully addresses the annual PM2.5 standard, it may not fully 
address the 24-hour PM2.5 standard. Where this may be the 
case, as explained previously, EPA's air quality modeling shows that 
the remaining component of non-attainment is almost entirely occurring 
in the winter months. Also as noted previously the atmospheric 
chemistry related to secondary particle formation, and the relative 
importance of particle species such as sulfate and nitrate, is quite 
different between summer and winter. Because of this, EPA is moving 
ahead with further efforts, before the final rule is published, to 
determine the extent to which this winter problem is caused by 
emissions transported from upwind states and, if this is the case, to 
identify the total amount of emissions that represents significant 
contribution and interference with maintenance. To the extent possible, 
EPA plans to finalize a rule that fully defines this amount.
    Based on the information that EPA currently has, EPA believes there 
are a number of possible outcomes of this further study. Possible 
outcomes include:
    (1) Identification of the additional amount of SO2 
emissions reductions needed to eliminate significant contribution and 
interference with maintenance from upwind states contributing to the 
residual 24-hour PM2.5 problem sites.
    (2) Identification of the additional amount of NOX 
emissions reductions needed to eliminate significant contribution and 
interference with maintenance from upwind states contributing to the 
residual 24-hour PM2.5 problem sites.
    (3) Identification of another pollutant that should be considered 
part of significant contribution and interference with maintenance for 
states that

[[Page 45285]]

contribute to the residual 24-hour PM2.5 problem sites.
    (4) Determination that the reductions proposed in today's 
rulemaking would fully address significant contribution and 
interference with maintenance at these sites.
    If EPA determines that more SO2 emissions should be 
considered part of this amount based on the analysis performed for 
today's proposal, EPA believes that the next set of emissions that can 
be reduced above the $2,000/ton threshold would likely still come from 
the power sector. If EPA determines that more SO2 emissions 
reductions are required or that the amount of emissions of 
SO2 and NOX that it has proposed as significantly 
contributing to nonattainment are the appropriate amounts to address 
this winter portion of the problem, EPA intends to supplement today's 
proposal and finalize a rule that would fully addresses emissions that 
significantly contribute to or interfere with maintenance of the 2006 
daily PM2.5 standard.
    To the extent that EPA determines that more NOX 
reductions are needed or that reductions of another pollutant are 
needed, EPA believes that we could provide the greatest assistance to 
states in addressing transport by finalizing this rule quickly and 
promulgating a separate rule to achieve any necessary additional 
NOX reductions. This is because those emissions reductions 
would likely involve placing reduction requirements on sources other 
than EGUs and that additional approaches would need to be addressed. 
EPA believes that developing supplemental information to address these 
sources and concepts would substantially delay publication of a final 
rule, beyond the anticipated publication of spring 2011.
    EPA plans to move forward aggressively in the event that these 
further reductions are needed. We do not, however, intend to delay the 
reductions in this proposed rule because those reductions have a 
substantial impact on states' abilities to attain the NAAQS in the 
required time period and have large health benefits.
b. Specific Application to Ozone
    This section discusses, for the 1997 ozone standards, how EPA 
applies its multi-step methodology for defining each state's 
significant contribution. For some aspects of the methodology, further 
work is needed to complete the methodology for ozone and this further 
work will be completed in a separate proposal.
(1) Years for Quantifying Significant Contribution
    In this subsection, we discuss how EPA identifies for ozone the 
years to analyze for eliminating significant contribution. Similar to 
the previous discussion for PM2.5, EPA believes that the 
selection of the year for eliminating significant contribution is 
informed by the attainment deadline and by the Act's requirement to 
attain the NAAQS ``as expeditiously as practicable.''
    As noted earlier, the 2012 ozone season is the last ozone season 
before the 2013 attainment deadline for ozone areas classified as 
``serious'' for the 1997 ozone air quality standards. Thus, for any 
states ``linked'' to ``serious area'' locations for which 2012 is the 
latest ozone season prior to their attainment deadline, EPA believes 
that 2012 is the appropriate year for eliminating significant 
contribution, to the extent that purpose can be achieved given the 
short time period. Because this proposed rule would not be finalized 
until 2011, the year 2012 also represents the earliest time by which 
emissions reductions could be achieved, which is consistent with 
statutory provisions calling for downwind states to achieve attainment 
``as expeditiously as practicable.'' This also is relevant for certain 
other areas with lower ozone classifications that are projected in our 
analysis to have continuing air quality problems and to be affected by 
transported pollution from certain upwind states in amounts greater 
than the 1 percent threshold.\61\
---------------------------------------------------------------------------

    \61\ This is possible where: (1) Latest monitoring data indicate 
attainment of the 1997 ozone standard, (2) the area is operating 
under one-year extensions of their 2009 deadline, or (3) EPA has not 
made a formal finding of failure to attain.
---------------------------------------------------------------------------

    EPA is concerned that the timing of this rule presents difficult 
challenges in eliminating significant contribution and interference 
with maintenance with regard to the 1997 ozone NAAQS by the attainment 
date. For states with a 2012 (or earlier) attainment date for which we 
project continuing ozone problems, we are concerned that strict 
adherence to a 2012 date for reductions could be viewed as an 
artificial constraint on our ability to require appropriate reductions. 
EPA believes that the current situation for ozone, involving a 
transport rulemaking within months of the attainment date (and in a 
number of cases, after the current attainment date) is a unique 
situation created by the Court's remand of the CAIR. Under normal 
circumstances adhering to the CAA schedule for addressing transport 
within 3 years after a NAAQS is promulgated, transport requirements 
would be in place years before the attainment date. For purposes of our 
analysis of ozone for areas with a 2012 attainment date, EPA proposes 
that we should not be constrained to only considering those reductions 
that are possible by 2012.
    Another reason that it would be inappropriate to limit upwind state 
responsibility based on the downwind area's current attainment date is 
that the statute contains provisions for extension of attainment dates. 
To the extent that downwind states have continuing ozone air quality 
problems after 2012, the Act requires that they be reclassified, which 
allows the downwind area to qualify for a later attainment date that is 
as expeditious as practicable but no later than 2019 (2018 emissions 
year).\62\ In addition, two 1-year attainment date extensions can be 
granted if an area comes close to attaining, based on specific 
criteria. In addition, history shows many examples of states not 
meeting air quality standards by their attainment deadlines, often due 
in part to interstate pollution transport. Even if a downwind area 
attains on time, further upwind reductions may be important to assure 
continued maintenance of the standard.
---------------------------------------------------------------------------

    \62\ In the case of PM2.5, under subpart I, areas can 
qualify for an extension beyond 5 years, to as many as 10 years, 
based on certain statutory criteria.
---------------------------------------------------------------------------

    If in determining upwind state reduction responsibilities EPA were 
to automatically assume that downwind states will attain on time 
despite pollution transport, this assumption would have the effect of 
absolving the upwind state of responsibility for any reductions in 
pollution transport that could not be achieved by the downwind area's 
current attainment date. EPA does not believe this would be 
appropriate. This would transfer emissions control responsibility from 
the upwind state to the downwind state in any case when the area did 
not attain by its current attainment date, and could delay for years 
the date when the public would breathe air that meets health-based 
standards.
    Accordingly, for all the reasons discussed previously, we address 
both 2012 and 2014 in our analysis, and we do not believe that 
examining 2012 only would be appropriate. EPA has chosen to examine 
2014 air quality results because, based on a conservative estimate, 
2014 is the earliest year for which significantly more stringent 
NOX limits (e.g., reflecting SCR) could conceivably be 
considered in a swift, subsequent rulemaking.
    One area in the eastern half of the U.S. covered by this proposal, 
Houston,

[[Page 45286]]

is classified as ``severe.'' For Houston, it is relevant to consider 
both that (1) the latest permissible attainment date for severe areas 
is June 2019, which would require emissions reductions by the 2018 
ozone season, and (2) the state implementation plan must provide for 
attainment as expeditiously as practicable. In light of this, EPA may 
select a year between 2012 and 2018 that is as expeditious as 
practicable as the appropriate year for eliminating significant 
contribution. Because, as explained later, further analysis is needed 
to quantify any additional reductions necessary to eliminate 
significant contribution to Houston, EPA requests comment on which year 
we should select within this 2012 to 2018 time period for this 
analysis.
(2) Step 1. Emissions Reductions Cost Curves for EGU Ozone Season 
NOX
    Using IPM, EPA developed cost curves for 2012 for ozone season 
NOX, showing the ozone season (May-September) NOX 
reductions available in 2012 at different cost increments. 
Specifically, EPA developed cost curves that show reductions available 
in 2012 from EGUs at various costs (in 2006 $) up to $5,000/ton. These 
EGU cost curves are presented in Table IV.D-7. Generally, projected 
emissions reductions for 2012 are modest because, by 2012, it is not 
feasible to install add-on equipment. Some highly effective and widely 
employed NOX control technologies such as SCR could not be 
planned and installed in significant numbers within a 1-year time 
period (i.e., because a single SCR unit on average takes 21 months to 
install,\63\ SCR-based limits in 2012, if feasible at all, would 
require an unacceptably steep cost premium).
---------------------------------------------------------------------------

    \63\ Estimate from EPA report, ``Engineering and Economic 
Factors Affecting the Installation of Control Technologies for 
Multi-Pollutant Strategies,'' CAIR docket no. OAR-2003-0053-0106).
---------------------------------------------------------------------------

    For some states (particularly those which are not regulated by the 
NOX SIP Call) EPA identified potential reductions from the 
installation of some combustion controls/low NOX burners and 
the use of existing SCR units that, in the absence of CAIR, would not 
be required to operate. These reductions are available at approximately 
$500/ton in 2012. There were very few emissions reductions available 
below this cost.

  Table IV.D-7--2012 Ozone-Season NOX Emissions From Electric Generating Units for Each State at Various Costs
                                         (2006$) per Ton (Thousand Tons)
----------------------------------------------------------------------------------------------------------------
     Marginal cost per ton          $0      $500    $1,000   $1,500   $2,000   $2,500   $3,000   $3,500   $5,000
----------------------------------------------------------------------------------------------------------------
Alabama........................       30       30       30       30       30       30       30       29       29
Arkansas.......................       21       11       11       11       11       11       11       11       11
Connecticut....................        3        3        3        3        3        3        3        3        3
Delaware.......................        2        2        2        2        2        2        2        2        2
Florida........................      101       74       60       59       59       59       59       58       57
Georgia........................       35       33       33       33       33       33       33       33       33
Illinois.......................       24       24       25       25       25       25       25       25       25
Indiana........................       51       50       49       48       47       47       47       46       46
Kansas.........................       31       15       15       15       14       14       14       14       14
Kentucky.......................       31       31       30       30       30       30       29       29       29
Louisiana......................       22       17       17       17       17       17       17       17       17
Maryland.......................       14       14       14       14       14       14       14       14       14
Michigan.......................       30       30       30       30       30       30       29       28       28
Mississippi....................       17        8        8        8        8        8        8        8        8
New Jersey.....................        7        7        7        7        7        7        7        7        7
New York.......................       16       16       16       16       16       16       16       16       16
North Carolina.................       27       27       27       27       27       27       27       27       27
Ohio...........................       42       41       41       41       41       42       42       42       42
Oklahoma.......................       43       27       27       27       27       26       26       26       26
Pennsylvania...................       51       51       51       51       50       50       50       50       48
South Carolina.................       16       16       16       15       15       15       15       15       15
Tennessee......................       12       12       12       12       12       12       12       12       12
Texas..........................       79       67       67       67        7       66       66       66       66
Virginia.......................       18       18       18       18       18       18       17       17       17
West Virginia..................       24       24       23       23       22       23       22       22       18
                                --------------------------------------------------------------------------------
    Total......................      746      648      632      628      625      622      620      618      609
----------------------------------------------------------------------------------------------------------------

    As discussed in section IV.D.3 later, little or no ozone season 
NOX reductions are available for non-EGU sources from 
control measures costing (at or below) $500/ton. The ozone season 
NOX cost curves in Table IV.D-7 include EGU reductions only. 
EPA believes that for costs at or below $500/ton, these curves include 
all available reductions (because only EGUs have substantial reduction 
opportunities at or below $500/ton), but for greater costs the curves 
do not include all available reductions as they do not include non-EGU 
reductions.
    For this reason, we are not addressing in this proposal whether 
cost per ton levels higher than $500/ton are justified for some upwind 
states and downwind receptors for ozone purposes. However, we are 
presenting the information we have on potential EGU reductions at 
higher cost levels for informational purposes. EPA intends to develop 
similar emissions reductions and cost information for sources other 
than EGUs and, in a future rulemaking, to consider whether or not 
reductions at a higher cost per ton are warranted for EGUs and other 
source categories.
    EPA developed EGU emissions reductions cost curves for 2014 as well 
as 2012. EPA believes it is useful to understand and display emissions 
reductions capabilities for 2014, the first year for which further 
emissions reductions could be achieved through the installation of add-
on controls such as SCR. These 2014 ozone season

[[Page 45287]]

emissions cost curves are presented in Table IV.D-8. The 2014 results 
have similarities to the 2012 results in that there is an initial drop 
in emissions when controls are applied at costs of $500 per ton, which 
represents the use of SCR units in states that would not be mandated to 
so. Also similar to the 2012 results, relatively few reductions are 
seen between $500/ton and $2,500/ton. In contrast to the 2012 results, 
add-on controls become feasible in 2014 at costs between $2,500/ton and 
$5,000/ton and more EGU emissions reductions are possible at those cost 
levels.

  Table IV.D-8--2014 Ozone-Season NOX Emissions From Electric Generating Units for Each State at Various Costs
                                         (2006$) per Ton (Thousand Tons)
----------------------------------------------------------------------------------------------------------------
     Marginal cost per ton          $0      $500    $1,000   $1,500   $2,000   $2,500   $3,000   $3,500   $5,000
----------------------------------------------------------------------------------------------------------------
Alabama........................       27       27       27       27       27       27       27       26       26
Arkansas.......................       22       12       12       12       12       11       11       11       12
Connecticut....................        3        3        3        3        3        3        3        3        3
Delaware.......................        2        3        3        3        3        3        3        3        3
Florida........................       95       72       58       57       57       56       53       43       37
Georgia........................       22       20       20       20       20       20       20       20       19
Illinois.......................       24       24       24       24       24       24       24       24       24
Indiana........................       49       48       48       47       47       47       46       44       43
Kansas.........................       35       16       16       16       16       16       16       15       15
Kentucky.......................       30       30       30       29       29       29       29       29       28
Louisiana......................       21       17       17       17       17       17       17       13       13
Maryland.......................       15       15       15       15       15       15       15       15       15
Michigan.......................       30       30       30       30       29       29       29       29       28
Mississippi....................       17        8        8        8        8        8        8        8        7
New Jersey.....................       10       10       10       10       10       10       10       10        9
New York.......................       17       17       17       16       16       16       15       15       15
North Carolina.................       27       27       27       27       27       27       27       27       26
Ohio...........................       45       44       43       43       42       42       42       41       38
Oklahoma.......................       39       24       24       24       24       23       23       23       20
Pennsylvania...................       53       53       52       52       52       52       52       52       41
South Carolina.................       16       16       15       15       15       15       15       15       15
Tennessee......................       12       12       12       12       12       12       12       12       12
Texas..........................       80       69       68       68       67       66       66       66       66
Virginia.......................       16       16       16       16       16       16       16       16       15
West Virginia..................       24       24       24       21       22       20       20       19       19
                                --------------------------------------------------------------------------------
    Total......................      732      639      621      614      610      604      598      579      547
----------------------------------------------------------------------------------------------------------------

(3) Step 2. Air Quality Assessment of Potential 2012 Emissions 
Reductions
    EPA uses an air quality assessment tool for ozone to assess the 
effect of NOX reductions on downwind ozone concentrations. 
This air quality assessment tool assumes a linear relationship between 
the reduction in an upwind state's ozone season NOX 
reductions and the reduction in that state's contribution to downwind 
ozone levels. For example, if a given upwind state reduced its ozone 
season NOX emissions by 20 percent, the air quality 
assessment tool estimates that there would also be a 20 percent 
reduction in the state's contribution to downwind ozone. Using this 
assessment tool, EPA projected the air quality impact of the emissions 
reductions at the $500/ton NOX level, the level for which we 
have complete estimates of potential emissions reductions. The 
assessment shows significant improvements in 2012 at downwind air 
quality locations, as evidenced by a reduction in the number of 
nonattainment and maintenance locations. EPA presents these 2012 ozone 
season results in Table IV.D-9.
    EPA also includes in Table IV.D-9 results for 2014 before and after 
the imposition of currently installed controls (that is, for the base 
case or zero dollars per ton, and for the case for which all controls 
are applied up to $500/ton). Because there are substantial reductions 
in ozone season NOX from mobile source fleet turnover 
between 2012 and 2014, there are correspondingly substantial 
improvements in ozone in the base case, even in the absence of 
additional EGU or other stationary source controls. Additionally, in 
this 2014 analysis, when these mobile source reductions are combined 
with EGU reductions at $500/ton, the simplified air quality assessment 
tool projects that almost all sites, with the exception of Houston, TX 
(nonattainment) and Baton Rouge, LA (maintenance), have resolved their 
ozone problems.

Table IV.D-9--Estimated Number of Remaining Nonattainment or Nonattainment and Maintenance Monitor Sites in 2012
                         and 2014 as a Function of Ozone-season NOX Cost per Ton Levels
----------------------------------------------------------------------------------------------------------------
                                         2012            2012                2014                   2014
----------------------------------------------------------------------------------------------------------------
                                                       Number of
                                       Number of       Remaining                            Number of Remaining
                                       Remaining     Nonattainment   Number of Remaining     Nonattainment and
       Marginal Cost per Ton         Nonattainment        and       Nonattainment Monitor   Maintenance Monitor
                                     Monitor Sites    Maintenance           Sites                  sites
                                                     Monitor Sites
----------------------------------------------------------------------------------------------------------------
>$0...............................              11              25  4 (all in Houston,     7 (Houston, TX; Baton
                                                                     TX).                   Rouge, LA).
>$500.............................              10              19  1....................  7.
----------------------------------------------------------------------------------------------------------------


[[Page 45288]]

(4) Step 3. Selection of Cost Thresholds, Taking Into Account Cost and 
Air Quality Considerations
    Using the multi-factor cost and air quality methodology described 
in section IV.D.1, EPA identifies, for a number of states, the 2012 
emissions reductions that eliminate the significant contribution to 
nonattainment of the 1997 ozone NAAQS and interference with maintenance 
to the 1997 ozone NAAQS.
(a) Cost Considerations
    As discussed previously, $500/ton represents the cost level for 
which EPA has complete information across source categories and 
represents the level for which significant emissions reductions are 
available in 2012. Large additional reductions in 2012 cannot be 
achieved given the insufficient amount of time for sources to install 
controls. Compared to NOX reduction levels determined to be 
highly cost effective in both the NOX SIP Call and the CAIR, 
$500/ton is a very low cost for requiring ozone season NOX 
reductions, and reductions at this level show measurable downwind air 
quality benefit. EPA believes that $500/ton continues to be an 
extremely cost effective level for NOX control relative to 
benchmarks provided by the cost per ton of NOX reductions in 
existing rules or available from technologies in various sectors, and 
the $500/ton level is based on proven and widely deployed technology.
    Considering the upwind-downwind state policy considerations 
discussed previously, $500/ton NOX clearly is not an 
unreasonable cost level of control for all upwind states that 
contribute more than threshold amounts to ozone air quality problems in 
downwind states.
    EPA believes that on purely reasonableness or highly cost effective 
grounds, a value considerably greater than $500/ton could be justified. 
EPA notes that the $2,000/ton threshold for highly cost effective ozone 
season NOX controls for the NOX SIP Call was 
calculated based on 1990 dollars. If this threshold were updated based 
on a more recent year, such as the 2006 year used for recent EPA RIA 
documents, the $2,000/ton threshold would become approximately $3,200 
per ton. As a result, EPA believes that controlling to at least this 
level should be considered, unless air quality considerations suggest 
an ``off-ramp'' at lower cost levels.
(b) Air Quality Considerations
    Using the air quality assessment tool, EPA determined that 
emissions reductions from ozone season NOX controls at $500/
ton would have a significant reduction in nonattainment and maintenance 
receptors in 2012. Accordingly, EPA believes that requiring the 
reductions that can be achieved at $500/ton are justified based upon 
the 2012 air quality results.
    EPA proposes, as discussed previously, that EPA is not artificially 
constrained in considering reductions beyond 2012 and that it is 
relevant to address possible air quality impacts of additional 
emissions reductions that could be achieved by 2014, the first year for 
significant additional controls. At the same time, EPA proposes that 
while 2014 is a relevant year to consider, it is also relevant to 
consider the nature of the air quality problem in 2014 even in the 
absence of further transport controls that could be achieved by that 
date. Taking all of these 2014 considerations into account, the air 
quality assessment tool results show that in 2014 ozone problems remain 
only for locations in Houston and Baton Rouge. Thus, EPA believes that 
additional post-2012 controls, beyond the $500/ton reductions that are 
justified based on 2012, are possibly warranted for states that are 
linked to Houston and Baton Rouge. (See also discussion later on the 
issue regarding New York City raised by air quality modeling results.)
(c) Proposed Cost Threshold for Ozone
    Based on the cost and air quality considerations, EPA proposes 
$500/ton as the appropriate cost threshold for the following states 
which contribute to downwind nonattainment and/or maintenance problems 
in 2012, but which are not linked to ozone air quality problems in 
either Houston or Baton Rouge: Connecticut, Delaware, the District of 
Columbia, Indiana, Iowa, Kansas, Maryland, Massachusetts, New Jersey, 
New York, North Carolina, Ohio, Oklahoma, Pennsylvania, South Carolina, 
Virginia, and West Virginia.
    For states linked to ozone air quality problems in Houston or Baton 
Rouge, EPA has not yet identified a cost threshold for eliminating 
significant contribution. EPA does, however, propose to find that those 
states must make at least all of the reductions that can be achieved 
for $500/ton in 2012. These states are: Alabama, Arkansas, Florida, 
Georgia, Illinois, Kentucky, Louisiana, Mississippi, Tennessee, and 
Texas. For these states, the $500/ton threshold represents emissions 
reductions that EPA believes are an essential part of the ultimate 
emissions reductions amount that will be required to eliminate the 
significant contribution and interference with maintenance. This level 
does not represent a complete significant contribution determination 
for these states because neither the analysis of costs up to $500/ton, 
nor the analysis of air quality impacts of the corresponding emissions 
reductions, suggest that those reductions necessarily represent all 
reasonable upwind state reductions. For the reasons stated previously 
in subsection 2.b, EPA believes it is appropriate and consistent with 
the statutory mandate to consider whether section 110(a)(2)(D)(i)(I) 
requires further reductions from these states after 2012 for purposes 
of the 1997 ozone standard.
    To determine whether further reductions are warranted, EPA is 
expeditiously conducting further analysis. EPA is continuing to develop 
and evaluate NOX control costs, emissions reductions, and 
air quality impact information for NOX controls greater than 
$500/ton, and to examine facts involving Houston and Baton Rouge, to 
support a complete determination of significant contribution and 
interference with maintenance for states that contribute to one or both 
of those areas. Based on the analysis done for today's proposal, EPA 
believes that any additional NOX reduction requirements 
would involve reductions from sources beyond EGUs. If this is the case, 
EPA believes it is likely that we could provide the greatest assistance 
to states in addressing transport by promulgating a separate rule to 
achieve those NOX reductions. EPA believes that developing 
supplemental information to address these sources beyond EGUs would 
substantially delay publication of a final rule, beyond the anticipated 
publication of spring 2011. While EPA intends to move forward 
aggressively on this issue in gathering the necessary information, EPA 
does not believe that this effort should delay the reductions and large 
health benefits associated with this proposed rule. EPA fully intends 
to proceed with additional rulemaking to fully address the residual 
significant contribution to nonattainment and interference with 
maintenance as quickly as possible.
(5) Request for Comment Concerning New York City and Contributing 
States
    As in the case of PM2.5, EPA has done additional refined 
air quality analysis of a 2014 scenario that assumes implementation of 
the proposed ozone season NOX emissions reductions, that is, 
the reductions that would be achieved based on the $500/ton 
NOX cost threshold. This air quality analysis, conducted 
with the CAMx model, can be compared to the results using the air 
quality assessment tool. The CAMx modeling demonstrated that the

[[Page 45289]]

required NOX reductions would assist many downwind areas 
with achieving and maintaining the NAAQS. The CAMx air quality modeling 
for 2014 confirmed the conclusion that Houston and Baton Rouge would 
continue to have nonattainment/maintenance concerns even with the 
reduction of NOX emissions that could be reduced for (at or 
below) $500/ton. The modeling also showed that the locations within the 
New York City nonattainment area would continue to have a maintenance 
problem despite the modeled reductions (including those in New York 
State). That is, the New York City area is possibly at risk of being in 
nonattainment in light of historical year-to-year variability in ozone 
levels in the New York City area. For that reason, EPA is taking 
comment on whether it should consider and analyze the NOX 
reductions that can be achieved for greater than $500/ton in states 
that are linked to the New York area sites. These states include: 
Connecticut, Delaware, Indiana, Kentucky, Maryland, New Jersey, North 
Carolina, Ohio, Pennsylvania, Virginia, and West Virginia. If EPA were 
to conclude that additional analysis is necessary, it would present the 
results of this in a future notice that would also consider whether and 
to what extent states linked to New York City, Houston, and Baton Rouge 
should be required to make additional NOX reductions in 
order to eliminate all significant contribution with respect to the 
1997 ozone NAAQS.
3. Discussion of Control Costs for Sources Other Than EGUs
    Previously in this section (see discussion in IV.D.2 previously) 
EPA discusses its proposed cost criteria for identifying SO2 
and NOX emissions reductions necessary to eliminate at least 
part of each state's significant contribution and to eliminate at least 
part of each upwind state's interference with maintenance of the 
PM2.5 NAAQS. In addition, EPA discusses interim cost 
criteria for ozone. Consistent with these criteria, EPA does not 
believe that other source categories have emissions that are currently 
significantly contributing to nonattainment or interfering with 
maintenance of the 1997 and 2006 PM2.5 NAAQS. Thus, with 
respect to the 1997 and 2006 PM2.5 NAAQS, we are not 
proposing to include in the FIPs emissions reductions requirements for 
other source categories.
(a) SO2 Sources and Costs
    As described previously, EPA is proposing to define significant 
contribution on the basis of cost informed by air quality impacts, and 
to conclude $2,000/ton represents the highest cost value necessary for 
SO2 to eliminate significant contribution and interference 
with maintenance. For SO2, as described previously, EPA is 
proposing to conclude that significant contribution and interference 
with maintenance would be eliminated at costs of no more than $2,000/
ton, and in some states, at lower costs. The EPA has not identified 
SO2 reductions for sources other than EGUs at $2,000/ton or 
less (in year 2006 $).
    For the CAIR, EPA included a technical support document \64\ which 
noted that for SO2, EGUs were the dominant contributor to 
transported emissions, but that there were a few additional categories 
for which regional emissions exceeded 1 percent of the overall 
inventory in the eastern half of the U.S. EPA has updated this analysis 
with a review of the year 2012 inventory, with similar conclusions. See 
TSD--``Non-EGU Emissions Reductions Cost and Potential.'' The highest-
emitting categories of non-EGU SO2 emissions are: (1) 
Industrial, commercial, and institutional (ICI) boilers, (2) Portland 
cement manufacturing, (3) petroleum refining, and (4) sulfuric acid 
manufacturing.
---------------------------------------------------------------------------

    \64\ Identification and Discussion of Sources of Regional Point 
Source NOX and SO2 emissions other than EGUs. 
EPA/OAQPS and CAMD. January 2004.
---------------------------------------------------------------------------

    For ICI boilers, most of the SO2 emissions are from 
coal-fired boilers, and to a lesser degree from residual or distillate 
oil-fired boilers. Possible ways to reduce SO2 emissions 
from ICI boilers include fuel switching, flue gas desulfurization, and 
dry sorbent duct injection. Because of variability in operations, it is 
difficult to identify precise cost per ton estimates for fuel switching 
and sorbent injection. For industrial boilers, the capacity factor 
(that is, the fraction of boiler capacity that is used in a year) can 
have a significant impact on the cost per ton estimate. Regarding flue 
gas desulfurization, a recent report prepared by NESCAUM \65\ suggests 
scrubber costs are typically well above $2,000/ton for ICI boilers.
---------------------------------------------------------------------------

    \65\ Reference: NESCAUM Applicability and Feasibility of 
NOX, SO2, and PM Emissions Control 
Technologies for Industrial, Commercial, and Institutional (ICI) 
Boilers. NESCAUM, November 2008. pp. xvii, 3-12-13.
---------------------------------------------------------------------------

    For Portland cement manufacturing, information from a 2006 report 
prepared by the Lake Michigan Air Directors Consortium (LADCO) 
estimated costs for SO2 scrubbing to be between $2,211-6,917 
per ton (in year 2003 $). The LADCO ``white papers'' discussion is 
available from the following Web site: http://www.ladco.org/reports/
control/final_reports/identification_and_evaluation_of_candidate_
control_measures_ii_june_2006.pdf.
    For petroleum refining, the largest sources of SO2 
emissions are from catalytic cracking, sulfur recovery units, and 
process heaters. For each of the sources in the petroleum refining 
sector, EPA believes that SO2 controls at or below $2,000/
ton will generally not be available at refineries covered by the recent 
settlement agreements EPA has entered into with numerous petroleum 
refineries. Moreover, such agreements cover 88 percent of U.S refining 
capacity, and will lead to up to 250,000 tons of SO2 
emissions reductions annually. Compliance with these agreements has 
already taken place at most affected refineries, and these reductions 
are generally reflected in our 2012 base case emissions inventory.\66\
---------------------------------------------------------------------------

    \66\ U.S. EPA. Petroleum Refinery National Priority Case 
Results. Available at http://www.epa.gov/compliance/resources/cases/
civil/caa/oil/index.html.
---------------------------------------------------------------------------

    For sulfuric acid manufacturing, the SO2 emissions are 
related to the percent recovery of sulfuric acid product. Because the 
percent recovery is plant-specific, the available emissions reductions 
and the cost per ton of controls are highly variable. At the time of 
the CAIR, EPA made rough calculations that the then-existing 126,000 
tons of SO2 would be reduced by about one-half if all of the 
sulfuric acid manufacturing in the eastern U.S. was controlled to meet 
the NSPS level of 4 pounds of SO2 per ton of product. EPA 
did not develop cost estimates for these approximate reductions and 
such cost estimates are still not available. EPA notes, however, that 
it has entered into a number of settlement agreements with sources in 
the sulfuric acid production industry, and a significant amount of the 
estimated available reductions has already been realized. Over 36,000 
tons of SO2 reductions have taken place at 22 plants in the 
U.S. by 2012 as a result of 6 settlement agreements.\67\ More than half 
of these plants are in states affected by this proposal.
---------------------------------------------------------------------------

    \67\ U.S. EPA. Acid Plant NSR Enforcement Priority. Available at 
http://www.epa.gov/compliance/civil/caa/acidplant-nsr/index.html.
---------------------------------------------------------------------------

    This information shows that few if any SO2 reductions 
are available from other source categories and thus, along with other 
information available to EPA, supports EPA's proposal not to include 
non-EGU SO2 reduction requirements for addressing 
PM2.5 transport for the proposed rule. EPA seeks comment on 
whether non-EGU emissions reductions should be required and on the 
specific

[[Page 45290]]

control measures that would serve as the basis for those reductions.
    Because sulfur content of both gasoline and diesel fuel are now 
subject to very stringent sulfur requirements, EPA believes there are 
no available on-road and nonroad engine measures to reduce mobile 
source SO2 at or below $2,000/ton.
b. NOX From Non-EGU Sources
    For NOX, the methodology described previously in section 
IV.D.2 requires all states linked to PM2.5 nonattainment and 
maintenance areas to ensure that emissions do not increase above 2009 
levels. This translates into a cost cutoff of $500/ton. In addition, 
for ozone, EPA determined that a number of states can eliminate their 
significant contribution and interference with maintenance by 
installing controls at this same $500/ton cost threshold.
    For the CAIR, the technical support document \68\ evaluating non-
EGU controls contained a discussion of non-EGU category contributions 
to the overall NOX emissions inventory and a discussion of 
available controls. This analysis identified source categories for 
which regional emissions exceeded 1 percent of the overall inventory in 
the eastern half of the U.S. EPA has updated this analysis of non-EGU 
NOX controls done for the CAIR with a review of the year 
2012 inventory. See TSD--``Non-EGU Emissions Reductions Cost and 
Potential.'' The highest-emitting stationary source categories of non-
EGU NOX emissions are: (1) Stationary reciprocating internal 
combustion engines (RICE), (2) industrial, commercial, and 
institutional (ICI) boilers, (3) Portland cement manufacturing, (4) 
petroleum refining, (5) glass manufacturing, (6) pulp and paper 
production, and (7) iron and steel production.
---------------------------------------------------------------------------

    \68\ Identification and Discussion of Sources of Regional Point 
Source NOX and SO2 emissions other than EGUs. 
EPA/OAQPS and CAMD. January 2004.
---------------------------------------------------------------------------

    EPA has not identified additional non-EGU controls that can be 
achieved at $500/ton or less. For example, available information \69\ 
suggests that costs of various types of NOX controls are 
greater than this level for non-EGU sources such as ICI boilers, iron 
and steel mills, petroleum refineries, \70\ glass manufacturing plants, 
and asphalt manufacturing plants. For industrial boilers, a recent 
report prepared by NESCAUM \71\ suggests NOX control costs 
are typically well above $500/ton for ICI boilers. In addition, a 
recent report prepared by LADCO \72\ indicated NOX control 
costs are also well above $500/ton for glass manufacturing plants and 
asphalt manufacturing plants.
---------------------------------------------------------------------------

    \69\ Reference: Identification and Evaluation of Candidate 
Control Measures. Phase II Final Report. LADCO, June. 2006. Appendix 
B.
    \70\ Reference: Assessment of Control Technology Options For 
Petroleum Refineries in the Mid-Atlantic Region. Final Report. 
MARAMA, January 2007. p. 2-24.
    \71\ Reference: NESCAUM Applicability and Feasibility of 
NOX, SO2, and PM Emissions Control 
Technologies for Industrial, Commercial, and Institutional (ICI) 
Boilers. NESCAUM, November 2008. pp. xvii, 3-12-13.
    \72\ Reference: Identification and Evaluation of Candidate 
Control Measures. Phase II Final Report. LADCO, June 2006. Appendix 
B.
---------------------------------------------------------------------------

    For the NOX SIP Call, EPA identified a number of 
categories where costs were less than $2,000/ton (1990 dollars), 
including large ICI boilers with capacities greater than 250 million 
BTU/hour, cement kilns, and large RICE emitting more than 1 ton 
NOX per day. For each of these categories regulated under 
the NOX SIP Call, EPA believes there are no available 
control measures (especially that could be implemented by 2012) at or 
below $500/ton.
    EPA has not identified further controls for stationary nonpoint 
sources or mobile source NOX measures that have costs at or 
below $500 per ton.

E. State Emissions Budgets

    As described later, EPA used the cost thresholds identified for 
each covered state in the previous section and applied them to state-
specific data to develop individual state emissions budgets. These 
budgets facilitate implementation of the requirement that significant 
contribution and interference with maintenance be eliminated. A state's 
emissions budget is the quantity of emissions that would remain in that 
state from covered sources after elimination of that portion of each 
state's significant contribution and interference with maintenance that 
EPA has identified in today's proposal, before accounting for the 
inherent variability in power system operations (see discussion of 
variability in section IV.F, later). The state emissions budget is a 
mechanism for converting the quantity of emissions that a state must 
reduce (i.e., the state's significant contribution and interference 
with maintenance) into enforceable control requirements. In other 
words, it provides a quantity of emissions to use in developing a 
remedy (e.g., the remedy should be designed to achieve the budget in an 
average year).
    Because the budget represents emissions that would remain without 
accounting for variability, it also represents the amount of emissions 
that would remain after significant contribution and interference with 
maintenance have been addressed, in an average year. In a year when 
base case emissions would have been higher than average (e.g., because 
a large nuclear unit was out of service and more fossil-fuel-fired 
generation was needed), the emissions that would remain after 
significant contribution and interference with maintenance had been 
addressed also would be higher. The variability limits discussed in 
section IV.F address this issue. Application of variability limits in 
the remedies is described in section V.D.
1. Defining SO2 and Annual NOX State Emissions 
Budgets for EGUs
    For group 1 states required to make deeper emissions reductions in 
2014, EPA based each state's 2014 budgets on the same projections from 
IPM that were used as inputs into the cost curves explained in section 
IV.D.2.a previously. For SO2, the values were taken from an 
IPM run requiring all SO2 reductions available at $2,000/
ton. For group 2 states (and for the first phase 2012 budgets for 
sources required to make greater reductions in 2014), EPA took a 
different approach. These states are only required to make 
SO2 reductions that could be made through (1) the operation 
of existing scrubbers, (2) scrubbers that are expected to be built by 
2012 and (3) the use of low sulfur coal. Because those strategies were 
already being applied in most states covered by this rule in 2009,\73\ 
EPA believes that the actual performance units achieved in 2009 is more 
representative of expected emissions than what EPA modeled using IPM. 
This is because real data takes into account actual unit by unit 
information that is represented at a more aggregate level in IPM. The 
only exception to this rule is if a source was modeled to install a 
scrubber by 2012 (because of rules requiring that installation and/or 
because of information that the company had already contracted to 
install a scrubber). In this case, EPA adjusted emissions from the unit 
to account for the new scrubber.
---------------------------------------------------------------------------

    \73\ Even though allowance prices dropped significantly in 2008 
after the Court decision, most sources appear to have continued with 
the same reduction strategies.
---------------------------------------------------------------------------

    For 2012 NOX budgets, EPA used the same general 
methodology for all states that was used for the group 2 states for 
SO2. The $500/ton cost threshold, that EPA has determined 
can be used to calculate the minimum significant contribution from 
upwind states linked to downwind nonattainment and maintenance areas, 
almost exclusively

[[Page 45291]]

represents reductions from turning on SCR units. EPA believes that 
instead of defining the budgets based on IPM projections of what will 
happen when SCR units are turned on, it is better to use real data, 
therefore EPA has developed budgets based on a combination of 
historical heat input, historical emissions rates, and, where new SCR 
units are expected between now and 2012, projected emissions rates for 
those new SCR units. The emissions budgets developed using the previous 
methodology are as follows in Table IV.E-1:

  Table IV.E-1--SO2 and Annual NOX State Emissions Budgets for Electric Generating Units Before Accounting for
                                                 Variability 74
                                                     [Tons]
----------------------------------------------------------------------------------------------------------------
                                                                   SO2, 2012 and   SO2, 2014 and    NOX annual,
                              State                                    2013            later         all years
----------------------------------------------------------------------------------------------------------------
Alabama.........................................................         161,871         161,871          69,169
Connecticut.....................................................           3,059           3,059           2,775
Delaware........................................................           7,784           7,784           6,206
District of Columbia............................................             337             337             170
Florida.........................................................         161,739         161,739         120,001
Georgia.........................................................         233,260          85,717          73,801
Illinois........................................................         208,957         151,530          56,040
Indiana.........................................................         400,378         201,412         115,687
Iowa............................................................          94,052          86,088          46,068
Kansas..........................................................          57,275          57,275          51,321
Kentucky........................................................         219,549         113,844          74,117
Louisiana.......................................................          90,477          90,477          43,946
Maryland........................................................          39,665          39,665          17,044
Massachusetts...................................................           7,902           7,902           5,960
Michigan........................................................         251,337         155,675          64,932
Minnesota.......................................................          47,101          47,101          41,322
Missouri........................................................         203,689         158,764          57,681
Nebraska........................................................          71,598          71,598          43,228
New Jersey......................................................          11,291          11,291          11,826
New York........................................................          66,542          42,041          23,341
North Carolina..................................................         111,485          81,859          51,800
Ohio............................................................         464,964         178,307          97,313
Pennsylvania....................................................         388,612         141,693         113,903
South Carolina..................................................         116,483         116,483          33,882
Tennessee.......................................................         100,007         100,007          28,362
Virginia........................................................          72,595          40,785          29,581
West Virginia...................................................         205,422         119,016          51,990
Wisconsin.......................................................          96,439          66,683          44,846
                                                                 -----------------------------------------------
    Total.......................................................       3,893,870       2,500,003       1,376,312
----------------------------------------------------------------------------------------------------------------

    For more detail on how the budgets were developed, see the TSD: 
``State Budgets, Unit Allocations, and Unit Emissions Rates''.
---------------------------------------------------------------------------

    \74\ The impact of variability on the budgets is discussed in 
section IV.F, later.
---------------------------------------------------------------------------

2. Defining Ozone Season NOX State Emissions Budgets for 
EGUs
    Ozone season NOX budgets were developed the same way as 
the annual NOX budgets were developed (explained in IV.E.1, 
previously).

   Table IV.E-2--Ozone-season NOX State Emissions Budgets for Electric
           Generating Units Before Accounting for Variability
                                 [Tons]
------------------------------------------------------------------------
                                                              NOX ozone
                           State                             season, all
                                                                years
------------------------------------------------------------------------
Alabama....................................................       29,738
Arkansas...................................................       16,660
Connecticut................................................        1,315
Delaware...................................................        2,450
District of Columbia.......................................          105
Florida....................................................       56,939
Georgia....................................................       32,144
Illinois...................................................       23,570
Indiana....................................................       49,987
Kansas.....................................................       21,433
Kentucky...................................................       30,908
Louisiana..................................................       21,220
Maryland...................................................        7,232
Michigan...................................................       28,253
Mississippi................................................       16,530
New Jersey.................................................        5,269
New York...................................................       11,090
North Carolina.............................................       23,539
Ohio.......................................................       40,661
Oklahoma...................................................       37,087
Pennsylvania...............................................       48,271
South Carolina.............................................       15,222
Tennessee..................................................       11,575
Texas......................................................       75,574
Virginia...................................................       12,608
West Virginia..............................................       22,234
                                                            ------------
    Total..................................................      641,614
------------------------------------------------------------------------

    These budgets are based on a 5 month ozone season (May 1 through 
September 30). Consistent with the approach taken by the OTAG, the 
NOX SIP Call, and the CAIR, we propose to define the ozone 
season, for purposes of emissions

[[Page 45292]]

reductions requirements in this rule, as May through September. We 
recognize that this ozone season for regulatory requirements will have 
differences from the official state-specific ozone monitoring season. 
EPA requests comment on whether the budgets for the final rule should 
be based on a longer ozone season, such as March through October.

F. Emission Reduction Requirements Including Variability

    In this section, EPA discusses the inherent variability in electric 
power system operation and presents proposed variability limits for 
each state. As explained below, EPA proposes to calculate variability 
limits for each state and to use those variability limits in 
conjunction with the budgets (which are based on expected average 
conditions) to provide limited flexibility (within the limits allowed 
by the variability provisions) to address years in which more fossil 
generation occurs than projected in the average base case year. This 
section also presents projected emission reduction results.
1. Variability
a. Introduction to Power Sector Variability
    Historically, power sector emissions have varied over time. 
Factors, such as fuel switching and installing new emissions controls, 
which can lead to significant decreases in emissions, primarily affect 
emissions rates rather than generation and change largely as a result 
of pollution regulation.
    Even when emissions rates do not change from year to year, overall 
emissions can change because of factors including power demand, timing 
of maintenance activities, and unexpected shutdowns of units. Extreme 
weather conditions, sudden economic shocks, and other unpredictable 
events can also significantly impact power generation from fossil 
units. These factors relate directly to heat input, generation, and the 
routine operation of power plants to supply our electricity, and thus 
affect total emissions.
    As discussed previously, EPA has identified a specific amount of 
emissions that must be prohibited by each state to satisfy the 
requirements of CAA section 110(a)(2)(D)(i)(I). EPA has also developed 
state budgets based on its projections of state emissions in an average 
year after the elimination of such emissions. However, because of the 
unavoidable variability in baseline emissions--resulting from the 
inherent variability in power plant operations--state-level emissions 
may vary somewhat after all significant contribution and interference 
with maintenance that EPA has identified in this proposal are 
eliminated. This occurs even when the emissions rates of the units 
within the state do not change. For this reason, EPA has determined 
that it is appropriate to develop variability limits for each state 
budget. These limits are used to identify the range of emissions that 
EPA believes may occur in each state following the elimination of all 
significant contribution and interference with maintenance.
    For the proposed rule, EPA proposes to factor this variability 
explicitly in its consideration of how to control emissions. The Agency 
believes that because baseline emissions are variable, emissions after 
the elimination of all significant contribution are also variable and 
thus it is appropriate to take this variability into account.
    As discussed in detail in section V, EPA proposes and considers 
specific regulatory remedies that are designed to meet the emissions 
budget in an average year. Because base case emissions may vary from 
projections, EPA believes these same remedies may incorporate 
provisions that account for variability. This variability, however, 
must be limited to provide downwind states with assurance that 
necessary reductions will be made in upwind states. This section 
describes how EPA calculated variability limits for each state to 
achieve this goal.
    Remedies (i.e., regulatory approaches for achieving emissions 
reductions) can range from emissions rate-based ``direct control'' 
options to options which allow for interstate trading. EPA believes 
that inherent variability in power system operations affects each 
state's baseline emissions and thus also affects a state's emissions 
after elimination of all significant contribution and interference with 
maintenance. Thus, emissions may vary somewhat after implementation of 
the remedies under consideration. Under an emissions rate-based 
approach, emissions rate limits could be developed that would meet the 
budget assuming a given pattern of operation for the affected units. If 
some of the units with higher emissions rates actually operated more 
than projected, the state's actual emissions would be higher. In an 
interstate trading program, budgets could be developed that each state 
would be projected to meet in an average year. In some years, however, 
generation from units in one state may increase (with a corresponding 
increase in emissions), but because variability in a larger region is 
less significant than within a single state, the increase in one state 
would be expected to be offset by decreases in other states. Finally, 
even in an intrastate-only trading program, the ability to bank 
allowances could mean that in one year, emissions would be below the 
budget, while in another year they would be above.
    In all these cases, variability limits can be used to retain the 
flexibilities that the various remedies provide to deal with real-world 
variability in the operating system, while still providing downwind 
states reasonable certainty about the level of upwind emissions.
    EPA also notes that explicit consideration of variability in the 
emissions resulting from a remedy is consistent with removing a state's 
``significant contribution.'' As noted previously, even if the 
emissions result is variable from year to year, there is still a 
similar increment of emissions reductions. For example, because 
increased emissions in the control case would also correspond to 
increased emissions in the base case, the increment of emissions 
representing significant contribution and interference with maintenance 
would still be removed. Finally, as is explained more below in IV.F.b, 
the variability limits (as applied, for instance, in the State Budgets/
Limited Trading remedy in section V.D.4) are relatively low and thus 
the total amount of variability allowed is very small compared to total 
EGU emissions and even smaller when considering all of the emissions 
within a state. It is also worth noting that in the proposed State 
Budgets/Limited Trading remedy, variability is taken into account in 
such a way that does not allow an overall increase in emissions. Under 
this remedy, an individual state could emit up to its budget plus 
variability limit. However, the requirement that all sources hold 
allowances to cover emissions, and the fact that those allowances are 
allocated based on state-specific budgets absent variability, would 
ensure that total emissions do not increase. This remedy, therefore, 
ensures not only that total emissions do not increase above state 
budgets, but also that reductions occur in each and every state.
b. How EPA Accounted for Inherent Power Sector Variability
    EPA determined 1-year variability limits and 3-year rolling average 
variability limits for each state. First, EPA determined 1-year 
variability limits based on historical variability in heat input. 
Second, EPA determined 3-year rolling average variability limits using 
statistical methods to convert the 1-year variability into 3-year 
variability. The approaches EPA used to determine the

[[Page 45293]]

1-year and 3-year limits are summarized later and described in more 
detail in the Power Sector Variability TSD.
    Expected variability over a single year. EPA performed analyses 
using historical data to demonstrate that there is year-to-year 
variability in baseline emissions (even when emissions rates for all 
units are held constant) and to quantify the magnitude of this 
variability. This year-to-year variability in emissions is reflected, 
in combination with other factors, in year-to-year variability in air 
quality.
    The focus of the analysis is on quantifying the magnitude of the 
inherent variability in the baseline emissions (on both a 1-year and a 
3-year basis). The goals of this analysis, therefore, are to determine 
the typical variability in emissions that is due to changes in 
generation, and not due to changes in emission limits, and to set 
emissions criteria limits that can be used as part of a remedy to 
ensure that states are eliminating their significant contribution and 
interference with maintenance to protect air quality.
    EPA used statewide average emissions rates projected using IPM to 
convert historical heat input variability into corresponding emissions 
variability limits. The approach assessed the variability in state-
level heat input over a 7-year time period (2002 through 2008) using 
the standard deviation and then determined the difference in emissions 
from the 95th percent two-tailed confidence level and the mean.\75\ The 
approach resulted in a maximum allowable variability, in tons, for each 
state. These values were then divided by the mean emissions values over 
the 7-year time period to yield a percentage variability value for each 
state. See the Power Sector Variability TSD for details.
---------------------------------------------------------------------------

    \75\ The two-tailed 95th percent confidence level is the 
equivalent of the 97.5th upper (single-tailed) confidence level.
---------------------------------------------------------------------------

    From the state-by-state tonnage and percentage emission variability 
values, EPA identified a single set of variability levels (that is, a 
tonnage and a percentage) based on the historic variability. EPA made 
the decision to adopt a single, uniform tonnage and percentage level 
pairing 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. The effect of the pairing is to 
ensure that each state is allowed adequate variability while minimizing 
the total amount of emissions allowed. Using, for all states, only a 
constant percentage (reflecting emissions variability in smaller states 
with a greater range of emissions in percentage terms) would result in 
large states being allowed greater variability than needed. Conversely, 
using only a constant tonnage (reflecting emissions variability in 
larger states with a greater range of emissions in tonnage terms) would 
result in small states being allowed greater variability than needed. 
To ensure adequate variability limits--even in states with small 
numbers of units where expected variability would be more pronounced in 
percentage terms, and in large states where expected variability would 
be more pronounced in absolute tonnage terms--EPA derived variability 
limits both as a percentage and in terms of absolute emissions (tons) 
that serve to minimize the total amount of emissions allowed under this 
combination variability limit approach.
    For the tonnage and percentage limit criteria, EPA looked at a wide 
range of percentage and tonnage combinations, and chose for further 
investigation combinations that provided states sufficient variability 
limits (based on historic variability) and fit the requirement of 
minimizing the allowed emissions. Power plants in states that were 
close to the variability limits were evaluated more closely to ensure 
the modeling reflected all controls known to operate. EPA believes that 
the chosen limits would not be tighter than these states could be 
expected to meet.
    This approach (identifying both a tonnage and a percentage) 
addresses the difficulty that smaller states with fewer units could 
face if only percentages were used to set the limits. For instance, in 
a small state with a budget of 5,000 tons of SO2, an 
infrequently used unit that on average emitted 500 tons when it 
operated 10 percent of the time could increase its emissions to 1,500 
tons by operating 30 percent of the time in a year when there is 
unusually high demand for that unit. That would result in a 20 percent 
increase in statewide emissions. In a much larger state, with a budget 
of 50,000 tons, such a change in operation would only lead to a 1 
percent change in statewide emissions.
    For both annual NOX and SO2, the percentage 
variability limits are 10 percent of a state's budget and the 
corresponding tonnage variability limits are 5,000 and 1,700 tons for 
NOX and SO2, respectively. These are the values 
that result from the approach described previously, i.e., these 
variability levels allow the necessary variability for every state 
based on its historic variability, while minimizing the amount of 
emissions allowed.
    EPA assigned each state one of these values--either the tonnage 
limit or the percent limit, whichever was greater for that state. For 
instance, 10 percent of Connecticut's SO2 budget is less 
than 1,700 tons, so Connecticut received a 1-year 1,700 ton variability 
limit for its EGU SO2 emissions. EGU sources in Connecticut 
could emit up to the state's SO2 budget plus the variability 
limit of an additional 1,700 tons of SO2 in a year, and 
still eliminate the state's significant contribution and interference 
with maintenance. Proposed 1-year variability limits for each covered 
state are shown in the tables in section IV.F.2, later. See the Power 
Sector Variability TSD for more details on EPA's variability approach.
    Expected variability over a 3-year time period. Because air quality 
is assessed under the Act annually on a rolling 3-year time period, EPA 
believes that it is appropriate to also evaluate the inherent 
variability in emissions over similar time periods, and to establish 
state budgets with variability limits that ensure that the significant 
contribution and interference with maintenance that EPA has identified 
in this notice be eliminated.
    While the year-to-year variability in emissions could lead to 
variability in 3-year rolling averages, inherent variability is lower 
over a 3-year time period than over a 1-year period and thus a state's 
3-year variability limit will be lower than the state's 1-year 
variability limit. Establishing such 3-year limits thus provides an 
opportunity to ensure that the variability limits do not allow greater 
fluctuation in emissions than justified based on historic variability. 
EPA estimated the variability in a state's emissions over a 3-year time 
period based on the expected variability in emissions for a single 
year.
    As summarized later and described in the Power Sector Variability 
TSD, the Agency used statistical methods to estimate the 3-year 
variability based on 1-year variability. The average variability of a 
multi-year sample is the average variability of a single year divided 
by the square root of the number of years in the multi-year sample.\76\ 
Thus, the variability of a 3-year average is equal to the annual 
variability divided by the square root of three. EPA used this approach 
to determine 3-year variability limits based on the 1-year limits. For 
example, the Agency calculated the 3-year variability that corresponds 
to a 1-year variability of 5,000 tons as 5,000 divided by the

[[Page 45294]]

square root of three, or 2,887 tons. Similarly, EPA calculated the 3-
year variability that corresponds to a 1-year variability of 1,700 tons 
as 1,700 divided by the square root of three, or 981 tons. EPA decided 
to use three years instead of some other interval in order to be 
consistent with 3-year averaging used to assess attainment with the 
NAAQS, as explained earlier in this section.
---------------------------------------------------------------------------

    \76\ Moore, David S. and George P. McCabe. Introduction to the 
Practice of Statistics. 2nd ed. New York: W.H. Freeman and Company, 
1993. p. 395.
---------------------------------------------------------------------------

    Proposed 3-year variability limits for each covered state are shown 
in the tables in section IV.F.2, later. See the Power Sector 
Variability TSD for more details on EPA's variability approach.
2. State Budgets With Variability Limits
    As explained previously, EPA determined variability limits for each 
state. EPA then applied these variability limits on a state-by-state 
basis to calculate state-specific emissions budgets with variability 
limits. EPA calculated state budgets with both 1-year and 3-year 
variability limits.
    Table IV.F-1 shows proposed variability limits by state on 
SO2 emissions for 2014 and later. Table IV.F-2 shows 
proposed variability limits by state on NOX annual emissions 
for 2014 and later. EPA requests comment on the proposed variability 
limits.
    EPA also requests comment on an alternative calculation method for 
variability. The alternative method would use the results of the 
proposed method but add a ceiling based on the maximum percentage of 
variability among covered states as observed in the historic heat input 
data described previously. For both NOX annual and 
SO2, the percentage limits calculated using this alternative 
methodology are 21 and 28 percent of a state's budget, respectively. 
Under this alternative calculation method, a state's variability limit 
would be no lower than 10 percent of its budget and no higher than 21 
or 28 percent, for NOX and SO2, respectively. 
Because no state varied more than these percentages, EPA believes they 
could serve as reasonable caps on variability limits. These limits 
would address the issue of small states receiving very large 
variability limits as a fraction of their budgets.
    For instance, although Connecticut's proposed 1-year variability 
limit of 1,700 tons is greater than 10 percent of its SO2 
budget of 3,059 tons (306 tons), it is also greater than 28 percent of 
the budget (857 tons). Therefore, under this alternative calculation 
method, Connecticut's 1-year SO2 variability limit would be 
857 tons (28 percent of the state's SO2 budget). Similarly, 
for annual NOX, while Connecticut's proposed 1-year 
variability limit of 5,000 tons is greater than 10 percent of its 
NOX annual budget of 2,775 (278 tons), it is greater than 21 
percent of the budget (583 tons). Therefore, under this alternative 
approach, Connecticut's 1-year annual NOX variability limit 
would be 583 tons. Tables IV.F-1 through IV.F-3 show the variability 
limits under the proposed and alternative calculation methods. See the 
Power Sector Variability TSD in the docket for this rule for more 
details.

    Table IV.F-1--Variability Limits on SO2 Annual Emissions for 2014 and Later for Electric Generating Units
                                                     [Tons]
----------------------------------------------------------------------------------------------------------------
                                                                      Proposed                 Alternative
                                                  SO2 annual ---------------------------------------------------
                     State                        emissions                   3-year                    3-year
                                                    budget       1-year      average       1-year      average
                                                                 limit        limit        limit        limit
----------------------------------------------------------------------------------------------------------------
Alabama........................................      161,871       16,187        9,346       16,187        9,346
Connecticut....................................        3,059        1,700          981          857          495
Delaware.......................................        7,784        1,700          981        1,700          981
District of Columbia...........................          337        1,700          981           94           54
Florida........................................      161,739       16,174        9,338       16,174        9,338
Georgia........................................       85,717        8,572        4,949        8,572        4,949
Illinois.......................................      151,530       15,153        8,749       15,153        8,749
Indiana........................................      201,412       20,141       11,629       20,141       11,629
Iowa...........................................       86,088        8,609        4,970        8,609        4,970
Kansas.........................................       57,275        5,728        3,307        5,728        3,307
Kentucky.......................................      113,844       11,384        6,573       11,384        6,573
Louisiana......................................       90,477        9,048        5,224        9,048        5,224
Maryland.......................................       39,665        3,967        2,290        3,967        2,290
Massachusetts..................................        7,902        1,700          981        1,700          981
Michigan.......................................      155,675       15,568        8,988       15,568        8,988
Minnesota......................................       47,101        4,710        2,719        4,710        2,719
Missouri.......................................      158,764       15,876        9,166       15,876        9,166
Nebraska.......................................       71,598        7,160        4,134        7,160        4,134
New Jersey.....................................       11,291        1,700          981        1,700          981
New York.......................................       42,041        4,204        2,427        4,204        2,427
North Carolina.................................       81,859        8,186        4,726        8,186        4,726
Ohio...........................................      178,307       17,831       10,295       17,831       10,295
Pennsylvania...................................      141,693       14,169        8,181       14,169        8,181
South Carolina.................................      116,483       11,648        6,725       11,648        6,725
Tennessee......................................      100,007       10,001        5,774       10,001        5,774
Virginia.......................................       40,785        4,079        2,355        4,079        2,355
West Virginia..................................      119,016       11,902        6,871       11,902        6,871
Wisconsin......................................       66,683        6,668        3,850        6,668        3,850
                                                --------------
    Total......................................    2,500,003
----------------------------------------------------------------------------------------------------------------
Proposed 1-year variability limits are the larger of (1) 1,700 tons or (2) 10 percent of the state's budget. 3-
  year limits are the 1-year limits divided by the square root of three.
The alternative 1-year variability limit is 1,700 tons as long as that amount is between 10 and 28 percent of
  the state's budget. If 1,700 tons is greater than 28 percent of the state's budget, the state's limit is set
  at 28 percent of its budget. If 1,700 tons is less than 10 percent of the state's budget, the state's limit is
  set at 10 percent of its budget.


[[Page 45295]]


    Table IV.F-2--Variability Limits on NOX Annual Emissions for 2014 and Later for Electric Generating Units
                                                     [Tons]
----------------------------------------------------------------------------------------------------------------
                                                                      Proposed                 Alternative
                                                             ---------------------------------------------------
                     State                        NOX annual                  3-year                    3-year
                                                                 1-year      average       1-year      average
                                                                 limit        limit        limit        limit
----------------------------------------------------------------------------------------------------------------
Alabama........................................       69,169        6,917        3,993        6,917        3,993
Connecticut....................................        2,775        5,000        2,887          583          336
Delaware.......................................        6,206        5,000        2,887        1,303          752
District of Columbia...........................          170        5,000        2,887           36           21
Florida........................................      120,001       12,000        6,928       12,000        6,928
Georgia........................................       73,801        7,380        4,261        7,380        4,261
Illinois.......................................       56,040        5,604        3,235        5,604        3,235
Indiana........................................      115,687       11,569        6,679       11,569        6,679
Iowa...........................................       46,068        5,000        2,887        5,000        2,887
Kansas.........................................       51,321        5,132        2,963        5,132        2,963
Kentucky.......................................       74,117        7,412        4,279        7,412        4,279
Louisiana......................................       43,946        5,000        2,887        5,000        2,887
Maryland.......................................       17,044        5,000        2,887        3,579        2,066
Massachusetts..................................        5,960        5,000        2,887        1,252          723
Michigan.......................................       64,932        6,493        3,749        6,493        3,749
Minnesota......................................       41,322        5,000        2,887        5,000        2,887
Missouri.......................................       57,681        5,768        3,330        5,768        3,330
Nebraska.......................................       43,228        5,000        2,887        5,000        2,887
New Jersey.....................................       11,826        5,000        2,887        2,483        1,434
New York.......................................       23,341        5,000        2,887        4,902        2,830
North Carolina.................................       51,800        5,180        2,991        5,180        2,991
Ohio...........................................       97,313        9,731        5,618        9,731        5,618
Pennsylvania...................................      113,903       11,390        6,576       11,390        6,576
South Carolina.................................       33,882        5,000        2,887        5,000        2,887
Tennessee......................................       28,362        5,000        2,887        5,000        2,887
Virginia.......................................       29,581        5,000        2,887        5,000        2,887
West Virginia..................................       51,990        5,199        3,002        5,199        3,002
Wisconsin......................................       44,846        5,000        2,887        5,000        2,887
                                                -------------
    Total......................................    1,376,312
----------------------------------------------------------------------------------------------------------------
Proposed 1-year variability limits are the larger of (1) 5,000 tons or (2) 10 percent of the state's budget. 3-
  year limits are the 1-year limits divided by the square root of three.
The alternative 1-year variability limit is 5,000 tons as long as that amount is between 10 and 21 percent of
  the state's budget. If 5,000 tons is greater than 21 percent of the state's budget, the state's limit is set
  at 21 percent of its budget. If 5,000 tons is less than 10 percent of the state's budget, the state's limit is
  set at 10 percent of its budget.

    The NOX ozone season variability limits have been 
calculated based on five months of data corresponding to the May 
through September ozone season. EPA is proposing to use the same 
approach to calculate ozone season limits that the Agency used to 
calculate the proposed SO2 and NOX annual 
variability limits described earlier in this section, but adjusted to 
reflect the ozone season data.
    Using that approach, the resulting ozone season 1-year variability 
limits are 2,100 tons and 10 percent of a state's budget. EPA assigned 
each state one of these values-either the tonnage limit or the 
percentage limit, whichever was greater for that state--using the same 
approach as for the SO2 and NOX annual limits 
described previously. EPA determined the 3-year variability limits as 
the 1-year limits divided by the square root of three, the same 
approach used for the SO2 and NOX annual limits. 
The NOX ozone season limits resulting from this approach are 
shown in Table IV.F-3.
    EPA did not explicitly model ozone season variability limits 
because it was assumed that the NOX annual limits would also 
serve to limit variability in the ozone season and that additional 
constraints were unnecessary. However, a comparison of the data 
revealed that these variability limits would be lower than the ozone 
season emissions shown in EPA's modeling for this proposed rule in 
seven states, with the difference ranging from less than 100 tons to 
about 900 tons. Adding these ozone season variability limits would, 
presumably, change the NOX emissions projections in the IPM 
modeling, but the differences are expected not to make a noticeable 
impact in the overall air quality results.
    As with the SO2 and NOX annual variability 
limits, EPA also calculated NOX ozone season limits using 
the alternative calculation method described previously; the 
alternative method adds a ceiling based on the maximum percentage of 
variability among covered states as observed in the historic heat input 
data. For NOX ozone season, the percentage limit ceiling 
would be 27 percent of a state's budget. The NOX ozone 
season limits resulting from this approach are also shown in Table 
IV.F-3.
    EPA requests comments on the NOX ozone season limits 
shown in Table IV.F-3.

[[Page 45296]]



    Table IV.F-3--Variability Limits on NOX Ozone Emissions for 2014 and Later for Electric Generating Units
                                                     [Tons]
----------------------------------------------------------------------------------------------------------------
                                                                      Proposed                 Alternative
                                                  NOX ozone  ---------------------------------------------------
                     State                          season                    3-year                    3-year
                                                  emissions      1-year      average       1-year      average
                                                    budget       limit        limit        limit        limit
----------------------------------------------------------------------------------------------------------------
Alabama........................................       29,738        2,974        1,717        2,974        1,717
Arkansas.......................................       16,660        2,100        1,212        2,100        1,212
Connecticut....................................        1,315        2,100        1,212          355          205
Delaware.......................................        2,450        2,100        1,212          662          382
District of Columbia...........................          105        2,100        1,212           28           16
Florida........................................       56,939        5,694        3,287        5,694        3,287
Georgia........................................       32,144        3,214        1,856        3,214        1,856
Illinois.......................................       23,570        2,357        1,361        2,357        1,361
Indiana........................................       49,987        4,999        2,886        4,999        2,886
Kansas.........................................       21,433        2,143        1,237        2,143        1,237
Kentucky.......................................       30,908        3,091        1,784        3,091        1,784
Louisiana......................................       21,220        2,122        1,225        2,122        1,225
Maryland.......................................        7,232        2,100        1,212        1,953        1,127
Michigan.......................................       28,253        2,825        1,631        2,825        1,631
Mississippi....................................       16,530        2,100        1,212        2,100        1,212
New Jersey.....................................        5,269        2,100        1,212        1,423          821
New York.......................................       11,090        2,100        1,212        2,100        1,212
North Carolina.................................       23,539        2,354        1,359        2,354        1,359
Ohio...........................................       40,661        4,066        2,348        4,066        2,348
Oklahoma.......................................       37,087        3,709        2,141        3,709        2,141
Pennsylvania...................................       48,271        4,827        2,787        4,827        2,787
South Carolina.................................       15,222        2,100        1,212        2,100        1,212
Tennessee......................................       11,575        2,100        1,212        2,100        1,212
Texas..........................................       75,574        7,557        4,363        7,557        4,363
Virginia.......................................       12,608        2,100        1,212        2,100        1,212
West Virginia..................................       22,234        2,223        1,284        2,223        1,284
                                                --------------
    Total......................................      641,614
----------------------------------------------------------------------------------------------------------------
Proposed 1-year variability limits are the larger of (1) 2,100 tons or (2) 10 percent of the state's budget. 3-
  year limits are the 1-year limits divided by the square root of three.
The alternative 1-year variability limit is 2,100 tons as long as that amount is between 10 and 27 percent of
  the state's budget. If 2,100 tons is greater than 27 percent of the state's budget, the state's limit is set
  at 27 percent of its budget. If 2,100 tons is less than 10 percent of the state's budget, the state's limit is
  set at 10 percent of its budget.

    As discussed in section V.D, the proposed FIPs would apply the 1-
year variability limits commencing in 2014 and the 3-year variability 
limits commencing in 2016, noting that application of the 3-year 
average limits in 2016 would serve to limit each state's emissions in 
2014 and 2015. The Agency also requests comment on whether the remedy 
in the proposed FIPs should be modified so that the limits would apply 
starting in 2012 instead of 2014. In addition, the direct control 
remedy option on which EPA requests comments includes assurance 
provisions based on these variability limits that would apply starting 
in 2012. Thus, EPA also explains later what variability limits would 
apply in 2012 and 2013. The 1-year variability limits for 2012 and 2013 
would be the same as the variability limits for 2014 and later in 
Tables IV.F-1, IV.F-2, and IV.F-3 for all state budgets except for the 
SO2 budgets for the 15 states comprising the stringent 
SO2 tier (``group 1''), which have different SO2 
budgets in 2012 and 2013 than in 2014 and beyond.
    If EPA finalizes a remedy that uses the 2012 and 2013 variability 
limits, EPA would also start applying the 3-year variability limits in 
2014 (for all state budgets except group 1 SO2 budgets) 
which would serve to limit each state's emissions in 2012 and 2013, in 
the same way that starting the 3-year limits in 2016 would serve to 
limit emissions in 2014 and 2015 under the proposed approach. The 3-
year variability limits would be the same as the 3-year limits for 2014 
and later in Tables IV.F-1, IV.F-2, and IV.F-3.
    In this alternative approach, the 15 SO2 group 1 states, 
which have different SO2 budgets in 2012 and 2013 than in 
2014 and beyond, would be subject to different 1-year variability 
limits in 2012 and 2013 than in later years. All of the group 1 states 
have sufficiently large SO2 budgets in 2012 and 2013 that 
the tonnage limit of 1,700 tons would not apply and the 1-year limits 
would be 10 percent of the state SO2 budgets. The 2012 and 
2013 1-year limits on SO2 emissions for these 15 states 
under this alternative approach are shown later in Table IV.F-4.
    Additionally, commencing in 2013, EPA would apply in these 15 
states a distinct 2-year average variability limit on SO2 
emissions for the years 2012 and 2013. Analogous to the 3-year average 
in subsequent years, this 2-year average limit would restrict average 
variability in 2012 and 2013 more than the 1-year average alone. Table 
IV.F-4 shows, for this alternative approach, 2-year variability limits 
on SO2 emissions for 2012 and 2013 for the 15 group 1 
states. For these states, the 3-year variability limits for later years 
would be as shown in Tables IV.F-1, IV.F-2, and IV.F-3.
    For an alternative approach where variability limits start in 2012 
instead of 2014, EPA considered--instead of two-year average limits on 
SO2 emissions in the 15 group 1 states in 2012 and 2013--
applying 3-year average limits in these states starting in 2014. This 
would be the same method as for all other state budgets under the 
alternative where variability limits start in 2012. However, because 
the 15 group 1 states have different SO2 budgets in 2012 and 
2013 than in 2014 and beyond, calculation of the 3-year average limits 
to apply in

[[Page 45297]]

years spanning the two budget levels is less straightforward. EPA 
analyzed this alternative method for the 15 SO2 group 1 
states and compared results to the results using the 2-year average 
limits in 2012 and 2013 for these states, and determined that the 2-
year average approach is reasonable. See the Power Sector Variability 
TSD for more information.
    Table IV.F-4 includes 1-year and 2-year variability limits 
calculated according to the proposed methodology. The 2-year limits are 
the 1-year limits divided by the square root of two. The table does not 
include separate columns with variability limits calculated according 
to the alternative calculation method (i.e., the method that adds a 
ceiling based on the maximum percentage of variability in historic 
data, described previously) because for the SO2 budgets in 
Table IV.F-4 the alternative calculation method would yield identical 
results to the proposed method. The Power Sector Variability TSD 
contains more details on the variability limits.

   Table IV.F-4--2012-2013 One- and Two-Year Variability Limits on SO2
       Emissions for Group 1 States for Electric Generating Units
                                 [Tons]
------------------------------------------------------------------------
                                    SO2 annual                 Two-year
              State                 emissions      1-year      average
                                      budget       limit        limit
------------------------------------------------------------------------
Georgia..........................      233,260       23,326       16,494
Illinois.........................      208,957       20,896       14,775
Indiana..........................      400,378       40,038       28,311
Iowa.............................       94,052        9,405        6,650
Kentucky.........................      219,549       21,955       15,524
Michigan.........................      251,337       25,134       17,772
Missouri.........................      203,689       20,369       14,403
New York.........................       66,542        6,654        4,705
North Carolina...................      111,485       11,149        7,883
Ohio.............................      464,964       46,496       32,878
Pennsylvania.....................      388,612       38,861       27,479
Tennessee........................      100,007       10,001        7,072
Virginia.........................       72,595        7,260        5,133
West Virginia....................      205,422       20,542       14,526
Wisconsin........................       96,439        9,644        6,819
------------------------------------------------------------------------
1-year variability limits calculated by the proposed method are the
  larger of (1) 1,700 tons or (2) 10 percent of the state's budget. Two-
  year limits are the 1-year limits divided by the square root of two.
The alternative 1-year variability limit is 1,700 tons as long as that
  amount is between 10 and 28 percent of the state's budget. If 1,700
  tons is greater than 28 percent of the state's budget, the state's
  limit is set at 28 percent of its budget. If 1,700 tons is less than
  10 percent of the state's budget, the state's limit is set at 10
  percent of its budget. The alternative calculation method would yield
  identical limits to the limits determined using the proposed method
  for the budgets in Table IV.F-4, because for each of these budgets,
  1,700 tons is less than 10 percent of the budget.

3. Summary of Emissions Reductions Across All Covered States
    Table IV.F-5 presents projected power sector emissions in the base 
case (i.e., without the proposed Transport Rule or CAIR) compared to 
projected emissions with the proposed Transport Rule in 2012 and 2014 
for all covered states. Table IV.F-6 presents 2005 historical power 
sector emissions compared to projected emissions with the Transport 
Rule in 2012 and 2014.

  Table IV.F-5--Projected SO2 and NOX Electric Generating Unit Emissions 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      emissions       case         rule      emissions
                                     emissions    emissions    reductions   emissions    emissions    reductions
----------------------------------------------------------------------------------------------------------------
SO2...............................          8.4          3.4          5.0          7.2          2.6          4.6
Annual NOX........................          2.0          1.3          0.7          2.0          1.3          0.7
Ozone Season NOX..................          0.7          0.6          0.1          0.7          0.6         0.1
----------------------------------------------------------------------------------------------------------------
Note: Emissions differ from emissions budgets due to banking.


  Table IV.F-6--Projected SO2 and NOX Electric Generating Unit Emissions Reductions in Covered States With the
                                Transport Rule Compared to 2005 Actual Emissions
                                                 [Million tons]
----------------------------------------------------------------------------------------------------------------
                                                                  2012         2012         2014         2014
                                                 2005 actual   transport    emissions    transport    emissions
                                                  emissions       rule      reductions      rule      reductions
                                                               emissions    from 2005    emissions    from 2005
----------------------------------------------------------------------------------------------------------------
SO2............................................          8.9          3.4          5.5          2.6          6.3

[[Page 45298]]


Annual NOX.....................................          2.7          1.3          1.4          1.3          1.4
Ozone Season NOX...............................          0.9          0.6          0.3          0.6         0.3
----------------------------------------------------------------------------------------------------------------
Note: Emissions differ from emissions budgets due to banking.

G. How the Proposed Approach Is Consistent With Judicial Opinions 
Interpreting Section 110(a)(2)(D)(i)(I) of the Clean Air Act

    The methodology described previously quantifies states' significant 
contribution and interference with maintenance in a manner that is 
consistent with the decisions of the DC Circuit. As discussed in 
section III 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 v. EPA, 
213 F.3d 663 (DC Cir. 2000), and the second found significant flaws in 
the CAIR, North Carolina v. EPA, 531 F.3d. 896 (DC Cir. 2008). 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 proposed Transport 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 proposed 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 emissions 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 proposed transport rule, EPA uses a first step similar to 
that used in the CAIR to identify the states with relatively large 
contributions. However, in contrast to the CAIR, it then uses a state-
specific analysis. Instead of identifying a single emissions 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 that 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, emissions 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 
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

[[Page 45299]]

``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 IV.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 proposed FIPs are 
either part of or constitute the state's significant contribution and 
interference with maintenance. Thus, elimination of these emissions 
will, at a minimum, make measurable progress towards satisfying the 
110(a)(2)(D)(i)(I) prohibition on significant contribution and 
interference with maintenance.

H. Alternative Approaches Evaluated But Not Proposed

    EPA evaluated a number of alternative approaches to defining 
significant contribution and interference with maintenance in addition 
to the approach proposed in this rule. Stakeholders suggested a variety 
of ideas. EPA considered all suggested approaches.
    EPA evaluated approaches including those based solely on air 
quality, based solely on cost with a uniform cost in all states, based 
on cost per air quality impact (e.g., $ per [mu]g/m\3\), and binning of 
states based on air quality impact. Detailed descriptions of the 
alternative approaches that EPA evaluated are in a TSD in the docket 
titled ``Alternative Significant Contribution Approaches Evaluated.''
    EPA is not proposing any of the alternative approaches listed here. 
However, the proposed approach (described in section IV.D) incorporates 
some elements from these approaches.

V. Proposed Emissions Control Requirements

    This section describes the proposed emissions control requirements 
in detail. The section starts with V.A which discusses the pollutants 
included in the proposal, followed by V.B which discusses the source 
categories covered. Section V.C discusses the timing of the proposed 
emissions control requirements. Section V.D describes the proposed 
approach to implement the emission reduction requirements, starting 
with a description of the NOX SIP Call and CAIR approaches 
to implementing reductions and the judicial opinions on those 
approaches, then describing in detail the proposed ``remedy'' (State 
Budgets/Limited Trading) for FIPs that would implement the emissions 
reductions, and explaining the structure and key elements of the 
proposed Transport Rule trading program rules for State Budgets/Limited 
Trading. Section V.D also describes two alternative remedies on which 
EPA requests comment. Section V.E presents projected costs and 
emissions for each remedy option. Section V.F discusses the transition 
from the CAIR cap and trade programs to the proposed Transport Rule 
programs. Section V.G discusses interactions of the proposed programs 
with the existing Title IV and NOX SIP Call programs.

A. Pollutants Included in This Proposal

    In this action, EPA is proposing FIPs to directly regulate upwind 
emissions of SO2 and NOX because of their impact 
on downwind states' ability to attain and maintain the PM2.5 
NAAQS. EPA is also proposing to regulate upwind emissions of 
NOX because of their impact on 8-hour ozone attainment and 
maintenance in downwind states. Our rationale for regulating these 
precursor pollutants is discussed in section IV.B. In this section, we 
also explain the regulatory mechanism we are proposing to use to 
regulate these pollutants and take comment on two alternative options.

B. Source Categories

    EPA is proposing to require emissions reductions from the power 
sector. This section discusses EPA's rationale for proposing to control 
power sector emissions, and our rationale for not proposing to control 
emissions from other source categories at this time.
1. Propose To Control Power Sector Emissions
    The proposed Transport Rule FIPs would require EGUs with capacity 
greater than 25 MWe in the covered states to reduce emissions of 
SO2, NOX, and ozone season NOX. See 
section V.D.4., later, for a detailed description of the proposed 
applicability requirements.\77\
---------------------------------------------------------------------------

    \77\ Certain non-EGUs and smaller EGUs were included in the CAIR 
NOX ozone season program in some CAIR states. EPA 
proposes that such units would not be covered by the Transport Rule 
requirements; see section V.F in this preamble for further 
discussion of these units.
---------------------------------------------------------------------------

    Electric generating units are important sources of SO2 
and NOX emissions. In 2012, considering other controls that 
will be in place, EPA projects that if a Transport Rule is not 
implemented, EGUs would emit more than 70 percent of the total man-made 
SO2 emissions and about 20 percent of the total man-made 
NOX emissions in the group of 32 states that would be 
affected by this rule (see Table III.A-1 in section III for lists of 
states).\78\
---------------------------------------------------------------------------

    \78\ Emissions estimates are based on the 2012 baseline 
projections described in section IV in this preamble.
---------------------------------------------------------------------------

    EPA has previously conducted extensive analyses of the cost and 
emissions impacts of SO2 and NOX reduction 
policies on the power sector using the Integrated Planning Model (IPM). 
Examples include EPA's IPM analyses of a number of multi-pollutant 
bills, including the Clean Air Planning Act (S. 843 in 108th Congress), 
the Clean Power Act (S. 150 in 109th Congress), the Clear Skies Act of 
2005 (S. 131 in 109th Congress), the Clear Skies Act of 2003 (S. 485 in 
108th Congress), and the Clear Skies Manager's Mark (of S. 131). EPA 
also analyzed several power sector multi-pollutant scenarios in July 
2009 at the request of Senator Tom Carper. These analyses are on EPA's 
Web site at: (http://www.epagov/airmarkets/progsregs/cair/multi.html). 
EPA's IPM analysis for CAIR is another example: (http://www.epagov/
airmarkets/progsregs/epa-ipm/cair/index.html).
    Based on these analyses, EPA believes that there exist reasonable 
means for EGUs to make substantial reductions in emissions of 
SO2 and NOX. EPA also believes that, at this 
time, EGUs can

[[Page 45300]]

reduce SO2 and NOX emissions more cost-
effectively than other source categories (see section IV.D for 
discussion of control costs for non-EGU source categories). For these 
reasons, EPA has decided to require reductions in SO2 and 
NOX emissions from EGUs in the FIPs in this proposed rule. 
EPA requests comments on these proposed FIPs and its proposal to 
require reductions from EGUs.
2. Other Source Categories Are Not Included
    In these proposed FIPs, EPA is not proposing to include emission 
reduction requirements for sources other than EGUs.\79\
---------------------------------------------------------------------------

    \79\ See section IV.D.3 for discussion of non-EGUs that were 
included in the CAIR NOX ozone season trading program.
---------------------------------------------------------------------------

a. Why EPA Does Not Require Reductions From Other Source Categories To 
Address Transport Requirements for PM2.5
    In the proposed FIPs to address the section 110(a)(2)(D)(i)(I) 
requirements with respect to the 1997 and 2006 PM2.5 
standards, EPA proposes to regulate only emissions from EGUs. As 
discussed previously in section IV.D, EPA's review of the costs of EGU 
and non-EGU controls resulted in a conclusion that substantial 
SO2 and NOX reductions from EGUs are available at 
a cost per ton that is lower than the cost per ton of non-EGU controls. 
Other analyses discussed in section IV.D demonstrated that these EGU 
reductions are sufficient to eliminate the quantity of emissions 
identified by EPA as significantly contributing to or interfering with 
maintenance of the 1997 PM2.5 NAAQS in downwind areas. This 
same section explains that EGU reductions substantially address 
eliminating the quantity of emissions identified by EPA as 
significantly contributing to or interfering with maintenance of the 
2006 PM2.5 NAAQS, and this same section explains the need 
for EPA to further analyze remaining winter PM2.5 
exceedances. This conclusion does not, in any way, address whether a 
FIP promulgated by EPA or SIPs promulgated by the states should include 
reductions from non-EGU sources in order to eliminate significant 
contribution and interference with maintenance for any other NAAQS, 
including the 1997 ozone NAAQS and future NAAQS for PM2.5.
b. Why EPA Does Not Propose To Require Reductions From Other Source 
Categories To Address Transport Requirements for Ozone
    In the FIPs for this proposed rule, EPA is only proposing to 
require reductions from EGUs to address emissions from those source 
categories that significantly contribute to or interfere with 
maintenance of the 1997 ozone NAAQS. As discussed previously in section 
IV.D, EPA's review of the costs of EGU and non-EGU controls resulted in 
a conclusion that significant NOX emissions reductions from 
EGU are available at a cost per ton that is lower than the cost per ton 
of non-EGU NOX controls. The same section also explains the 
need for EPA to further analyze whether fully addressing upwind state 
responsibilities to reduce NOX emissions that contribute to 
downwind nonattainment and maintenance problems requires additional 
reductions at higher cost per ton, which again would involve analysis 
of potential EGU and non-EGU reductions and costs. EPA will be moving 
forward to complete its assessment of pollution transport for the 1997 
ozone NAAQS as soon as possible.
    For future ozone and PM2.5 NAAQS, EPA intends to 
quantify the emissions reductions needed to satisfy the requirements of 
110(a)(2)(D)(i)(I) with respect to those NAAQS. EPA has not made any 
determinations or assessments regarding whether reductions from source 
categories other than EGUs will be needed to achieve the necessary 
reductions in each state.

C. Timing of Proposed Emissions Reduction Requirements

    EPA is proposing an initial phase of reductions in 2012 followed by 
a second phase in 2014. Sources will be required to comply with the 
annual SO2 and NOX requirements by January 1, 
2012 and January 1, 2014 for the first and second phases, respectively. 
Similarly, sources will be required to comply with the ozone season 
NOX requirements by May 1, 2012, and by May 1, 2014. EPA 
chose these dates to coordinate with the NAAQS attainment deadlines and 
to assure that reductions are made as expeditiously as practicable, as 
described later in this section. This section also discusses how the 
compliance deadlines address the Court's concern about timing. 
Additionally, this section explains that EPA will consider additional 
reductions to address the NAAQS in the future.
1. Date for Prohibiting Emissions That Significantly Contribute or 
Interfere With Maintenance of the PM2.5 NAAQS
    For all areas designated as nonattainment with respect to the 1997 
PM2.5 NAAQS, the SIP deadline for attaining that standard 
must be as expeditious as practicable but no later than April 2010, 
with a possible extension to no later than April 2015. Many areas have 
already come into attainment by the April 2010 deadline due in part to 
reductions achieved under CAIR. Because the 2010 deadline will have 
passed before the Transport Rule is finalized, we decided to coordinate 
the deadline for eliminating significant contribution under this rule 
with respect to the 1997 PM2.5 NAAQS with the April 2015 
deadline that applies to areas that will need an extension of the April 
2010 deadline. 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 
with a possible extension to as late as December 2019.\80\
---------------------------------------------------------------------------

    \80\ Section 172(a)(2) of the Clean Air Act provides that ``the 
attainment date for an area designated nonattainment with respect to 
a national primary ambient air quality standard shall be the date by 
which attainment can be achieved as expeditiously as practicable, 
but no later than 5 years from the date such area was designated 
nonattainment under section 7407(d) of this title, except that the 
Administrator may extend the attainment date to the extent the 
Administrator 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 2006 24-hour 
PM2.5 NAAQS became effective on December 14, 2009.
---------------------------------------------------------------------------

    Upwind emissions reductions achieved by the 2014 emissions year 
will help areas that failed to meet the April 2010 deadline, to meet 
the April 2015 deadline for the 1997 PM2.5 NAAQS. These 
reductions will also help areas meet the December 2014 attainment 
deadline with respect to the 2006 PM2.5 NAAQS. Any areas not 
meeting that deadline can request a 5-year extension to December 2019.
    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 needed for compliance (see further discussion in section 
IV.D).

[[Page 45301]]

2. Date for Prohibiting Emissions That Significantly Contribute or 
Interfere With Maintenance of the 1997 Ozone NAAQS
    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 part 51). 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 corresponding to the end of the 2006, 2009, and 2012 
ozone seasons. Many areas have already attained due in part to CAIR, 
federal mobile source standards, and other local, state, and federal 
measures. Those that have not yet attained the standard have maximum 
attainment dates ranging from 2010 (these are the 2009 areas that have 
been granted a 1-year extension due to clean data in 2009) to 2018. 
Areas designated ``serious'' nonattainment areas have a June 2013 
maximum attainment deadline. The proposed 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. The reductions will also improve air quality in areas 
with later deadlines.
3. Reductions Required by 2012 To Ensure That Significant Contribution 
and Interference With Maintenance Are Eliminated as Expeditiously as 
Practicable
    EPA is requiring an initial phase of reductions by 2012. These 
reductions are necessary to ensure that significant contribution and 
interference with maintenance are eliminated as expeditiously as 
practicable. This will in turn assist downwind states to achieve 
attainment as expeditiously as practicable as required by the CAA.
    Because the proposed rule, if finalized, will replace the CAIR, EPA 
cannot assume that after this rule is finalized, EGUs would continue to 
emit at the reduced emissions levels achieved by CAIR. Instead, it is 
the emissions reductions requirements in the proposed FIPs that will 
determine the level of EGU emissions in the eastern United States. For 
these reasons, EPA is proposing to require an initial phase of 
reductions by 2012 which would ensure that existing and planned 
SO2 and NOX controls operate as anticipated.
4. How Compliance Deadlines Address the Court's Concern About Timing
    As directed by the Court in North Carolina v. EPA, 531 F.3d 896 (DC 
Cir. 2008), and described previously, EPA has established the 
compliance deadlines in the proposed 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 coordinated with the June 2013 maximum 
attainment deadline for serious ozone nonattainment areas (taking into 
account the need for reductions by 2012 to demonstrate attainment by 
that date). This deadline is also consistent with the requirement that 
states attain the NAAQS as expeditiously as practicable.
    The 2014 deadline for compliance with the limits on annual 
NOX and annual SO2 emissions is coordinated with 
the April 2015 maximum attainment deadline for 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). This 2014 compliance 
deadline is also consistent with December 2014 attainment deadline (5 
years from designation, in the absence of an extension) for areas 
designated nonattainment for the 2006 PM2.5 NAAQS. Areas 
unable to meet this 2014 deadline may seek a maximum 5-year extension 
to 2019.
    In addition, the 2012 compliance deadline for the first-phase of 
annual NOX and annual SO2 emissions reductions 
will assure the reductions are achieved as expeditiously as 
practicable. EPA established the interim 2012 compliance deadline for 
annual NOX and annual SO2 reductions because a 
significant number of reductions can be achieved by 2012. However, 
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 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.
5. EPA Will Consider Additional Reductions in Pollution Transport To 
Assist in Meeting Any Revised or New NAAQS
a. Ozone
    As noted, in a January 19, 2010, notice of proposed rulemaking, EPA 
proposed to strengthen the NAAQS for ozone. In that notice, EPA 
proposed levels for the ozone standard to a level within the range of 
0.060 to 0.070 parts per million. EPA also proposed in this same notice 
to establish a distinct cumulative, seasonal ``secondary'' standard, 
designed to protect sensitive vegetation and ecosystems, including 
forests, parks, wildlife refuges and wilderness areas.\81\
---------------------------------------------------------------------------

    \81\ This proposed cumulative, seasonal standard is expressed as 
an annual index of the sum of weighted hourly concentrations, 
cumulated over 12 hours per day (8 a.m. to 8 p.m.) during the 
consecutive 3-month period within the O3 season with the 
maximum index value, set at a level within the range of 7 to 15 ppm-
hours.
---------------------------------------------------------------------------

    EPA expects to finalize the revised NAAQS for ozone in August 2010. 
After the NAAQS are finalized, EPA will be able to identify areas that 
are expected to have difficulty attaining and maintaining those 
standards and will evaluate and analyze the impact of upwind state 
emissions in those areas with regard to those standards. EPA has 
already begun the technical background work necessary to allow it to 
move quickly, once the revised ozone standards are promulgated, with a 
proposal to address upwind emissions that significantly contribute to 
nonattainment of or interfere with maintenance of those standards. 
Because that analysis will take some time, and because EPA recognizes 
the urgency of responding to the concerns raised by the Court in North 
Carolina v. EPA, EPA intends to address the requirements of 
110(a)(2)(D)(i)(I) with respect to the revised ozone standards in a 
subsequent proposal. Addressing the 110(a)(2)(D)(i)(I) requirements for 
the new NAAQS shortly after promulgation of those NAAQS would help 
clarify the requirements related to transported emissions before 
downwind state nonattainment SIPs are due. In doing so, the transport 
rule would aid downwind states in developing plans for attaining and 
maintaining the new NAAQS.
b. Fine Particles
    EPA is also on a schedule to review and, if necessary update the 
PM2.5 NAAQS. This review is scheduled for completion in 
October 2011. EPA plans

[[Page 45302]]

to conduct background technical analyses so that EPA will be prepared 
to move quickly, if necessary, with a transport rule related to any 
revised PM2.5 NAAQS.

D. Implementing Emissions Reductions Requirements

    In this rule, EPA is proposing FIPs to eliminate the significant 
contribution and interference with maintenance EPA has identified in 
this action. We are proposing one ``remedy'' option to implement the 
necessary emissions reductions and taking comment on two other options. 
Before presenting these options we briefly summarize the approaches 
used in the NOX SIP Call and CAIR.
1. Approaches Taken in NOX SIP Call and CAIR
    In the NOX SIP Call and CAIR, EPA developed emissions 
trading programs as possible remedies to 110(a)(2)(D)(i)(I) SIP 
deficiencies. States covered by the rules were given the option of 
joining the trading programs and EPA determined that, by doing so, they 
would satisfy the requirements of 110(a)(2)(D)(i)(I) with respect to 
specific NAAQS. The NOX SIP Call provided an ozone-season 
NOX trading program and addressed the requirements of the 
ozone NAAQS only. The CAIR provided SO2, annual 
NOX, and ozone-season NOX trading programs, and 
addressed both the 1997 ozone and the 1997 PM2.5 NAAQS.
    NOX SIP Call approach. The NOX SIP Call proposed a 
regional cap and trade program as a way to make cost-effective 
NOX reductions. Created after years of scientific research 
and air quality data analyses showed that upwind NOX 
emissions can contribute significantly to ozone nonattainment in 
downwind states, the NOX Budget Trading Program (NBP) 
followed several other major efforts to reduce NOX from 
large, stationary sources. These initiatives included the Acid Rain 
Program, OTC NOX Budget Program, New Source Review, New 
Source Performance Standards, application of Reasonably Available 
Control Technology to existing sources, and other state efforts.
    By notice dated October 27, 1998 (63 FR 57356), EPA took final 
action to require states to prohibit specified amounts of emissions of 
one of the main precursors of ground-level ozone, NOX, in 
order to reduce ozone transport across state boundaries in the eastern 
half of the United States. EPA found that sources in 23 states emit 
NOX in amounts that significantly contribute to 
nonattainment of the 1-hour ozone NAAQS in downwind states. EPA set 
forth requirements for each of the affected upwind states to submit SIP 
revisions prohibiting those amounts of NOX emissions that 
significantly contribute to downwind air quality problems. EPA 
established statewide NOX emissions budgets for the affected 
states. States had the flexibility to adopt the appropriate mix of 
controls for their state to meet the NOX emissions 
reductions requirements of the SIP call.
    In the final regulation, EPA offered to administer a multi-state 
NOX Budget Trading Program for states affected by the 
NOX SIP Call. The NOX Budget Trading Program was 
an ozone season (May 1 to September 30) cap and trade program for EGUs 
and large industrial combustion sources, primarily boilers and 
turbines. The program used a regionwide cap for ozone season 
NOX emissions. The cap was the sum of the state emissions 
budgets established by EPA under the NOX SIP Call regulation 
to help states meet their SIP obligations. Authorizations to emit, 
known as allowances, were allocated to affected sources based on state 
trading budgets. The NOX allowance market enabled sources to 
trade (buy and sell) allowances throughout the year. Sources could 
reduce NOX emissions in any manner. Options included adding 
emissions control technologies, replacing existing controls with more 
advanced technologies, optimizing existing controls, or switching 
fuels. At the end of every ozone season, each source surrendered 
sufficient allowances to cover its ozone season NOX 
emissions (each allowance represents one ton of NOX 
emissions). This process is called annual reconciliation. If a source 
did not have enough allowances to cover its emissions, EPA 
automatically deducted allowances from the following year's allocation 
at a 3:1 ratio. If a source had excess allowances because it reduced 
emissions beyond required levels, it could sell the unused allowances 
or bank (save) them for use in a future ozone season. To accurately 
monitor and report emissions, sources use continuous emission 
monitoring systems (CEMS) or other approved monitoring methods under 
EPA's stringent monitoring requirements (Title 40 of the Code of 
Federal Regulations [CFR], Part 75).
    The NOX SIP Call cap and trade program was a way to make 
cost-effective NOX reductions. Under the NOX SIP 
Call, states had the flexibility to determine the mix of controls to 
meet their emissions reductions requirements. However, the rule 
provides that if the SIP controls EGUs, then the SIP must establish a 
budget, or cap, for EGUs. The EPA recommended that each state authorize 
a trading program for NOX emissions from EGUs. Each of the 
states required to submit a NOX SIP under the NOX 
SIP Call chose to adopt the cap and trade program regulating large 
boilers and turbines. Each state based its cap and trade program on a 
model rule developed by EPA. Some states essentially adopted the full 
model rule as is, while other states adopted the model rule with 
changes to the sections that EPA specifically identified as areas in 
which states may have some flexibility. The NOX SIP Call cap 
and trade program, modeled closely after the OTC NOX Budget 
Program, was phased in starting in 2003 for the OTC states, with the 
majority of affected states participating as of 2004.
    CAIR Approach. In May 2005, EPA promulgated CAIR to address 
emissions in 28 states and the District of Columbia that it found 
contribute significantly to nonattainment of the 1997 PM2.5 
and 8-hour ozone NAAQS in downwind states. The EPA required these 
upwind states to revise their SIPs to include control measures to 
reduce emissions of SO2 and/or NOX. Reducing 
upwind precursor emissions helps the downwind PM2.5 and 8-
hour ozone nonattainment areas achieve the NAAQS. Moreover, reducing 
upwind emissions makes it possible for attainment to be achieved in a 
more equitable, cost-effective manner than if each nonattainment area 
attempted to achieve the NAAQS by implementing local emissions 
reductions alone.
    In CAIR, EPA offered states optional regionwide cap and trade 
programs, which were similar to the SO2 trading program in 
Title IV of the CAA and the NOX Budget Trading Program in 
the NOX SIP Call. CAIR required implementation of emissions 
reductions requirements for SO2 and NOX in two 
phases. The first phase of NOX reductions started in 2009 
(covering 2009-2014) and the first phase of SO2 reductions 
began in 2010 (covering 2010-2014); the second phase of reductions for 
both NOX and SO2 would start in 2015 (covering 
2015 and thereafter). The required emissions reductions requirements 
are based on controls that are known to be highly cost effective for 
EGUs. CAIR also included model rules for multi-state cap and trade 
programs for annual SO2 and NOX emissions for 
PM2.5, and seasonal NOX emissions for ozone, that 
states could choose to adopt to meet the required emissions reductions 
in a flexible and cost-effective manner. The CAIR provided for the 
NOX SIP Call cap and trade program to be replaced by the

[[Page 45303]]

CAIR ozone season NOX trading program.
    The U.S. Court of Appeals granted several petitions for review of 
the CAIR and remanded the rule to EPA. Because the Court decided to 
remand the rule without vacatur, however, CAIR remains in effect. This 
proposed rule would replace the CAIR upon final promulgation.
2. Judicial Opinions
    Challenges to both the NOX SIP Call and the CAIR were 
brought before the U.S. Court of Appeals for the DC Circuit. In 
Michigan v. EPA, 213 F.3d 663, the Court largely upheld the 
NOX SIP Call. The portion of this opinion most directly 
related to the remedy selected by EPA, discusses EPA's decision to 
utilize a uniform control strategy. The Court rejected two specific 
challenges to the requirement that ``all covered jurisdictions, 
regardless of amount of contribution, reduce their NOX by an 
amount achievable with ``highly cost-effective controls.'' Id. at 679. 
EPA's approach, Petitioners first alleged, was irrational because it 
did not take into account differences in individual states'' respective 
contributions to downwind nonattainment. Both small and large 
contributors were required to make reductions achievable by the 
application of highly cost effective controls. The court rejected this 
challenge finding that this result ``flows ineluctably from EPA's 
decision to draw the `significant contribution' line on the basis of 
cost differentials.'' Id.
    Petitioners' second objection to the use of uniform controls was 
that it failed to take into account the fact that the location of 
emissions reductions may affect the impact of those reductions on 
downwind nonattainment areas. Petitioners argued that because 
reductions closer to the nonattainment area have a greater benefit, 
EPA's use of a highly-cost-effective standard and region-wide emissions 
trading did not guarantee that it would have secured the rule's health 
benefits at the lowest cost. See id. The Court rejected this challenge 
also, giving deference to EPA's judgment that non-uniform regional 
approaches would not `` `provide either a significant improvement in 
air quality or a substantial reduction in cost.' '' Id. (quoting 63 FR 
57423).
    Petitioners challenging the CAIR also raised issues related to 
EPA's use of an interstate trading program to satisfy the requirements 
of section 110(a)(2)(D)(i)(I). Petitioners challenged both the trading 
program itself and the state budgets. These budgets were used to 
determine the number of emission allowances allocated to sources in 
each state or, if the state chose not to participate in the trading 
programs, the specific emission reduction requirements for that state.
    The Court concluded, in North Carolina v. EPA, 531 F.3d 896, that 
EPA had not demonstrated that the 110(a)(2)(D)(i)(I) remedy promulgated 
in CAIR would effectuate the statutory mandate of section 
110(a)(2)(D)(i)(I) and promote the goal of prohibiting contributing 
sources within one state from contributing to nonattainment in another 
state. In reaching this conclusion, the Court emphasized that EPA had 
not adequately measured each individual state's significant 
contribution. See id. at 908. (``It is unclear how EPA can assure that 
the trading programs it has designed in CAIR will achieve section 
110(a)(2)(D)(i)(I)'s goals if we do not know what each upwind state's 
``significant contribution'' is to another state.'')
    The Court also emphasized that section 110(a)(2)(D)(i)(I) 
``prohibits sources `within the State' from `contribut[ing] 
significantly to nonattainment in * * * any other State * * *' '' Id. 
at 907. (quoting section 110(a)(2)(D)(i)(I) and adding emphasis). While 
recognizing that it was ``possible that CAIR would achieve section 
110(a)(2)(D)(i)(I)'s goals'' it concluded that ``CAIR assures only that 
the entire region's significant contribution will be eliminated,'' 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.'' 
Id. at 907. Furthermore, since CAIR was designed as a ``complete remedy 
to section 110(a)(2)(D)(i)(I) problems'' the Court emphasized that ``it 
must actually require elimination of emissions from sources that 
contribute significantly and interfere with maintenance.'' Id. at 908. 
In doing so, however, the Court also acknowledged that it had accepted 
in Michigan v. EPA, 213 F.3d 663 (D.C. Cir. 2000) EPA's decision to 
apply uniform emissions controls and its consideration of cost in the 
definition of significant contribution. See North Carolina, 531 F.3d at 
908.
    In developing options to eliminate the emissions identified as 
constituting all or part of a state's significant contribution and 
interference with maintenance, EPA has been mindful of the direction 
provided by the Court. As discussed in greater detail later, EPA 
believes that each of the remedy options presented is consistent with 
the Court's opinions interpreting the requirements of section 
110(a)(2)(D)(i)(I).
3. Remedy Options Overview
    EPA is proposing one ``remedy'' option to implement the emissions 
reductions requirements and taking comment on two alternatives. This 
section provides a brief overview of the proposed remedy and the two 
alternatives. Sections V.D.4, V.D.5, and V.D.6, later, describe the 
proposed remedy and the alternatives in detail.
    EPA considered a full range of remedy options in developing this 
proposal. Among other things, EPA considered variations of direct 
control options, intrastate cap and trade, interstate cap and trade, 
hybrids of these approaches, and simple state emissions caps. 
Stakeholders have suggested a variety of remedy options for EPA's 
consideration. A TSD in the docket entitled ``Other Remedy Options 
Evaluated'' describes other options that EPA evaluated.
    Based on its consideration of a range of options, EPA is proposing 
one remedy option and requesting comment on two alternatives. The 
proposed remedy option, discussed later, is a hybrid approach that 
combines limited interstate trading with other requirements. The 
alternative remedies on which EPA requests comment include an 
intrastate trading option and a direct control option. The proposed and 
alternative remedy options would regulate SO2 and 
NOX emissions from EGUs through FIPs in the covered states 
to eliminate or address the states'' significant contribution to 
nonattainment in, or interference with maintenance by, downwind areas 
with respect to the daily and annual PM2.5 NAAQS and the 8-
hour ozone NAAQS.
    The remedy option EPA is proposing would use state-specific control 
budgets and allow for intrastate and limited interstate trading of 
emissions allowances allocated to EGUs. This approach would assure 
environmental results while providing some limited flexibility to 
covered sources consistent with the Court decision as described later. 
The approach would also help ease the transition for implementing 
agencies and covered sources from CAIR to the Transport Rule. Based on 
consideration of a range of options, EPA believes that the proposed 
option is the best approach, for the reasons discussed in section 
V.D.4.
    The Agency is also presenting other alternative remedies for 
comment. The first alternative for which EPA requests comment would use 
state-specific control budgets and allow intrastate trading of 
emissions allowances allocated to EGUs, but no interstate

[[Page 45304]]

trading. The second alternative for which EPA requests comment is a 
direct control program in combination with state-specific control 
budgets.
    EPA recognizes there could be cost savings from an approach that 
uses aless restrictiveinterstate trading option. EPA also recognizes 
that unrestricted trading programs including the NOX SIP 
Call Trading Program have been very successful in addressing regional 
pollution problems.
    In this action, EPA is not proposing such an unrestricted trading 
program, because EPA does not believe that such an option could provide 
assurance that each state achieves emissions reductions within the 
state, as required by the North Carolina decision. As the D.C. Circuit 
emphasized in its opinion, the statutory requirement in section 
110(a)(2)(D)(i)(I) aims to prohibit ``sources ``within the State'' from 
contributing to nonattainment or interfering with maintenance in ``any 
other State.'' North Carolina, 531 F.3d at 908. The location of 
emission reductions is relevant because it can influence where air 
quality improvements occur and whether a particular state meets its 
statutory obligations. See North Carolina, 531 F.3d at 907.
    In addition to considering unrestricted trading, EPA also 
considered whether there were other ways that a trading program could 
be structured to address the Court's concerns. In particular, EPA 
reviewed a methodology that had been investigated during the 
development of the NOX SIP Call regulation that used trading 
ratios (``Development and Evaluation of a Targeted Emission Reduction 
Scenario for NOX Point Sources in the Eastern United States: 
An Application of the Regional Economic Model for Air Quality 
(REMAQ)'', Prepared by Stratus Consulting inc. November 24, 1999) (at 
http://www.epagov/airtransport). This approach would allow interstate 
trading, but use trading ratios to take into account differences in the 
cumulative downwind impact of emissions from different states. Trading 
ratios would be developed for each pair of states using air quality 
modeling such that, given the meteorological assumptions underlying the 
air quality modeling, the ratios would represent the ratio of the 
benefit to downwind air quality within a region from controlling 
emissions in different upwind areas. For instance, in its simplest 
form, if emission reductions from State A were twice as effective at 
reducing cumulative downwind air quality impact on a set of downwind 
receptors as emission reductions from State B, the trading ratio 
between States A and B would be 2 to 1.\82\ In other words, if the 
States chose to trade, State A would have to purchase 2 allocations 
from State B to cover 1 ton of State A's emissions, since State A's 
emissions have twice the impact on downwind air quality. Such an 
approach offers the very valuable potential to address the transport 
problem in an effective (and potentially less costly) manner, as it 
incentivizes reductions from the places where they have the greatest 
value in reducing downwind air quality problems. While it offers such 
opportunities, there are challenges in developing such a system that is 
consistent with the requirement under section 110(a)(2)(D) that 
emission reductions occur in particular geographic locations. The 
trading ratio approach would be designed to assure a cumulative 
downwind air quality result, not to assure specific upwind reductions. 
Although it would reduce the incentive for sources from upwind states 
with larger cumulative impacts to comply by purchasing allowances 
(since they would need to purchase a greater number of allowances per 
ton emitted than sources in states with less of an impact), as 
currently contemplated it would not be possible under this approach 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 requests comment on whether a ratios trading program could 
be designed to provide such a legal assurance. We also seek comment on 
whether such an assurance would be needed if, for example, in practice 
modeling results predicted with confidence that sufficient state-by-
state reductions would be achieved under such an approach.
---------------------------------------------------------------------------

    \82\ Note that the report evaluating this alternative was a 
theoretical economic and air quality analysis of the concept. It did 
not explore how trading ratios would be incorporated into a workable 
trading program. It did however indicates that the ``approach also 
provides for the possibility that the emission weights developed by 
this analysis could be incorporated into an emission trading program 
in which emission weights act like exchange rates between different 
subregions and species. However this adds a significant increase in 
the complexity of the market and in practical terms is worth 
considering only when the potential cost savings are large enough to 
offset the additional complexity in market structure.'' P. 1-7, 
Stratus Consulting Inc. November 24, 1999.
---------------------------------------------------------------------------

    In the SIP Call, EPA did not ultimately propose this methodology 
for several reasons. First, the Stratus Consulting study (``Development 
and Evaluation of a Targeted Emission Reduction Scenario for 
NOX Point Sources in the Eastern United States: An 
Application of the Regional Economic Model for Air Quality (REMAQ)'') 
estimated that the most significant cost savings occurred from moving 
from a uniform direct control approach to a conventional cap-and-trade 
approach (the study suggested that this would lead to cost savings of 
approximately 25 percent). Adding trading ratios added significant 
complexity while only very slightly lowering costs (1 percent to 5 
percent compared to conventional cap and trade, where the cost savings 
decreased as the problem being addressed became more widespread (e.g. 
cost savings for the more stringent 1997 8 hour ozone NAAQS standard 
would be less than cost savings for the less stringent early 1 hour 
standard)) (Stratus, page s-2). However, because the transport rule is 
a larger program covering multiple pollutants with a different set of 
non-attainment areas and a broader geographic scope, there is the 
potential for greater cost savings. Second, the trading ratios are 
dependent upon the meteorological assumptions used to develop them; to 
the extent that future year meteorology or costs turn out to be 
different, the trading ratios could in fact lead to less than predicted 
downwind air quality benefits. Notably in reality, the ratios would 
have to consider that the upwind states that impact a downwind receptor 
vary from receptor to receptor; conversely each upwind state 
contributes to different sets of downwind receptors. It would be very 
challenging to develop trading ratios that account for this myriad of 
different relationships. EPA believes these concerns are also valid in 
the context of this Transport Rule.
    In addition, in considering this approach in the original SIP Call, 
it took close to a year to perform the underlying analysis to develop 
ratios for 1 pollutant (NOX) and one downwind air quality 
problem (ozone). In this context, there are 3 pollutants (annual 
NOX, annual SO2 and ozone season NOX) 
and two downwind air quality problems (ozone and PM2.5) to 
consider.
    EPA requests comment on the trading ratios approach, including 
whether: The trading ratio approach described above would be consistent 
with the Court opinion in North Carolina v. EPA and satisfy the section 
110(a)(2)(D) requirement that reductions occur ``within the state''; 
there are ways the approach could be modified to be consistent with the 
Court opinion and the statutory requirement; there are ways that such 
an approach could administratively be put in place by 2012 and be 
modified and adopted if further reductions are required to address

[[Page 45305]]

future NAAQS; and on whether there are ways that such a system could be 
designed to be transparent and relatively simple for sources to 
understand and comply with.
    Analysis from the SIP Call suggests that the trading ratios 
approach might have the potential to slightly reduce costs. However, 
the approach, as envisioned, appears to be in tension with EPA's 
mandate under section 110(a)(2)(D)(i)(I) to assure that significant 
contribution is fully addressed in each upwind state. While such an 
approach would ensure reductions on a region-wide basis, EPA has not 
been able to identify a way that the trading ratio approach could be 
modified to assure a specific set of downwind emissions reductions from 
all states. Under such an approach, there is the potential that some 
upwind states might make reductions that are larger than their 
significant contribution, while other states might make reductions that 
are less than their significant contribution. Because the state budgets 
have been designed to achieve all reductions available at a given cost, 
trading ratios other than one to one, although providing equivalent 
improvements in downwind air quality would lead to emissions reductions 
that were inconsistent with the initial budgets.\83\
---------------------------------------------------------------------------

    \83\ EPA, however, has proposed variability limits to these 
budgets, and it is possible a ratios approach may imply emissions 
would fall within the variability limits if the ratios ultimately 
turned out to be close to one-to-one.
---------------------------------------------------------------------------

    Because EPA recognizes the potential cost savings and potential 
improvements in program effectiveness associated with less restricted 
trading options, EPA is also requesting comment on the appropriateness 
of the assurance provisions that have been proposed, including whether 
they are adequate to assure that significant contribution and 
interference with maintenance are addressed in each state, whether they 
are overly restrictive, and whether there are less restrictive options 
that would provide adequate assurance that the statutory mandate is 
satisfied while providing more flexibility. Alternative approaches 
could potentially include: Using the basic methodology proposed with a 
higher or lower variability limitation or using an alternative to the 
approach to assure that state emissions budgets are met (e.g., trading 
ratios designed to assure that certain upwind emission reduction 
targets are met, rather than trading ratios designed to assure that 
downwind air quality goals are met). With regards to the variability 
limits that EPA has proposed, EPA takes comment on alternative 
approaches to calculating those limits, such as considering confidence 
intervals different than a 95 percent confidence interval such as a 99 
percent confidence interval (For more information see TSD, ``Power 
Sector Variability''.)
    EPA specifically requests that any commenter suggesting a less 
restrictive approach address how the commenter's preferred approach 
would satisfy the statutory mandate in section 110(a)(2)(D)(i)(I) of 
the Clean Air Act and be consistent with the decision of the DC Circuit 
in North Carolina v. EPA, 531 F.3d 8906 (2008) (e.g., if commenters 
suggest a higher variability limitation, what would be the rationale 
for allowing that amount of variability; if commenters suggest an 
alternative framework, how would that framework assure that reductions 
occur ``within the state'') as well as how EPA could develop the 
approach in a way that would be workable for sources, states, and EPA 
in time to achieve emission reductions in 2012 (e.g., would an approach 
with trading ratios impact transaction costs or be overly complex for 
less sophisticated trading entities, can the analysis needed to develop 
the approach be completed in a timely way).
    As discussed in section IV.E, EPA is proposing new state budgets 
developed on a different basis from the CAIR budgets. The intrastate 
and interstate trading remedy options would use new allowance 
allocations, also developed on a different basis from the CAIR FIP 
allowance allocations. See section IV for the proposed state budget 
approach and section V.D.4 for proposed allowance allocation 
approaches.
    As discussed in section IV.F, EPA believes that inherent 
variability in power system operations affects each state's baseline 
emissions and thus also affects a state's emissions after elimination 
of all significant contribution and interference with maintenance. 
Thus, emissions may vary somewhat after implementation of the remedies 
under consideration. This includes the proposed remedy option (State 
Budgets/Limited Trading), the intrastate trading alternative, and the 
direct control alternative. Sections V.D.4, V.D.5, and V.D.6 describe 
variability approaches for the proposed remedy and each of the 
alternative remedies.
    EPA also considered only establishing state emissions caps. Such an 
approach would define what must be done to eliminate all (or in some 
cases part) of each state's significant contribution and interference 
with maintenance, but it would not implement specific requirements to 
eliminate those emissions. As described in section III.C in this 
preamble, EPA decided to implement the emission reduction requirements 
through FIPs. To do so, EPA recognized that it needed to do more than 
establish simple state emissions caps. For this reason, EPA rejected 
the simple state emission cap option.
    As with any FIP that EPA issues, a covered state may submit, for 
review and approval, a state implementation plan (SIP) that replaces 
the Federal requirements with state requirements that would achieve the 
required reductions. A state's SIP submission to replace the Transport 
Rule FIP might propose to use any remedy of the state's choosing that 
actually eliminates the emissions that significantly contribute to 
nonattainment or interfere with maintenance downwind. Section VII in 
this preamble further discusses SIP submissions.
4. State Budgets/Limited Trading Proposed Remedy
    In this action, EPA is proposing FIPs that would establish state-
specific emission control requirements using state budgets starting in 
2012 in 32 states.\84\ This remedy option would allow unlimited 
intrastate trading and limited interstate trading to account for 
variability in the electricity sector, but also includes assurance 
provisions to ensure that the necessary emissions reductions occur 
within each covered state. The assurance provisions, described later in 
this section, would restrict EGU emissions within each state to the 
state's budget with the variability limit and would ensure that every 
state is making reductions to eliminate the portion of significant 
contribution and interference with maintenance that EPA has identified 
in today's action. EPA is proposing to impose these assurance 
provisions starting in 2014. State-specific emissions budgets with 
variability limits would be established as described in section IV in 
this preamble. These budgets without the variability limits would be 
used to determine the number of emissions allowances allocated to 
sources in each state: An EGU source would be required to hold one 
allowance for every ton of

[[Page 45306]]

SO2 and/or NOX emitted during the compliance 
period. Banking of allowances for use in future years would be allowed 
under the proposed remedy. For the 2012-2013 transition period, EPA is 
proposing the State Budgets/Limited Trading remedy without assurance 
provisions. EPA is taking comment on all aspects of, as well as 
alternatives to, this option that address the requirements of 
110(a)(2)(D)(i)(I) for prohibiting emissions that significantly 
contribute to or interfere with maintenance of the NAAQS in downwind 
states.
---------------------------------------------------------------------------

    \84\ The 32 states are: Alabama, Arkansas, Connecticut, District 
of Columbia, Delaware, Florida, Georgia, Illinois, Indiana, Iowa, 
Kansas, Kentucky, Louisiana, Maryland, Massachusetts, Michigan, 
Minnesota, Mississippi, Missouri, Nebraska, New Jersey, New York, 
North Carolina, Ohio, Oklahoma, Pennsylvania, South Carolina, 
Tennessee, Texas, Virginia, West Virginia, and Wisconsin. As noted 
in section III, for purposes of this rulemaking, when we discuss 
``states'' we are also including the District of Columbia.
---------------------------------------------------------------------------

a. Description of the Proposal
    The proposed FIPs would address the elimination of significant 
contribution and interference with maintenance by 2014. A first phase 
of reductions would be required by 2012 to assure that significant 
contribution and interference with maintenance are eliminated as 
expeditiously as practicable.
    To directly eliminate the portion of each state's significant 
contribution and interference with maintenance that EPA has identified 
in this action, the proposed remedy utilizes the state budgets with 
variability limits described in section IV. The budgets without 
variability limits are used to determine the number of allowances 
issued to sources in each state. Each affected source must hold, and 
surrender to EPA, allowances equal to its emissions during the 
compliance period. In addition, assurance provisions under the proposed 
remedy cap each state's EGU emissions at a state-specific budget with a 
variability limit to ensure that every state actually reduces, within 
the state, all emissions necessary to eliminate the portion of its 
significant contribution and interference with maintenance that EPA has 
identified in today's proposal.
    For the 2012-2013 transition period, EPA is taking comment on 
whether the assurance provisions used to limit interstate trading are 
needed, since the state-specific budgets are based on known air 
pollution controls and thus a high level of certainty exists about 
where reductions will occur. As described later, the proposed FIPs 
include penalty provisions that are adequate to ensure that the budget 
including a variability limit will not be exceeded so that each state 
eliminates the portion of its significant contribution and interference 
with maintenance that EPA has identified in today's proposed action.
    The proposed remedy establishes four interstate trading programs 
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 
the SO2 group 1) that need to make more aggressive 
reductions to eliminate the portion of their significant contribution 
that EPA has identified in today's proposed action, while the second is 
for sources in states (referred to as SO2 group 2) with less 
stringent reduction requirements. States within SO2 group 1 
can trade SO2 allowances only with other states in that 
group. Similarly, states within SO2 group 2 can trade 
SO2 allowances only with other states in that group. Note 
that all states covered for annual NOX may trade with each 
other, even if they are in different groups for SO2. Table 
IV.D.5 in section IV, previously, summarizes the respective covered 
states for the SO2 group 1, SO2 group 2, and 
annual NOX trading programs; Table IV.E-2 lists the states 
for the ozone season NOX program.
    New emissions allowances based on the new state budgets without 
variability would be allocated to individual sources, as described 
later. Four sets of allowances would be allocated, one for each of the 
four trading programs (SO2 group 1, SO2 group 2, 
NOX annual, and NOX ozone season). This 
allocation methodology neither uses heat input adjusted by fuel 
factors, nor relies on the allocation of allowances under Title IV of 
the Act.
    Sources would be allowed to trade allowances. However, the 
assurance provisions would limit total emissions from each state, 
restricting the variability of emissions from any particular state to 
the variability associated with its baseline emissions prior to the 
elimination of all or part of the state's significant contribution or 
interference with maintenance.
    Allowance banking is permitted. Banking (or saving) allowances for 
future use in any given year allows sources flexibility in compliance 
planning. Banking lowers costs and helps reduce market volatility. 
Banking also acts as an incentive to reduce emissions early and 
accumulate allowances that can be used for compliance in future 
periods. Because the early reductions encouraged by the ability to bank 
allowances would result in the reduction of emissions below allowable 
levels earlier than required, the environmental and human health 
benefits of the reductions would accrue sooner.
b. How the Proposal Would Be Implemented
(1) Applicability
    The requirements in the proposed FIPs would apply to large EGUs. 
Specifically, a covered source would be any stationary, fossil-fuel-
fired boiler or stationary, fossil-fuel-fired combustion turbine 
serving at any time, since the later of November 15, 1990 or the start-
up of the unit's combustion device, a generator with nameplate capacity 
of more than 25 MWe producing electricity for sale. The term ``fossil 
fuel'' is defined as including natural gas, petroleum, coal, or any 
form of fuel derived from such material. This is the same definition 
that was used in CAIR and would include all material derived from 
natural gas, petroleum, or coal, 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 used as fuel, these materials in 
the consumer products would qualify as fossil fuel.
    Certain cogeneration units or solid waste incinerators otherwise 
covered by this general category of covered units would be exempt from 
the FIP requirements. These proposed applicability requirements are 
essentially the same as those in the CAIR model trading rules and CAIR 
FIPs (reflecting the revised cogeneration unit definition promulgated 
in October 2007 (72 FR 59195; October 19, 2007)), with some technical 
corrections to the exemptions.
    Cogeneration unit exemption. In order to meet the proposed 
definition of ``cogeneration unit,'' 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 order to qualify as a cogeneration unit, a 
unit also must meet, on an annual basis, specified efficiency and 
operating standards, e.g., the 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, useful thermal energy must be no 
less than a certain percentage of total energy output, and useful power 
must be no less than a certain percentage of total energy input. Total 
energy input includes all energy input except from biomass.
    These proposed elements of the ``cogeneration unit'' definition are 
very similar to the definition used in CAIR. However, there are two 
technical differences. First, under the definition used in CAIR to 
qualify as a ``cogeneration unit,'' a unit had to meet

[[Page 45307]]

the efficiency and operating standards every year starting with the 
first 12-months during which the unit produced electricity. In 
contrast, under the definition proposed here, a unit can qualify as a 
``cogeneration unit'' if it meets the efficiency and operating 
standards every year starting the later of November 15, 1990 or the 
date on which the unit first produces electricity. EPA believes this 
definition of ``cogeneration unit'' is preferable because it may be 
problematic to obtain sufficiently detailed information about unit 
efficiency and operations for some units (e.g., old units that may have 
started producing electricity many years ago). This approach is also 
more consistent with the approach taken in the general applicability 
criteria. EPA requests comment on whether it may also be problematic to 
obtain sufficiently detailed information about unit efficiency and 
operation back to November 15, 1990 and whether the efficiency and 
operating standards should be limited to even more recent years by 
requiring that the standards be met every year starting the later of a 
date (e.g., January 1) of a more recent year (e.g., 2000, 2005, or 
2009) or the date on which the unit first produces electricity. Second, 
in CAIR, each unit had to meet individually the efficiency standard 
(i.e., the requirement that useful thermal or electrical output be at 
least a specified percentage of energy input). In contrast, under the 
``cogeneration unit'' definition proposed here, if the cogeneration 
system of which a topping-cycle unit (where power is produced first and 
then useful thermal energy is produced using the resulting waste 
energy) is a part meets the efficiency standard on a system-wide basis, 
then the unit is also deemed to meet that efficiency standard. EPA 
believes this definition is preferable because it addresses cases where 
one unit in a cogeneration system is operated at a lower efficiency 
(e.g., as a ``swing'' unit whose use varies with demand) to allow the 
rest of the units in the cogeneration system to operate with higher 
efficiency. EPA requests comment on whether this approach should also 
be applied to bottoming-cycle units (where useful thermal energy is 
produced first and then useful power is produced using the resulting 
waste energy).
    As discussed previously, the operating and efficiency standards in 
the ``cogeneration'' definition must be met every year. However, EPA is 
concerned whether these annual standards should be applied to a 
calendar year when the unit involved did not operate at all. For such a 
year, the unit would be unable to meet the operating and efficiency 
standards but also would not have any emissions. EPA therefore requests 
comment on whether it should exclude, from the requirement to meet the 
operating and efficiency standards, calendar years (if any) during 
which a unit does not operate at all.
    If a unit meets the definition of cogeneration unit (including the 
efficiency and operating standards), then it may qualify for the 
proposed cogeneration unit exemption depending on whether it meets 
additional criteria concerning the amount of electricity sales from the 
unit. In order to qualify for the exemption, a cogeneration unit would 
need to supply in any calendar year--starting the later of November 15, 
1990 or the start-up of the unit's combustion chamber--no more than 
one-third of its potential electric output capacity or 219,000 MWh, 
whichever is greater, to any utility power distribution system for 
sale. EPA requests comment on whether it may be problematic to obtain 
sufficiently detailed information about the disposition of a unit's 
generation (e.g., how much was used on site or by an industrial host 
and how much was supplied to a utility distribution system for sale) 
back to November 15, 1990 and whether the electricity sales limit 
should be restricted to more recent years by requiring that the limit 
be met every year starting the later of a date (e.g., January 1) of a 
more recent year (e.g., 2000, 2005, or 2009) or the start-up of a 
unit's combustion chamber.
    Solid waste incineration unit exemption. The proposed FIPs also 
include an exemption for solid waste incineration units commencing 
operation before January 1, 1985, for which the average annual fuel 
consumption of non-fossil fuels during 1985-1987 exceeded 80 percent 
and, during any three consecutive calendar years after 1990, the 
average annual fuel consumption of non-fossil fuels exceeds 80 percent, 
on a Btu basis. With regard to a solid waste incineration unit 
commencing operation on or after January 1, 1985, EPA proposes that the 
unit would be exempt if its average annual fuel consumption of non-
fossil fuel for the first 3 calendar years of operation and for any 3 
consecutive calendar years, thereafter, does not exceed 80 percent. 
This is the same as the solid waste incineration unit exemption used in 
CAIR. EPA requests comment on whether it may 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 by 
requiring that the standard be met every year starting the later of a 
date (e.g., January 1) of a more recent year (e.g., 2000, 2005, or 
2009) or the date on which the unit first produces electricity.
    Further, analogous to the approach proposed for the cogeneration 
unit exemption, the proposed solid waste incineration unit exemption 
would apply to units that qualify as solid waste incineration units 
every year starting the later of November 15, 1990 or the date the unit 
first produces electricity. EPA requests comment on whether it may be 
problematic to obtain sufficiently detailed information about whether a 
unit qualified as a solid waste incineration unit back to November 15, 
1990 and whether the qualification requirement should be restricted to 
more recent years by imposing the qualification requirement every year 
starting the later of a date (e.g., January 1) of a more recent year 
(e.g., 2000, 2005, or 2009) or the date of unit first produces 
electricity.
    EPA also proposes to make explicit in the FIPs an interpretation 
that the Agency adopted in applying CAIR, namely that--solely for 
purposes of applying the fossil-fuel use limitation in the solid waste 
incineration unit 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, this 
means that consumer products made from natural gas, petroleum, or coal 
are not fossil fuel, for purposes of determining qualification under 
the limitation on fossil-fuel use, 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).
    Opt-in units. EPA proposes to include, in the trading programs 
under the proposed FIP, provisions allowing non-electric generating 
(non-covered) units to opt into one or more of the proposed trading 
programs. EPA is proposing opt-in provisions since they could encourage 
emission reductions by sources that could make lower cost emissions 
reductions than electric generating units. These lower cost reductions 
could replace higher cost reductions that would otherwise be required 
by some electric generating units and could reduce overall program 
costs.
    Specifically, the proposed opt-in provisions would allow a non-
covered unit to enter a proposed trading program voluntarily and obtain 
an allocation of

[[Page 45308]]

allowances reflecting the unit's emissions before opting in. Once in 
the program, the unit could make emissions reductions at a lower cost 
than other units in the program and then sell, to covered sources for 
use in compliance, allocated allowances that are in excess of the 
unit's reduced emissions. The allowances created for and allocated to 
the opt-in unit would be in addition to the allowances issued from the 
state budget and would be usable in compliance by any covered unit (or 
opt-in unit) just like the allowances allocated from the state budget 
to covered sources. Replacing higher cost reductions by covered units 
by lower cost reductions by opt-in units could reduce the overall cost 
of controlling emissions. EPA requests comment on the benefits and 
concerns of including opt-in provisions.
    The proposed opt-in provisions would establish the following 
procedures, which are similar to those set forth in the CAIR FIPs. A 
unit would be eligible to opt into one of the proposed trading programs 
if the unit: (1) Is an operating boiler, combustion turbine, or other 
stationary combustion device; (2) is in a facility that is located in a 
state subject to that proposed trading program; (3) vents all its 
emissions through a stack or duct; and (4) would be able to meet the 
monitoring, reporting, and recordkeeping requirements for covered units 
under the proposed trading program. The owners and operators, through a 
designated representative, of a source with a unit seeking to opt in 
would submit to EPA an opt-in application, which must include an 
emissions monitoring plan for the unit. If EPA approved the monitoring 
plan, the unit would operate, monitor, and report emissions in 
accordance with the monitoring plan and monitoring and reporting 
requirements under Part 75, for at least one or for up to 3 full 
calendar years (or full ozone seasons, in the case of an opt-in unit in 
the proposed NOX ozone season trading program). The unit's 
monitored heat input and emissions rate for that period would be the 
baseline heat input and baseline emissions rate used in calculating any 
future opt-in allowance allocations.
    After the monitoring period, EPA would review the opt-in 
application and either approve the application (including an allowance 
allocation for the first year of approved opt-in status), effective 
January 1 (May 1 for the NOX ozone season program) of the 
year of the approval, or disapprove the application. By December 1 
(September 1 for the NOX ozone season program) of the first 
year and each subsequent year, EPA would calculate and record the opt-
in unit's allowance allocation for the year. The allowance allocation 
for the year involved would be the product of: The lesser of the 
baseline heat input and the opt-in unit's actual heat input during the 
control period in the immediately preceding year; and the lesser of the 
baseline emissions rate multiplied by 70 percent and the most stringent 
state or federal emissions limitation applicable to the unit (or 
emissions levels resulting from the imposition of Clean Air Act 
requirements) any time during the control period in the year involved.
    After the opt-in unit was in the program for at least four years, 
the owners and operators could request to withdraw the opt-in unit at 
the end of a control period if the unit met the requirement to hold 
allowances covering emissions for that control period and if any 
allowances already allocated for a subsequent control period were 
surrendered. However, the owners and operators could not submit a new 
opt-in application for the withdrawn unit until at least 4 years after 
the last control period before the withdrawal. An opt-in unit that had 
a change in regulatory status during a control period and would then 
meet the general applicability requirements for covered units would 
immediately lose its status as an opt-in unit. Having lost its opt-in 
unit status, the unit would have to surrender to EPA the allocated opt-
in allowances attributable to the portion of any control period during 
which the unit no longer qualified as an opt-in unit.
    In addition to a general request for comment on all aspects of this 
opt-in requirement, EPA requests comment on three specific aspects of 
the proposed opt-in provisions. First, EPA requests commenters to 
explain how much interest they believe owners and operators of 
noncovered sources would have in using these proposed provisions to opt 
into one or more of the proposed trading programs and what types of 
sources would be most likely to opt in. Commenters on this aspect of 
the proposed provisions should consider what effect (if any) future 
emission reduction requirements under upcoming, new regulations (e.g., 
regulations concerning maximum available control technology (MACT) 
standards for sources such as industrial boilers and cement kilns, best 
available retrofit technology (BART) requirements for certain 
stationary source categories, and reasonably available control 
technology (RACT)) might have on the pool of sources that might be 
interested in opting into the program. EPA notes that, in the Acid Rain 
Program, opt-in provisions were established in section 410 of the Act, 
were implemented in the Acid Rain Program regulations starting in 1995, 
and, to date, have been used by 4 facilities (plus 2 more facilities 
that temporarily opted in to obtain allowances for use in the CAIR 
SO2 trading program). In the NOX Budget Trading 
Program, EPA promulgated opt-in provisions that states could include in 
their SIPs and that were used by 3 facilities.
    Second, EPA requests comment on whether it is necessary to take 
steps to identify in this application process whether emissions 
reductions identified by these facilities are reductions units would 
not have made for other reasons unrelated to the opt in. Comments on 
this issue would be especially useful if they discussed how the 
proposed opt-in provisions could be revised in order to ensure that 
opt-in units would not be credited for emissions reductions that the 
units would make even if they did not opt in. For example, a unit that, 
for business or other reasons, was already planning to take actions 
that would have the effect of reducing emissions (e.g., fuel switching) 
may be able to opt in under this proposed approach and obtain allowance 
allocations that could be sold to covered units. In that case, 
emissions reductions that would have occurred anyway would be offset by 
the allocation of new, opt-in allowances that would be in addition to 
the state budget. The net result, in that case, would be an increase in 
total emissions--considering the emissions of both the covered units 
and the opt-in unit--over what total emissions would have been if the 
unit had not opted in. EPA requests comment on whether, in that 
circumstance the total emissions reduction still may be sufficient to 
satisfy the interstate transport issue if such reductions were not 
anticipated in state budgets. In other words, even if emissions 
reductions would have happened in the absence of the program, they may 
still be reductions that alleviate attainment or maintenance issues in 
downwind states. Third, EPA requests comment on whether the baseline 
emission rate used to determine the allocations for each opt-in unit 
should be multiplied by 70 percent before EPA compares that rate to the 
unit's most stringent applicable emissions limitation in order to 
determine which is lower. The lower emission rate would then be used in 
calculating the opt-in unit's allocation. EPA also requests comment on 
whether the allocation for an opt-in unit during Phase II of the 
proposed SO2 Group 1

[[Page 45309]]

trading program should be reduced by 45 percent, reflecting the average 
percent reduction in state SO2 Group 1 budgets from Phase I 
to Phase II. The 70 percent reduction of the baseline emission rate for 
all opt-in units, and the further 45 percent reduction in Phase II 
allocations for SO2 Group 1 opt-in units, would be meant to 
ensure that opt-in facilities install controls in a similar manner as 
covered units; however, all things equal, this may serve to lower the 
number of facilities that would opt into the program. EPA therefore 
specifically solicits comment on whether the proposed 70 percent 
reduction (or some other percentage reduction or no reduction) should 
applied to the baseline emission rate for all opt-in units and on 
whether any additional percentage reduction or 45 percent or some other 
additional percentage reduction should be applied to SO2 
Group 1 opt-in units on Phase II in order to strike a reasonable 
balance between achieving additional reductions per opt-in facility and 
having more facilities opt in.
    Sources equal to or less than 25 MWe and Non-EGUs. Certain smaller 
EGUs and non-EGU sources that were included in the NOX 
Budget Trading Program were brought into the CAIR NOX ozone 
season trading program. For treatment of such sources in the proposed 
FIPs, see section V.F in this preamble.
    In the Northeast, a large number of EGUs serving generators with a 
nameplate capacity equal to or less than 25 MWe contribute 
NOX emissions to ozone problems on high electric demand 
days. There is regional interest in lowering the 25 MWe applicability 
threshold in the ozone season to deal with this issue and in 
potentially requiring these units to operate with greater controls than 
a trading program would necessitate. EPA requests comment on lowering 
the greater-than-25 MWe applicability threshold for EGUs during the 
ozone season, and whether a trading program offers the right approach 
for addressing NOX emissions from these smaller EGUs.
(2) Allocation of Emissions Allowances
    EPA proposes to distribute, to sources in each state, a number of 
emissions allowances equal to the SO2, annual 
NOX, and ozone-season emissions budgets for that state 
identified in section IV.E (the state budgets listed in IV.E are the 
budgets without accounting for variability). As discussed later, EPA 
proposes to set aside 3 percent of each state's emissions budgets for 
new units. Tables IV.E.-1 and IV.E.-2 in section IV.E, referenced 
previously, show the permanent SO2, NOX, and 
ozone season NOX budgets for each covered state (without 
accounting for variability). EPA would distribute four discrete types 
of emissions allowances for four separate cap and trade programs: 
SO2 group 1 allowances, SO2 group 2 allowances, 
NOX annual allowances, and NOX ozone season 
allowances.
    In the SO2 group 1 and SO2 group 2 programs, 
each SO2 allowance would authorize the emission of one ton 
of SO2 annually. In the NOX annual program, each 
NOX annual allowance would authorize the emission of one ton 
of NOX annually. In the NOX ozone season program, 
each NOX ozone season allowance would authorize the emission 
of one ton of NOX during the regulatory ozone season (May 
through September for this proposed rule). Note that, as explained in 
section IV.E, EPA is taking comment on extending the ozone season for 
this rule.
    In each of the four trading programs, a covered source would be 
required to hold sufficient allowances to cover the emissions from all 
covered units at the source during the control period. EPA proposes to 
assess compliance with these allowance-holding requirements at the 
source (i.e., facility) level.
    This section explains how EPA proposes to allocate to two sets of 
units in a state, existing units and new units. This section also 
describes the new unit set asides in each state, allocations to units 
that are not operating, and the recording of allowance allocations in 
facility accounts.
    EPA proposes to base allocations to existing units on projected 
emissions from these units after elimination of some or all significant 
contribution and interference with maintenance (i.e., projected 
emissions after implementation of the proposed FIPs), and after 
deductions for the new unit set asides. Section IV.E describes how EPA 
developed the overall state budgets.
    EPA requests comment on all aspects of the allocation method, such 
as the overall state budgets, the need to have existing unit and new 
unit allowance allocations, the proposed allocation methodology for 
existing units, and the proposed allocation methodology for new units. 
EPA believes the proposed approach is consistent at the state budget 
and unit level with the Court's direction and also addresses the new 
unit issue. The proposed methodology for allocating allowances does not 
consider heat input or fuel adjustment factors. Note that in light of 
the Court decision, EPA also is not proposing any allocation 
methodologies that rely on Title IV existing allowances.
    EPA requests comment on whether there are alternative allocation 
methods EPA should consider that are consistent with the Court 
decision. EPA asks that commenters present any such approaches in 
detail to enable thorough evaluation and that they provide a legal 
analysis demonstrating how the approach is consistent with the Court's 
opinions and the statutory mandate of section 110(a)(2)(D).
    Allocations to existing units. Existing units are units, as 
described in the Applicability section, previously (see 4.b), that 
commenced commercial operation, or are planned \85\ to commence 
commercial operation, prior to January 1, 2012. EPA proposes 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. EPA proposes to use this same method to allocate 
allowances for each of the four trading programs (SO2 group 
1, SO2 group 2, NOX annual, and NOX 
ozone season). This proposed allocation method is different from the 
allocation method used in the CAIR.
---------------------------------------------------------------------------

    \85\ Planned units, as identified in the EGU inventory and 
included in IPM modeling projections, comprise units that had broken 
ground or secured financing and were expected to be online by the 
end of 2011.
---------------------------------------------------------------------------

    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. This approach is also different from the 
allocation method in CAIR. Further details on the proposed allocation 
method for existing units can be found in the ``State Budgets, Unit 
Allocations, and Unit Emissions Rates'' TSD in the docket for this 
rule.
    The proposed FIPs are designed to remove emissions from each upwind 
state that significantly contributes to nonattainment or interferes 
with maintenance downwind. The allocation method is consistent with the 
proposed approach for determining each upwind state's significant 
contribution and interference with maintenance (described in section 
IV) because the allocations would be based on the projected remaining 
emissions from each covered source in each upwind state after removal 
of the state's significant contribution and interference with 
maintenance.
    EPA proposes to allocate to existing units one time, before the 
Transport

[[Page 45310]]

Rule cap and trade programs commence (see discussion of schedule, 
later). The allocations generally would be permanent (with the 
exception of non-operating units, discussed later) as base amounts and 
would not be updated. (Note that any unused new source set aside 
allowances would be distributed proportionally to existing units in 
addition to the base amount.) By not updating the allocations, EPA can 
allocate for several years at once, which supports the development of 
allowance trading markets.
    The proposed unit-level allocations for existing EGUs for Phases I 
and II are set forth in the ``State Budgets, Unit Allocations, and Unit 
Emissions Rates'' TSD in the docket for this rule, but EPA proposes to 
include them in the final rule in an Appendix A to each set of trading 
program regulations (i.e., the SO2 group 1, SO2 
group 2, NOX annual, and NOX ozone season trading 
programs). Because the TSD shows the proposed allocations, Appendices A 
in the proposed trading program regulations do not repeat the 
allocations and are simply reserved. The only circumstances under which 
allocations would not be permanent as base amounts would be if the unit 
in the Appendix A table turned out not to be a covered unit, or turned 
out not to be required to hold allowances to cover emissions, as of the 
first day of the control period in 2012,\86\ or if the unit stops 
operating for three consecutive years.
---------------------------------------------------------------------------

    \86\ If a unit was allocated allowances but turned out not to be 
a covered unit or turned out not to be required to hold allowances 
as of January 1, 2012, then the treatment of the allocation depends 
on when the Administrator determines the unit is not subject to the 
trading program or to the allowance-holding requirement. For 
instance, if the allocation has not been recorded, the Administrator 
would not record it, and, if the allocation has been recorded and 
the Administrator has not completed the compliance determination 
process for the unit, allowances equal to the allocation would be 
deducted from the unit's compliance account.
---------------------------------------------------------------------------

    Allocations to new units. EPA proposes to allocate emissions 
allowances to new units from new unit set-asides in each state. EPA 
proposes, for each of the four trading programs, to define a new unit 
as: Any covered EGU not listed in the table in Appendix A of the 
trading rule applicable to that program; any unit listed in Appendix A 
whose allocation is subject to the requirement that the Administrator 
not record the allocation or that the Administrator deduct the amount 
of the allocation (see previous discussion in footnote), or any unit 
listed in Appendix A that stopped operating for three consecutive 
years, is no longer allocated allowances as an existing unit, but 
resumes operation.
    EPA believes it is important to have a small new unit set-aside in 
each state to cover new units within the budget that was set aside to 
address the state's significant contribution and interference with 
maintenance. To create new unit set-asides, EPA would distribute to 
existing EGUs a quantity of allowances less than the entire state 
emissions budgets. EPA would hold back, for the new unit set-aside for 
a state, 3 percent of the state budget. Three percent was established 
based on the total amount of new unit emissions projected for all the 
covered states (See ``State Budgets, Unit Allocations, and Unit 
Emissions Rates'' TSD). In this way, new units could be allocated some 
allowances for their emissions, which are part of the the state's 
contribution to downwind nonattainment or interference with 
maintenance.
    For every control period after the control period in which a new 
unit commences commercial operation or, in the case of an existing unit 
that did not operate for three consecutive years, resumes operation, 
EPA would allocate to the unit from the new unit set-asides based on 
the unit's reported emissions from the previous control period. EPA 
would not allocate to a new unit for the control period during which 
the unit commences commercial operation because the unit would have no 
actual emissions data on which to base such an allocation.
    EPA proposes that, for the first control period for which the new 
unit wants an allowance allocation from the new unit set aside (after 
the first year of operation), the designated representative of the 
source that includes the new unit would submit to EPA a request for a 
new unit allocation.
    For each control period, any allowances remaining in a state's new 
unit set-aside (after allocations are made to new units that requested 
allowances) would be distributed to the existing units in that state in 
proportion to the existing unit's original allocations. This ensures 
that total allocations to units in the state would equal the state 
budget.
    For each control period, if the size of the new unit set-aside were 
insufficient to provide allocations for all new units requesting 
allowances, then allocations to all new units would be proportionally 
reduced.
    EPA requests comment on the proposed allocation approach for new 
units. EPA also requests comment on alternative allocation approaches 
that would provide allowances to new units for the control period 
during which the unit commences commercial operation.
    Size of new unit set asides. EPA proposes new unit set-asides that 
are 3 percent of the state emissions budgets. The size of the new unit 
set-aside would be 3 percent for the SO2 group 1, 
SO2 group 2, NOX annual, and NOX ozone 
season trading programs, as appropriate, for each state. EPA based the 
size of the proposed new unit set-asides on a comparison of projected 
emissions from new units to projected emissions from existing units for 
all covered states under the proposed State Budgets/Limited Trading 
remedy. As noted previously, EPA proposes that after a unit is not 
operating for three 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. 
This approach would allow the size of the new unit set-asides to grow 
over time. Note that in EPA's analysis to determine the size of the new 
unit set-asides, EPA assumed that allocations for non-operating units 
would be allocated to the new unit set-asides after a unit had ceased 
operating for 3 consecutive years (see ``State Budgets, Unit 
Allocations, and Unit Emissions Rates'' TSD). EPA requests comment on 
the size of the new unit set-asides.
    Non-operating units. EPA proposes that, once an EGU does not 
operate (i.e., does not combust any fuel) for 3 consecutive years, the 
Agency would no longer allocate allowances to the unit, starting in the 
seventh year after the first year of non-operation. All allowances that 
would otherwise have been allocated to the unit for that seventh year 
and every year thereafter would be allocated to the new unit set-aside 
for the state in which the non-operating unit is located. This would 
provide additional allowances for new units that may need them (e.g., 
for new units that replace non-operating units), and reflects the fact 
that new unit emissions are included in the state's budget that 
eliminates the portion of significant contribution and interference 
with maintenance that EPA has identified in today's proposed action (in 
an average year).
    EPA proposes to continue allocating allowances to non-operating 
units during the 3 consecutive years of non-operation plus an 
additional 3-year period to reduce the incentive for owners to keep 
units operating simply to avoid losing the allowance allocations for 
those units. Other options that EPA considered include continuing to 
allocate allowances for an unlimited period of time, or

[[Page 45311]]

immediately discontinuing allocations to such units upon the unit 
ceasing operation.
    Continuing allocations to non-operating units has the benefit of 
reducing the incentive to keep units in operation that should otherwise 
be, for instance, permanently retired due to age and inefficiency. EPA 
believes there will be less incentive to continue running old, 
inefficient EGUs if at least some allowances would still be received 
after retirement. On the other hand, stopping allocations for non-
operating units realigns allowance allocations with the sources that 
actually need such allowances. Non-operating units obviously are no 
longer emitting and so do not need allowances. Moreover, additional 
allowances may be needed for the new unit set-aside to accommodate new 
units coming on line in the future. Allocating allowances for a 
specified, but limited, period after the unit ceases operating for 3 
consecutive years, as EPA proposes to do, would be a middle ground 
approach to this issue.
    EPA requests comment on the proposed approach for allocating 
allowances to non-operating units. EPA requests comment on simplifying 
allocations by not allocating at all to non-operating units. EPA also 
requests comment on maintaining perpetual allocations to non-operating 
units, similar to the treatment of non-operating units in the title IV 
Acid Rain Program.
    Schedule for determining and recording allowances. As discussed 
previously, proposed allocations for existing units are shown in the 
``State Budgets, Unit Allocations, and Unit Emissions Rates'' TSD. EPA 
proposes to include final allocations for existing units in the 
Appendix A for each proposed trading program in the final Transport 
Rule.
    EPA proposes to record initial allowances for existing units in 
facility accounts by September 1, 2011, for the control periods in 
2012, 2013, and 2014. EPA proposes to record allowances for existing 
units by July 1, 2012 and July 1 of each year thereafter, for the 
control periods in the third year after the year the allowances are 
recorded. For example, EPA would record existing unit allowances by 
July 1, 2012 for control periods in 2015. Recording allowances several 
years in advance supports the development of the allowance trading 
markets and provides time for covered sources to plan for compliance.
    As discussed previously, EPA proposes to determine allocations to a 
new unit based on the unit's reported emissions the prior year. 
Although the last quarter of emissions data for a year must be 
submitted to EPA in the fourth quarterly emissions report by January 30 
of the next year, the emissions data in that report may be revised 
based on EPA's review and may not be finalized until May or June after 
receipt of that report. Consequently, EPA proposes to determine new 
unit allocations by July 1 of the year for which the allocation is 
determined. (Because, for an ozone season ending September 30, 
emissions data may not be finalized until the following February or 
March, EPA proposes to determine new unit allocations by April 1.) For 
example, EPA would determine a new unit's allocations for control 
periods in 2012 by July 1, 2012. EPA proposes to make the new unit 
allocation determinations available to the public through a notice of 
data availability. Under the proposal, objections to the notice could 
be submitted, and EPA would issue a second notice of data availability 
referencing any necessary adjustments of the new unit allocations.
    EPA proposes to record allowances for new units by September 1, 
2012 and September 1 of each year thereafter, for the control periods 
in the year that the allowances are recorded. (For the units in the 
NOX ozone season program, the comparable deadline for 
recordation of new units'' allowances is June 1.) For example, EPA 
would record new unit allocations by September 1, 2012 for control 
periods in 2012.
    EPA requests comment on the proposed schedule for determining and 
recording emissions allowances, especially administratively-practical 
ways to record allowances as soon as possible, so facilities have 
information useful in compliance planning.
    Alternative allocation methods. The proposed allocation method, 
described previously, would determine each unit's allocation consistent 
with the proposed approach to determine each state's significant 
contribution and interference with maintenance. EPA considered other 
alternative allocation methods. One is discussed here, but EPA 
recognizes that there are many ways that allowances could be allocated. 
EPA is requesting comment on whether the alternative described here or 
any other approach should be used instead of the proposed allocation 
method.
    As discussed in section IV, the state emissions budgets are 
determined based on EPA's analysis of significant contribution and 
interference with maintenance in each upwind state. EPA believes that 
it is appropriate to develop individual unit allowances consistent with 
this approach. In the proposed approach, EPA does this by allocating 
down to the individual unit level using all of the same assumptions 
used in developing the proposed budgets. Under this approach all units 
are allocated allowances consistent with their projected emissions; 
this means that a unit that installs control equipment receives fewer 
allowances than a similar unit that did not install control equipment.
    EPA is taking comment on an alternative methodology that still 
links unit allowances directly to the way state budgets were developed 
(and thus, significant contribution was defined). In the alternative, 
all units within a state would be treated as a single group. The 
allocation method would distribute allowances equal to a state's 
emissions budget without variability to each covered source in the 
state (in effect, distributing the responsibility for eliminating 
significant contribution and interference with maintenance) based on 
each source's proportional share of total state heat input. The state 
heat input would be as projected for the initial year of the program. 
In other words, this alternative method for distributing allowances 
would have the effect of distributing the responsibility for 
eliminating all or part of a state's overall significant contribution 
and interference with maintenance to individual units based on each 
unit's share of projected heat input.
    There are other approaches to allocation. For example, EPA could 
identify groups of units in each state that are capable of having 
similar emissions characteristics (e.g., grouped by size, fuel type, or 
age). EPA would distribute a state's emissions budget without 
variability to each group of units in the state (in effect, 
distributing the responsibility for eliminating all or part of 
significant contribution) perhaps based on each group's proportional 
share of the state budget as projected in the initial year of the 
program. After apportioning a state's budget to the groups of units, 
under such an approach EPA could distribute allocations to individual 
sources within each group based on each source's proportional share of 
projected heat input. Like the first alternative allocation method 
described previously, this approach distributes each state's 
significant contribution and interference with maintenance to 
individual sources in the state. By determining groups and then 
distributing allocations within the groups based on proportional 
shares, this approach would treat units within the categories equally 
(i.e., it would not treat a source that had acted early to control 
differently from one that had yet to take control action).

[[Page 45312]]

    EPA requests comment on the proposed allocation approach, the 
alternative approach, and on any other approaches that are consistent 
with the Court decision. EPA asks that commenters present any such 
approaches in detail to enable thorough evaluation and that they 
provide a legal analysis demonstrating how the approach is consistent 
with the Court's opinions and the statutory mandate of section 
110(a)(2)(D).
(3) Allowance Management System
    EPA proposes that the State Budgets/Limited Trading remedy include 
an allowance management system (AMS) operated essentially the same as 
the existing allowance management systems that are currently in use for 
CAIR and the Acid Rain Program under Title IV. Under the proposed State 
Budgets/Limited Trading remedy, the SO2 programs and the 
NOX programs would remain separate trading programs 
maintained in EPA's existing AMS. AMS would be 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. Specifically, AMS would track the allocation of all 
SO2 and NOX allowances, holdings of 
SO2 and NOX allowances in compliance accounts 
(i.e., accounts for individual covered sources) and general accounts 
(i.e., accounts for other entities such as companies and brokers), 
deduction of SO2 and NOX allowances for 
compliance purposes, and transfers of allowances between accounts. 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 rate limitations and other 
emissions-related provisions of the cap and trade programs. AMS also 
allows the public to see whether sources are complying. In addition, 
AMS provides data to the allowance market, including a record of 
ownership of allowances, dates of allowance transfers, buyer and seller 
information, and the serial numbers of allowances transferred.
(4) Monitoring and Reporting
    EPA proposes to require that Transport Rule-covered sources monitor 
and report SO2 and NOX emissions in accordance 
with 40 CFR part 75. Most sources that would be covered by the proposed 
Transport Rule are already measuring and reporting SO2 mass 
emissions year round under CAIR and/or the Title IV Acid Rain Program. 
Similarly, most sources that would be covered are already measuring and 
reporting NOX mass emissions year round under CAIR. CAIR and 
the Acid Rain Program both require Part 75 monitoring.
    Consistent, complete, and accurate measurement of emissions, as 
Part 75 requires, ensures that, for a given pollutant, one ton of 
reported emissions from one source is equivalent to one ton of reported 
emissions from another source. Thus, each allowance represents one ton 
of emissions, regardless of the source for which the emissions are 
measured and reported. This establishes the integrity of each 
allowance, which instills confidence in the underlying market 
mechanisms that are central to providing sources with flexibility in 
achieving compliance.
    EPA proposes to require monitoring of SO2 and 
NOX emissions by all existing covered sources by January 1, 
2012 for states covered for the daily and/or annual PM2.5 
NAAQS, and monitoring of NOX emissions by May 1, 2012 for 
sources covered for the 8-hour ozone NAAQS, using Part 75 certified 
monitoring methodologies. New sources would have separate deadlines 
based upon the date of commencement of commercial operation, consistent 
with CAIR and the Acid Rain Program.
    Specifically, a new unit must install and certify its monitoring 
system within 180 days of the commencement of commercial operation. 
While, under the Acid Rain Program and CAIR, the deadline was the 
earlier of 90 operating days or 180 calendar days after commencement of 
commercial operation, EPA intends to propose that part 75 be revised to 
use only the 180-day deadline. EPA believes that using only the 180-day 
deadline would ensure that new units have sufficient time to complete 
installation and certification of monitoring systems without having to 
request extensions of time and would facilitate compliance by making 
the monitoring deadline clearer for owners and operators and easier for 
EPA to apply. See a discussion on units transitioning from CAIR and 
units previously not covered by Part 75 requirements in section V.F, 
later.
    EPA also proposes to require designated representatives to submit 
quarterly reports that would include emissions and related data and 
proposes to establish a procedure for resubmission of quarterly reports 
where appropriate. Specifically, the proposed reporting provisions 
would include the same requirement to submit quarterly reports as the 
requirement in Part 75. In addition, the proposed provisions would 
include language that would make explicit a process that is implicit 
under, and has been in continuous use in, the Acid Rain, NOX 
Budget, and CAIR trading programs. The resubmission process would be as 
follows. The Administrator could review and audit any quarterly report 
to determine whether the report met the monitoring, reporting, and 
recordkeeping requirements in the proposed rule and Part 75. The 
Administrator would provide notification to the designated 
representative stating whether any of these requirements was not met 
and specifying any corrections that the Administrator believed were 
necessary to make through resubmission of the report and a reasonable 
deadline for a response. The Administrator could provide reasonable 
extensions of such deadline. The designated representative would be 
required, within the deadline (including any extensions), to resubmit 
the report with the identified corrections, except to the extent the 
designated representative would submit information showing that a 
correction was not necessary because the report already met the 
monitoring, reporting, and recordkeeping requirements relevant to the 
correction. Any resubmission of a quarterly report would have to meet 
the requirements for quarterly report submission, except for the 
deadline for initial submission of quarterly reports.
(5) Assurance Provisions
    To ensure that the proposed FIPs require the elimination of all 
emissions that EPA has identified that significantly contribute to 
nonattainment or interfere with maintenance within each individual 
state, we are proposing to establish assurance provisions, as described 
later, 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 budget 
with the variability limit for state budgets, discussed in section IV. 
As described therein, 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 is 
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.
    Starting in 2014, EPA is proposing as part of the FIPs to establish 
limits on the total emissions that may be emitted from EGUs at sources 
in each state. For

[[Page 45313]]

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 addition, the 3-year 
rolling average of the state's emissions must not exceed the state 
budget with the variability limit allowed on average for any 
consecutive 3 years for that state (i.e., the state's 3-year 
variability limit). Note that in 2014 and 2015, EPA would apply only 
the 1-year variability limit, and not the 3-year variability limit. 
Because emissions would be evaluated against the 3-year variability 
limit on a 3-year rolling average basis, the application of the 3-year 
variability limit in 2016 would serve to limit emissions in 2014 and 
2015.
    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 one year, and the state's 
annual average emissions for any 3-year period can not exceed, on 
average, the state budget with the state's 3-year variability limit. 
The fact of the 3-year variability limit would further assure that 
emissions are constrained during the two preceding years.
    For example, a hypothetical state has a budget of 100,000 tons, a 
1-year variability limit of 10,000 tons, and a 3-year variability limit 
of 5,800 tons.
     In the first year, collective emissions from covered EGUs 
in the state are 120,000 tons, 10,000 tons over the budget with 1-year 
variability limit of 110,000 tons, triggering the assurance provisions 
in that year.
     In the second year, collective emissions from covered EGUs 
in the state are 97,500 tons, below the state budget with 1-year 
variability limit of 110,000 tons. Assurance provisions are not 
triggered.
     In the third year, collective emissions from covered EGUs 
in the state are 109,000 tons, below the state budget with 1-year 
variability limit of 110,000 tons. Assurance provisions are not 
triggered for the 1-year variability limit. But after three years, the 
state emissions are computed against the 3-year variability limit. The 
3-year rolling average (adding the last 3 years of emissions and 
dividing that by three) computes to 108,833 and determines that the 3-
year variability limit of 105,800 tons is exceeded, even though in any 
one year, the 1-year variability limit may not have been exceeded.
     In the fourth year, collective emissions from covered EGUs 
in the state are 99,000 tons, below the state budget with 1-year 
variability limit of 110,000 tons. Assurance provisions are not 
triggered for the 1-year variability limit. The 3-year rolling average 
of the last 3 years is 101,833, which is less than the 3-year 
variability limit of 105,800. Assurance provisions are not triggered 
for the 3-year variability limit.
    The variability limits for each state are shown in Tables IV.F-1 
through IV.F-3 in section IV. The basis for the variability limits is 
also described in section IV.F. Additional details may be found in the 
``Power Sector Variability'' TSD in the docket to this rule.
    To implement this requirement, EPA would first evaluate whether any 
state's total EGU emissions in a control period exceeded the state's 
budget with 1-year variability limit. Next, EPA would evaluate whether 
any state's total EGU emissions in a control period exceeded the 
state's budget with the 3-year variability limit (once the program is 
in effect for 3 years, and each year thereafter). If any state's EGU 
emissions in a control period exceeded either of these limits, then EPA 
would apply additional criteria to determine which source owners in the 
state would be subject to an allowance surrender requirement. The 
proposed allowance surrender requirement that owners surrender 
allowances under the assurance provisions would be triggered only for 
owners of units in a state where the total state EGU emissions for a 
control period exceed the applicable state budget with the variability 
limit. Moreover, only an owner whose units'' emissions exceed the 
owner's share of the state budget with the variability limit would be 
subject to the allowance surrender requirement.
    In applying the additional criteria, EPA would evaluate which 
source owners in the state had emissions exceeding the respective 
owner's share of the state budget with the variability limit 
(regardless of whether the source had enough allowances to cover its 
emissions). An owner's share would equal the sum of the allocations of 
its EGUs in the state, plus its proportional share of the amount of the 
variability limit that, when included with the state budget, was 
exceeded by the state's EGU emissions during the year involved. If the 
state emissions exceeded both the state budget with the 1-year and with 
the 3-year variability limit, then the 3-year variability limit would 
be used in determining the owner's share of the state budget.
    On the other hand, if the state's total EGU emissions for a control 
period in a given year did not exceed the state budget with the state's 
1-year variability limit and did not exceed, on a 3-year rolling 
average basis, the state budget with the state's 3-year variability 
limit, then the additional criteria concerning the emissions of each 
owner's sources in the state would not apply. For more details see 
subsection V.D.4.i, later, and the rule text at the end of this 
preamble (Sec. Sec.  97.425, 97.525, 97.625, and 97.725--Compliance 
with assurance provisions).
    As discussed previously, EPA would not allocate emissions 
allowances to a new unit for the control period during which the unit 
commences commercial operation. In the case where assurance provisions 
for a state are triggered in the year that a new unit first operates, 
the owner's share--if calculated as the sum of the allocations of its 
EGUs plus its proportional share of the variability limit--would 
necessarily be zero because the new unit would have no allocation for 
that year. Instead, EPA would use a specific surrogate emissions number 
to calculate the maximum amount the unit could emit in that year before 
being required to surrender allowances under the assurance provisions. 
The surrogate emissions number would apply only if the state's 
assurance provisions were triggered and only in the first year of the 
new unit's operation.
    The surrogate emissions number would be calculated by multiplying 
the unit's allowable emissions rate (in lbs/MWe) by the unit's maximum 
hourly load (in MWe/hr) and a default capacity factor specific to the 
unit type. The default capacity factors would be: 84 percent for coal-
fired units, 66 percent for gas-fired combined cycle units, and 15 
percent for combustion turbines in the NOX annual and 
SO2 trading programs; and 89 percent for coal-fired units, 
72 percent for gas-fired combined cycle units, and 22 percent for 
combustion turbines in the NOX ozone season trading program. 
These percentages are based on the 95th percentile capacity factors for 
these unit types in quarterly data that have been reported to EPA for 
coal-fired units commencing operation since 2000 and combustion 
turbines since 2004. EPA believes that this approach would cover a 
range of operating conditions for new units and thus avoid attributing 
to each new unit a share of the state budget with variability 
reflecting the maximum amount of emissions possible for the unit in its 
first operating year, in the case where the state's assurance 
provisions were triggered. (See ``Capacity Factors Analysis for New 
Units'' TSD in the docket for further information on the proposed 
default capacity factors for new units).

[[Page 45314]]

    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 later.
    EPA believes the likelihood of triggering assurance provisions is 
low. The State Budgets/Limited Trading programs have a regional cap 
that limits overall emissions; state-specific budgets that are the 
basis for allocating emissions allowances in each state; assurance 
provisions that each state eliminates the excess emissions leading to 
significant contribution and interference with maintenance that EPA has 
identified in this proposed action; and additional allowance surrender 
requirements for not meeting emissions reductions requirements. As 
discussed in section e, later, the underlying mechanism of cap and 
trade, even without assurance provisions, has succeeded in reducing 
emissions below allowance levels. The accumulated data, history, and 
experience from these programs underscore that emissions reductions 
requirements and environmental and public health goals of the programs 
were met. However, unlike earlier cap and trade programs (e.g., the 
Acid Rain, CAIR, and NOX Budget Trading Programs), where 
allocations were made based on the same average emissions rates for 
classes of units, in this proposed rule EPA specifically designed 
budgets that were intended to match up with reductions at certain cost 
levels used to determine the respective state's significant 
contribution and interference with maintenance. This means more units 
are likely to have allocations close to their emissions when the state 
is eliminating its significant contribution and interference with 
maintenance and there is likely to be less need for trading in order 
for sources to comply with the requirement to hold allowances covering 
emissions. Additionally, EPA has now added assurance provisions to 
ensure that emissions within a state do not exceed the state budget 
with the variability limitation.
    The existence of these assurance provisions will limit incentives 
to trade and ensure that state emissions will stay below the level of 
the budget with the variability limit. An example of a circumstance 
that might result in emissions approaching the variability limit is an 
extended nuclear unit outage that causes a company to run its fossil 
units harder to meet demand. Increased emissions under such a scenario 
would not result from the ability to trade across state boundaries, or 
because the fossil units were not controlled, but because the units 
were operated more. In this type of scenario, emissions would also be 
higher in a rate-based program that did not allow interstate trading.
    EPA is setting two criteria to determine if a state has exceeded 
its budget using the state budget with the 1-year variability limit on 
an annual basis, and the state budget with the 3-year variability limit 
on a 3-year rolling average basis. EPA proposes that emissions from an 
owner's EGUs in excess of the owner's share of the state budget with 
the variability limit would not be a violation of the regulation or the 
CAA. But the owner would be required to make an allowance surrender of 
one allowance for each ton emitted over the owner's proportional share 
of the amount by which state emissions exceed the state budget with the 
variability limit.
    This allowance surrender requirement is significant, and EPA 
believes sufficient, to ensure that the state emissions will not exceed 
the budgets plus the variability limit. The allowance surrender 
requirement, however, is less severe than the penalties (discussed 
later) that apply if a source fails to comply with the requirement to 
hold an allowance for each ton emitted by EGUs at the source. However, 
failing to hold sufficient allowances to meet the allowance surrender 
requirement would be a violation of the regulations and the CAA.
    EPA requests comment on whether the allowance surrender requirement 
should be different (either more or less) than one allowance per ton 
emitted over the owner's proportional share of the state budget with 
the variability limit. In addition, EPA requests comment on whether the 
exceedance of total emissions by an owner's sources over the owner's 
share of the state budget with the variability limit should be a 
violation of the CAA and thus subject to discretionary penalties. 
Finally, EPA requests comment on all aspects of the proposed assurance 
provisions in the proposed FIPs.
(6) Penalties
    All covered sources must hold an allowance for each ton of 
SO2 or NOX emitted and are subject to penalties 
if they fail to comply with this allowance-holding requirement.
    Each source must hold in its compliance account in the AMS enough 
allowances issued for the respective annual trading program 
(SO2 group 1, SO2 group 2, or NOX 
annual programs) to cover the annual emissions of the relevant 
pollutant from all the EGUs at the source. The source owner must 
provide, for deduction by the Administrator, one allowance as an offset 
and one allowance as an excess emissions penalty for each ton of excess 
emissions. These are automatic penalties-they are required, 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., a calendar year), is a violation of the CAA, for which 
the maximum discretionary penalty is $25,000 (inflation-adjusted to 
$37,500 for 2009) per violation under CAA Section 113.
    For the ozone season control program, the same provisions apply as 
for an annual program, except that the control period (and averaging 
period) is the ozone season, not a calendar year. Consequently, the 
relevant allowances and emissions are for an ozone season.
    EPA requests comment on the amount of allowances required for the 
automatic penalties.
c. 2012 and 2013 Transition Period
    For the 2012-2013 transition period, EPA is proposing the State 
Budgets/Limited Trading remedy without the previously-described 
assurance provisions (penalty provisions would remain in effect), but 
taking comment on whether the assurance provisions should be in force 
during that period.
    New state-specific control budgets (developed as described in 
section IV) and new allowances would be allocated to sources in the 
Transport Rule region. These state budgets would reflect the operation 
of all existing and planned emission control devices. Under EPA's 
proposed approach, for 2012 and 2013, intrastate and interstate 
trading, without the assurance provisions, would be allowed.
    The locations of existing and planned air pollution control 
retrofits on EGUs are known, and this knowledge provides greater 
certainty of where reductions will occur and how these reductions 
should impact air quality in downwind areas. There would not be 
sufficient time to complete construction of additional control 
retrofits or entirely new, controlled EGUs before 2014.\87\
---------------------------------------------------------------------------

    \87\ U.S. Environmental Protection Agency (U.S. EPA). 2002. 
Engineering and Economic Factors Affecting the Installation of 
Control Technologies for Multipollutant Strategies. Washington, DC.
---------------------------------------------------------------------------

    Consequently, EPA believes that there is a high level of certainty 
that emissions reductions projected for

[[Page 45315]]

2012-2013 with interstate trading would be achieved within the states 
where they are projected to occur, making imposition of the assurance 
provisions during 2012-2013 unnecessary. In addition, EPA believes that 
the two alternative options discussed later present greater 
implementation challenges than this proposed interim remedy for 2012-
2013. See sections V.D.5 and V.D.6. Except for the absence of the 
assurance provisions, the remedy for 2012-2013 would be the same as the 
State Budgets/Limited Trading option, including compliance and penalty 
provisions described previously.
    The 2012-2013 transition period would provide time for sources to 
migrate to the new rule requirements in 2014, such as preparing for the 
imposition of the assurance provisions and, for some states, tighter 
SO2 budgets. EPA is requesting comment on the proposed 
approach of locking in emissions reductions for 2012 and 2013 by 
allocating new state-specific budgets based on significant contribution 
and interference with maintenance and ensuring that pollution control 
devices operate, while allowing for interstate trading in 2012 and 2013 
without the assurance provisions. Assurance provisions would provide 
sources less flexibility and therefore likely increase compliance 
costs, but would be required starting in 2014. EPA requests comment on 
the pros and cons of including assurance provisions or other 
limitations on trading during the 2012-2013 period. Section IV.F 
presents variability limits for the alternative where assurance 
provisions would apply during 2012 and 2013 (see Tables IV.F-1 through 
IV.F-4).
d. Electric Reliability
    The State Budgets/Limited Trading remedy is not a risk to electric 
reliability. The option for sources to trade across state borders and 
to emit up to the specified state budget with variability limit gives 
ISOs (Independent System Operators) the flexibility to manage regional 
electricity generation so that reliability is maintained. For example, 
the operations of the electricity generation sector under the State 
Budgets/Limited Trading remedy, as compared to the option allowing only 
intrastate trading, would be less constrained by state borders and have 
greater flexibility to handle unexpected events such as extreme weather 
or the loss of generating capacity for extended periods of time.
e. How Emissions Cap and Trade Programs Have Worked Under Title IV, the 
NOX SIP Call, and CAIR
    Even absent assurance provisions, cap and trade programs have 
resulted in broad-based emissions reductions distributed across the 
entire covered area, with the reductions coming where emissions were 
highest and most cost effective. The national SO2 emissions 
cap and trade program that EPA implemented under Title IV of the CAA 
Amendments (the Acid Rain Program) and the regional SO2 and 
NOX programs established under CAA section 110(a)(2)(D)(i), 
in the form of the NOX Budget Trading Program and the three 
CAIR trading programs, all have several key components in common:
     Phases and reductions.
    [cir] An emissions cap is established and the programs are phased 
in, with increasing stringency to lower emissions.
     Allowance allocation.
    [cir] Authorizations to emit, i.e., allowances, are allocated to 
affected sources and are limited by each state's trading budget.
     Allowance trading.
    [cir] Markets enable sources to trade allowances.
     Flexible compliance.
    [cir] Sources have the flexibility to choose the most efficient way 
to comply including adding emission control technologies, updating 
control technologies, optimizing existing controls, switching fuels, 
and buying allowances.
     Annual reconciliation.
    [cir] At the end of every compliance period, each source must 
surrender sufficient allowances to cover its emissions. Excess 
allowances may be sold or banked for future use.
     Penalties and enforcement.
    [cir] There are automatic penalties and potentially discretionary 
civil penalties for program noncompliance.
     Stringent monitoring and reporting.
    [cir] Sources must use approved monitoring methods under EPA's 
stringent monitoring requirements (40 CFR part 75) to monitor and 
report emissions.
     Data transparency.
    [cir] The data on key program elements, such as emissions, 
allocations, and allowance trades, are publicly available on EPA's web 
site and in annual progress reports.
    About 50 government staff operate these cap and trade programs. 
They have been successful in achieving the emissions reductions goals 
at reasonable costs with virtually 100 percent program compliance. In 
the following paragraphs, specific results from the programs are 
described. These results are documented in program progress reports 
that are available on EPA's Web site (http://www.epagov/airmarkets/
progress/progress-reports.html) and in the docket to this rule, as 
referenced at the end of each program section later.

Title IV Acid Rain Program--Emissions Reductions

    Since program implementation in 1995, the ARP has reduced 
SO2 and NOX emissions from the power sector 
across the nation. In 2008, the ARP SO2 program covered 
3,572 electric generating units (including 1,055 coal-fired units, 
which account for almost 99 percent of total ARP unit SO2 
emissions). Verified data submitted to EPA from 2008 show that:
     SO2 emissions from power sector sources were 
7.6 million tons, which is 52 percent less than 1990 levels and already 
below the statutory annual emission cap of 8.95 million tons set for 
compliance in 2010.
     NOX emissions from power sector sources were 
3.0 million tons, which is 51 percent less than 1995 levels and more 
than double the Title IV NOX program emission reduction 
objective, but also reflects reductions achieved under the 
NOX Budget and CAIR NOX trading programs.
    The largest reductions have occurred in the states with the highest 
power plant emissions. These high emitting areas were upwind of major 
populations centers and areas of environmental and ecological concern. 
Emissions reductions have led to improvements in air quality with 
significant benefits to sensitive ecosystems and human health.
     Between the 1989 to 1991 and 2006 to 2008 observation 
periods, decreases in wet sulfate deposition averaged more than 30 
percent for the eastern U.S.
     Acid Neutralizing Capacity (ANC), the ability of water 
bodies to neutralize acid deposition, increased significantly from 1990 
to 2008 in lake and stream long-term monitoring sites in New England, 
the Adirondacks, and the Northern Appalachian Plateau.
     Recently updated assessments of U.S. PM2.5 and 
ozone health-related benefits estimate that PM2.5 benefits 
due to ARP implementation in 2010 are valued at $170-$410 billion 
annually and ground-level ozone benefits from ARP implementation in 
2010 are valued at $4.1-$17 billion (estimates are in 2008 dollars). 
The benefits are primarily from reduced premature mortality.
    See EPA's docket for this rule and http://www.epagov/airmarkets/
progress/ARP_4.html.

[[Page 45316]]

    NOX SIP Call NOX Budget Trading Program--Emissions Reductions. From 
2003-2008, the NBP reduced ozone season NOX emissions 
throughout the NOX SIP Call region each year. Results of the 
program include:
     In 2008, NBP ozone season NOX emissions totaled 
481,420 tons, which is 62 percent below 2000 levels and 9 percent below 
the 2008 NOX emissions cap. Emissions were also below the 
caps in 2006 and 2007.
     The average NOX emissions rate for the 10 
highest electric demand days (as measured by megawatt hours of 
generation) consistently fell every year of the NBP.
     The largest NOX emissions reductions and 8-hour 
ozone concentrations reductions took place along the Ohio River Valley, 
as was projected by EPA air quality models of the NOX SIP 
Call.
     Noticeable improvements in ambient concentrations of ozone 
have been measured across the region.
     Of the 104 areas in the eastern United States designated 
to be in nonattainment for the 1997 8-hour ozone NAAQS in 2004, 88 
areas (85 percent) had ozone air quality better than the level of the 
1997 standard in 2008. 8-hour ozone concentrations were 10 percent 
lower in 2008 than in 2001. This decline is largely due to reductions 
in NOX emissions required by the NOX SIP Call 
rule.\88\
---------------------------------------------------------------------------

    \88\ U.S. EPA, Our Nation's Air Status and Trends through 2008, 
Office of Air Quality Planning and Standards, EPA-454/R-09-002, 
Research Triangle Park, NC, pp. 1, 17.
---------------------------------------------------------------------------

    Over the past several years a series of studies \89\ \90\ \91\ have 
evaluated the NOX SIP Call and the link between decreasing 
NOX emissions and decreasing ozone concentrations. These 
studies demonstrate that the NOX SIP Call has been effective 
in improving ozone air quality in the eastern U.S.
---------------------------------------------------------------------------

    \89\ G[eacute]go, E., P.S. Porter, A. Gilliland, and S.T. Rao, 
2007: Observation-Based Assessment of the Impact of Nitrogen Oxides 
Emissions Reductions on Ozone Air Quality over the Eastern United 
States. J. Appl. Meteor. Climatol., 46, 994-1008.
    \90\ Godowitch, J.M., Hogfrefe, C., & Rao, S.T. 2008. Diagnostic 
analyses of a regional air quality model: Changes in modeled 
processes affecting ozone and chemical-transport indicators from 
NOX point source emission reductions. Journal of 
Geophysical Research, 113, D19303, doi:10.1029/2007JD009537.
    \91\ Godowitch, J.M., Gilliland, A.B., Draxler, R.R., and Rao, 
S.T. 2008. Modeling assessment of point source NOX 
emission reductions on ozone air quality in the eastern United 
States. Atmospheric Environment, 42 (1), 87-100.
---------------------------------------------------------------------------

    EPA stopped administering the NBP at the conclusion of 2008 control 
period. States still have the emissions reductions requirements under 
the NOX SIP Call and can use the CAIR NOX ozone 
season trading program to meet these.
    See EPA's docket for this rule for more details on the results of 
the NOX Budget Trading Program, or see http://www.epagov/
airmarkets/progress/NBP_4.html.
    CAIR--Emissions Reductions. Anticipation of the CAIR regional 
program in 2008 resulted in an additional 2.8 million tons of 
SO2 reductions from 2005 levels in the eastern United 
States, bringing emissions well under the 2010 Title IV cap. The 
NOX annual and ozone season programs began on January 1 and 
May 1, 2009, respectively. The SO2 program began on January 
1, 2010. The CAIR cap and trade programs remain in effect, consistent 
with the Court's remand, in order to benefit public health and the 
environment, until EPA replaces the rule.
    Allowance trading. Because of the ease with which allowances can be 
banked, bought and sold, and transferred in the trading programs, 
robust allowance trading markets have developed over the past fifteen 
years, along with considerable banking of allowances.
    Allowance prices and trading activity under the trading programs 
were reduced in 2008 in response to the Court's July 2008 decision in 
North Carolina v. EPA granting petitions for review of CAIR. However, 
the allowance markets remained active. For a recent assessment on 
allowance markets, see http://www.epagov/airmarkets/resource/docs/
marketassessmnt.pdf.
    Transaction Costs. The cap and trade program results described 
previously are real, measurable, and very significant. These results 
demonstrate that cap and trade is a policy tool that can achieve cost-
effective, broad reductions quickly to improve human health and the 
environment and help states meet their obligations to attain the NAAQS. 
While some have suggested that transaction costs associated with cap 
and trade programs were high or problematic, EPA has found no 
indication that this is the case. Transaction costs are important 
because they can diminish the incentive to trade or the amount traded.
    In fact, few empirical studies on transaction costs have been done. 
EPA has searched the literature and compiled a list of anecdotal 
discussions on transaction costs, including a study of the ARP's 
SO2 cap and trade program by Ellerman \92\ of MIT, published 
in 2004. Ellerman suggests that, while no comprehensive study has been 
conducted on the subject, ``* * * the creation of a standard unit of 
account in allowances and the lack of any review requirement for 
trading has avoided the very large transactions costs that limited * * 
* earlier experiments with emissions trading.'' Other studies (see 
Schennach, 2000 \93\) suggest transaction costs are about one percent 
of the allowance price. An industry expert, Gary Hart,\94\ suggested 
that a typical fee charged by a brokerage firm is $0.50 for each 
SO2 allowance.
---------------------------------------------------------------------------

    \92\ Ellerman, A. Denny. 2004. ``The U.S. SO2 Cap-
and-Trade Programme,'' Tradeable Permits: Policy Evaluation, Design 
and Reform, chapter 3, pp. 71-97, OECD.
    \93\ Schennach, S.M. 2000. The Economics of Pollution Permit 
Banking in the Context of Title IV of the 1990 Clean Air Act 
Amendments. Journal of Environmental Economics and Management 40(3): 
189-210.
    \94\ Personal communication with Gary Hart, ICAP-United, June 
25, 2007 as quoted in Napolitano, S., J. Schreifels, G. Stevens, M. 
Witt, M. LaCount, R. Forte, & K. Smith. 2007. ``The U.S. Acid Rain 
Program: Key Insights from the Design, Operation, and Assessment of 
a Cap-and-Trade Program.'' Electricity Journal. Aug/Sept. 2007, Vol. 
20, Issue 7. doi:10.1016/j.tej.2007.07.001.
---------------------------------------------------------------------------

    Tietenberg, in his book, Emissions Trading Principles and 
Practice,\95\ explains the role of transaction costs and their impact 
on trading. Note that Tietenberg and many economists use the word, 
``permits,'' in the same way EPA uses the word, ``allowances.''
---------------------------------------------------------------------------

    \95\ Tietenberg, T.H. 2006. Emissions Trading Principles and 
Practice. Washington, DC. Published by Resources for the Future.
---------------------------------------------------------------------------

    Tietenberg defines transactions costs as ``the costs, other than 
price, incurred in the process of exchanging goods and services. These 
include the costs of researching the market, finding buyers or sellers, 
negotiating and enforcing contracts for permit transfers, completing 
all the regulatory paperwork, and making and collecting payments.'' 
\96\ He also describes how to lower transaction costs, as follows: 
``Transaction costs can be lowered by making permit transactions 
transparent, by the availability of exchanges and knowledgeable 
brokers, and by the sharing of information on the availability of cost-
effective abatement technologies, while administrative costs can be 
lowered by continuous emissions monitoring and by software that 
streamlines monitoring and reporting.'' \97\ He goes on to say, ``Price 
transparency (making prices public) can reduce the uncertainty 
associated with trading and facilitate negotiations about price and 
quantity. One good example is [the] public auctions held each spring 
for the Sulfur Allowance Program [ARP].'' \98\
---------------------------------------------------------------------------

    \96\ Ibid., p. 41.
    \97\ Ibid., p. 73.
    \98\ Ibid., pp. 70-71.
---------------------------------------------------------------------------

    Tietenberg contrasts EPA's earlier credit-based trading programs in 
the

[[Page 45317]]

1970s and 1980s (U.S. Emissions Trading Program (ETP)) with cap and 
trade programs, such as the Acid Rain Program for SO2. He 
says that while credit-based programs ``typically involved a 
considerable amount of regulatory oversight at each step of the process 
(e.g., certification of credits and approval of each trade),'' cap and 
trade programs use instead a system ``that compares actual and 
authorized emissions at the end of the year, which can lower 
transactions costs'' compared to a credit program.
    All the features Tietenberg highlights comprise fundamental aspects 
of EPA's cap and trade program design. Program design remains one of 
the principle ways to ensure lower transaction costs. Over the last 15 
years, EPA's state-of-the-art information management system has evolved 
in parallel with the advancement of technology in order to offer 
platforms for reporting and receiving data and for public access. EPA 
provides dedicated assistance for sources, states, and regions around 
the country on program operations and monitoring and reporting, 
specifically. With limited oversight of transactions, EPA focuses on 
recording data and information accurately, including allowance 
transfers, as well as ``true-up'', where actual emissions are 
reconciled with allowances held in accounts for compliance.
    These features of EPA's program management lead to low transaction 
costs. EPA is attuned to trying to keep requirements as simple and 
straightforward as possible, and offers substantial and routine 
training to ensure successful program implementation and regulatory 
compliance. While some have equated the length of EPA's trading program 
rules with higher transaction costs, in fact, the detailed regulatory 
sections, such as for allocations and the stringent monitoring 
requirements, form the basis of what actually allows the programs to 
function with limited oversight, virtually 100 percent compliance, 
public transparency, and nominal transaction costs.
    For the ARP, NOX Budget Trading Program, and CAIR 
trading programs, EPA records all allowance allocations in accounts in 
an electronic allowance tracking system (currently called the AMS). In 
addition, EPA records in the AMS all allowance transfers that are 
submitted by parties for official recordation. These allowance accounts 
are searchable and visible to the public. The trading program 
regulations that directly govern allowance trading, i.e., the 
regulations governing the establishment of allowance accounts and the 
submission of allowance transfers, are relatively simple and establish 
requirements that are easy to meet. See, e.g., 40 CFR 96.151(a) 
(requiring establishment of source compliance accounts). Allowances may 
be held in an allowance account (i.e., banked) for use or trading in 
any future year in which the trading program involved is in effect. 
See, e.g., 40 CFR 96.155 (allowing banking). Further, allowances may be 
transferred from one account to another with no restrictions except the 
requirements that the authorized account representative of the 
transferor account submit to EPA a simple (generally electronic) 
allowance transfer form identifying the allowances to be transferred 
and the account to receive them, and that the allowances must be 
currently recorded in the transferor account. See, e.g., 40 CFR 96.160 
(requiring submission of specified allowance transfer form) and 
96.161(a)(2) (requiring that allowance be in transferor account). This 
transparency of data and availability of information allows the 
allowance market to function smoothly.
    EPA research found no indications that transaction costs have been 
a problem. From discussions with a leading industry consultant we 
learned that there is enough competition among the approximately 
fifteen brokerage houses that any attempt at charging fees in excess of 
market standards will be bid down through competition.\99\ In many 
instances, clients can negotiate fees even lower than market averages. 
Financial exchanges, such as the Chicago Climate Exchange and New York 
Mercantile Exchange, added SO2 and NOX allowances 
to their list of commodities. Prior to the vacatur of CAIR, transaction 
costs (broker fee as a percent of allowance price) were estimated at 
less than 0.2 percent for SO2, less than 1.8 percent for 
seasonal NOX, and less than 0.5 percent for annual 
NOX.\100\ These transaction costs are low and not expected 
to affect program outcome.
---------------------------------------------------------------------------

    \99\ Memo from ICF International to EPA Clean air Markets 
Division, September 17, 2008. Transaction Costs in Allowance Trading 
Markets.
    \100\ Ibid.
---------------------------------------------------------------------------

    In summary, EPA believes its cap and trade programs functioned 
efficiently and did not result in high transaction costs for several 
reasons. First, in developing the regulations for the trading programs, 
EPA strove to make the programs as transparent as possible in order to 
ensure that relevant data were available to the market, to minimize 
regulatory oversight of trading activity, and to let the market work 
unhampered. Strong markets exist that have seen upwards of 273 million 
SO2 allowances transferred to date. Educational and 
professional associations that hold regular conferences for members, 
regulated entities, government agents, and the public have existed to 
increase transparency of information and exchange ideas on cap and 
trade programs for more than a decade.
    Further, EPA is not aware of any source participating in the 
trading programs over the past 15 years that expressed concern about 
the costs of making allowance transfers. For example, EPA has received 
no comment in the rulemaking proceedings for the trading programs 
raising concern about the level of transactions costs for allowance 
transfers under these programs, and no party challenged the allowance 
transfer provisions on appeal of any of the trading program rules.
    In addition, all available information indicates that actual 
transactions costs are very low. For a list of some articles written by 
scholars and economists over the past 15 years on transaction costs, 
see the docket for this rule.
f. How the Remedy in the Proposed FIPs Is Consistent With the Court's 
Opinions
    The proposed remedy discussed in this section effectuates the 
statutory goal of prohibiting sources within the state from 
contributing to nonattainment or interfering with maintenance in any 
other state. See North Carolina, 531 F.3d at 908. The proposed FIPs 
eliminate all or the emissions that EPA has identified as significantly 
contributing to downwind nonattainment or interference with maintenance 
in today's proposed action by requiring sources to participate in 
emissions trading programs that allow intrastate trading and limited 
interstate trading, and that also 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 emissions allowances sufficient to cover their emissions, 
effectuate the requirement that emissions reductions occur ``within the 
State.''
    A state's ``significant contribution'' is the portion of emissions 
that must be eliminated.\101\ State budgets represent EPA's estimate of 
the remaining emissions after elimination of significant contribution, 
but in actuality

[[Page 45318]]

the amount of remaining emissions may vary. As explained in greater 
detail previously, both the budgets and the assurance provisions 
recognize the inherent variability in state EGU emissions. 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 
states' baseline emissions are variable, their remaining emissions 
after all significant contribution is eliminated are 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, could in fact exceed the state budget without 
variability. For this reason, the assurance provisions limit a state's 
emissions to the state's budget with variability limit.
---------------------------------------------------------------------------

    \101\ Note that in cases where EPA has not fully identified the 
quantity of emissions that represent significant contribution or 
interference with maintenance, state budgets define the emissions 
that remain after the part that has been identified is eliminated.
---------------------------------------------------------------------------

    In addition, the requirement that all sources hold emissions 
allowances (and the fact that the total number of emissions 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) 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 emissions levels, are more likely to vary significantly within the 
region so that resulting emissions 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 proposed use of state budgets 
with the variability limit may allow limited shifting of emissions 
between states is not inconsistent with the Court's holding that 
emissions reductions must occur ``within the state.'' North Carolina, 
531 F.3d at 907. Under the proposed 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. It is 
thus consistent with the statutory mandate of section 
110(a)(2)(D)(i)(I) as interpreted by the Court.
g. Why EPA Is Proposing the State Budgets/Limited Trading Option
    The FIPs that EPA is proposing use the State Budgets/Limited 
Trading remedy to eliminate all of the significant contribution and 
interference with maintenance that EPA has identified. This remedy--
which would use state budgets (see section IV) and allow full trading 
within each state and limited trading outside of each state--would be a 
cost-effective method for eliminating all or part of each state's 
emissions that constitute a significant contribution and interfere with 
maintenance, would be consistent with the Court's decision in North 
Carolina v. EPA, and would address the issues raised by the Court.
    In the first phase (2012 and 2013), the proposed remedy would 
provide a new interstate trading program that would ensure existing and 
planned pollution controls operate. Units would be required to run 
their existing, or already planned, pollution control devices when the 
units are operating. The State Budgets/Limited Trading remedy would use 
the new state budgets described in section IV and allocate allowances 
to individual sources using a methodology directly related to the 
methodology used to identify emissions that significantly contribute to 
nonattainment or interfere with maintenance in downwind areas. EPA 
believes that because the location of existing and already planned 
pollution controls for 2012 and 2013 is known, the use of these 
budgets, even without the added assurance provisions, would assure that 
the necessary emissions reductions would occur in each state under the 
trading programs during those years. The impact of the resulting 
emissions reductions on atmospheric concentrations of particulate 
matter and other pollution, and subsequent benefits for the environment 
and human health, would be significant and are described in sections 
III.B and IX. The proposed remedy would offer the most expeditious 
approach practicable for compliance in 2012-2013, given the short time 
available for sources, states, and EPA to implement a transition from 
CAIR. While there is some uncertainty about how quickly units 
potentially capable of switching fuels would actually be able to 
implement such fuel switching, the banking provisions of the State 
Budgets/Limited Trading approach would provide incentives to reduce 
emissions as quickly and early as possible. The trading provisions 
would provide flexibility for sources to purchase allowances in the 
meantime, without the risks of unexpected high costs, non-compliance, 
or the inability to operate if unable to switch fuels. The remedy would 
be relatively easy for sources and states to understand and follow as 
they transition from prior trading programs to a new regime, beginning 
in 2014, that would include limits on interstate trading.
    The second phase would begin in 2014 with tighter state-specific 
SO2 caps for states in the more stringent group 1 tier to 
address significant contribution and interference with maintenance. In 
addition, assurance provisions limiting interstate trading would become 
effective in each state. This approach in the proposed remedy, which is 
modeled in several ways after the approaches of the ARP and NBP 
programs, is likely to lead to virtually 100 percent compliance. The 
approach ensures that, as we see economic growth, future air quality is 
not compromised and states can depend on emissions reductions in 
meeting local air quality goals.
    The limited interstate trading permitted in this proposed remedy 
would address some of the problematic issues identified in the 
alternative options discussed later, such as, under the intrastate 
trading option, concerns about the administrative burden and needed 
resources associated with administering 82 new trading programs (with 
82 new sets of allowances),

[[Page 45319]]

conducting 82 annual auctions, concentrated allowance market power 
within individual states, and regional electricity reliability. In 
particular, the interstate trading component with assurance provisions 
would mean that allowances issued for one state for a trading program 
could be used in any of the states included in the respective trading 
program. This feature of the proposed remedy would create a regionwide 
allowance market, rather than single-state allowance markets where 
individual owners of sources would be much more likely to have market 
power (see discussion later in section V.D.5). Further, the interstate 
trading component with assurance provisions would provide source owners 
with much more flexibility to ensure electric reliability in the event 
of future variability in electricity demand (e.g., due to weather or 
economic changes) or in the availability of specific individual 
electricity generation facilities.
    In addition, the proposed State Budgets/Limited Trading remedy 
provides reductions at a lower cost than the direct control option 
described later and is flexible enough to accommodate unit-specific 
circumstances. In contrast, the direct control option described later 
would involve a complex process of determining unit-by-unit emissions 
limits that might need to take account of unit-specific circumstances. 
Moreover, this option would be roughly $600 million (2006$) more 
expensive than the proposed remedy in 2012. See section V.E for more 
details on projected costs and emissions.
    In summary, EPA believes that interstate trading, although limited 
by the assurance provisions, would allow source owners to choose among 
several compliance options to achieve required emissions 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 would also 
allow the electricity sector to continue to operate as an integrated, 
interstate system able to provide electric reliability. Compared to the 
alternative options, EPA believes the State Budgets/Limited Trading 
remedy would provide the greatest flexibility to companies complying 
with the rules and is the approach most likely to achieve the goals and 
principles outlined in section III.C.
    The proposed remedy provides intrastate and interstate trading 
components that simplify implementation for EPA (and, where applicable, 
states) and sources and results in cost-effective achievement of 
required emissions reductions. Resource needs for EPA and sources to 
implement the proposed remedy are expected to be comparable to the 
resources necessary to implement CAIR.
    EPA believes the State Budgets/Limited Trading proposed remedy 
provides more assurance that the emissions levels necessary to address 
NAAQS nonattainment are not exceeded than most previous regulatory 
programs such as rate-based direct control programs and even 
nonattainment plans, none of which places an absolute cap on emissions. 
EPA has pointed out, in contrast, that the results from cap and trade 
programs such as the Acid Rain and NOX Budget Trading 
programs demonstrate how substantial emissions reductions have been 
delivered throughout the respective covered region with high levels of 
compliance, at low costs, and with significant health and ecological 
benefits. The proposed State Budgets/Limited Trading remedy provides 
added assurance that emissions reductions now will occur on a state-by-
state basis, not just overall at a regional level. These assurance 
provisions would prohibit states from exceeding their state-level 
budgets with variability limits and impose stringent and costly 
allowance surrender requirements that are known upfront to deter 
exceedances. EPA is confident that the proposed program is both 
reasonable to implement and stronger than the alternative options.
    Additionally, this remedy approach and the method EPA proposes for 
determining significant contribution together provide a workable 
regulatory structure for not only dealing with the transport problem 
for the existing NAAQS, but also would be usable in the years ahead 
when EPA considers further revisions of the NAAQS, notably for ozone 
and fine particles. EPA requests comment on the State Budgets/Limited 
Trading proposed remedy. EPA is also requesting comment on the two 
options described later in sections V.D.5 and V.D.6.
h. Other Limited Interstate Trading Options Evaluated
    EPA considered a range of ways to create an interstate-trading-
with-limitations option consistent with the direction provided by the 
Court. One option considered was to put in place simultaneously 
intrastate trading with direct control requirements and interstate 
trading with direct control requirements. The challenges associated 
with developing direct control requirements are discussed in section 
V.D.6 later.
    EPA also considered interstate trading with backstop provisions, 
which were rejected as not workable. EPA considered a backstop 
provision that prohibited the units in a state from future 
participation in the interstate trading program if the state's 
emissions in a control period in any year exceeded the state's budget 
with variability. In that event, the units would be limited to 
intrastate trading only in the control period of the next year. This is 
not EPA's proposed option because data on annual emissions are not 
final until several months into the next year, making it hard for the 
units in a state to know early enough whether they would be in the 
interstate trading program or an intrastate trading program for that 
next year. This would make compliance planning and implementation of 
compliance plans extremely difficult and adversely affect allowance 
markets.
    In summary, EPA rejected these alternatives as more complicated and 
perhaps problematic to implement. Instead, EPA is proposing the State 
Budgets/Limited Trading remedy, which is similar in many ways to the 
approaches implemented in the past that have succeeded in reducing 
emissions. However, in order to address the Court's concerns about 
trading, the proposed remedy includes assurance provisions to ensure 
that the remedy removes each upwind state's significant contribution 
and interference with maintenance. The ``Other Remedy Options 
Evaluated'' TSD in the docket contains greater detail on the 
deliberations undertaken to evaluate other options for this rulemaking.
i. Structure and Key Elements of Proposed Transport Rule Trading 
Program Rules for State Budgets/Limited Trading
    This preamble section describes the structure and key elements of 
the proposed Transport Rule trading program rules for the State 
Budgets/Limited Trading remedy in the proposed FIPs. Proposed 
regulatory text that would be added to the Code of Federal Regulations 
if this option is finalized appears at the end of this notice. EPA 
requests comment on the structure and key elements of the program as 
well as on the proposed regulatory text.
    In order to make the proposed FIP trading program rules as simple 
and consistent as possible, EPA designed them so that the proposed 
rules for each of the trading programs (i.e., the Transport Rule 
NOX Annual trading program, Transport Rule NOX 
Ozone Season trading program, Transport Rule

[[Page 45320]]

SO2 Group 1 trading program, and Transport Rule 
SO2 Group 2 trading program) would be parallel in structure 
and contain the same basic elements. For example, the proposed rules 
for the Transport Rule NOX Annual, NOX Ozone 
Season, SO2 Group 1, and SO2 Group 2 trading 
programs would be located, respectively, in subparts AAAAA, BBBBB, 
CCCCC, and DDDDD of Part 97. Moreover, the order of the specific 
provisions for each trading program would be same, and the provisions 
would have parallel numbering. The key elements of the proposed 
Transport Rule trading program rules are discussed later.
(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
    The definitions and measurements, abbreviations, and acronyms would 
be the same in all four proposed Transport Rule trading programs, 
except where necessary to reflect the different pollutants 
(NOX and SO2), control periods (for 
NOX, annual and ozone season), and geographic coverage (for 
SO2, Group 1 and Group 2) involved. Moreover, many of the 
definitions would be essentially the same as those used in prior EPA-
administered trading programs, in some cases with modifications to 
reflect the specific, proposed Transport Rule trading program involved. 
For example, the definitions of ``unit'' and ``source'' would be the 
same as in prior trading programs. As a further example, the 
definitions of ``allowance transfer deadline,'' ``owner,'' and 
``operator'' would be the same as in prior trading programs, except for 
references to Transport Rule NOX Annual allowances, 
Transport Rule NOX Ozone Season allowances, Transport Rule 
SO2 Group 1 allowances, or Transport Rule SO2 
Group 2 allowances or Transport Rule NOX Annual units and 
sources, Transport Rule NOX Ozone Season units and sources, 
Transport Rule SO2 Group 1 units and sources, or Transport 
Rule SO2 Group 2 units and sources, as appropriate. As a 
further example, the term ``Allowance Management System'' would be used 
instead of the term ``Allowance Tracking System'' but would have 
essentially the same definition, while referencing the type of 
allowances appropriate for the proposed Transport Rule trading program 
involved. As a further example, ``continuous emission monitoring 
system'' is essentially the same as in prior trading programs, except 
for references to the proposed Transport Rule trading program rules.
    Some definitions would be similar to those used in prior EPA-
administered trading programs but with some substantive differences. 
For example, the definitions of ``cogeneration unit'' and ``fossil-
fuel-fired,'' used in the applicability provisions and discussed in 
this section of the preamble, would be 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.
    A few new definitions would be included to reflect unique 
provisions of the proposed Transport Rule trading programs. For 
example, the terms, ``owner's assurance level'' and ``owner's share'', 
would be used in the Transport Rule assurance provisions and defined in 
the proposed Transport Rule trading program rules. The assurance 
provisions are discussed previously in section V.D.4.b.
(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 would be the same for each of the 
proposed Transport Rule trading programs, except that the provisions 
would reflect (through the definition of ``state'') differences in the 
specific states whose EGUs are covered by the respective Transport Rule 
trading programs (as discussed in section IV.D of this preamble). In 
general, the proposed Transport Rule trading programs would cover 
fossil fuel-fired boilers and combustion turbines serving 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. The applicability provisions are 
discussed previously in section V.D.4.b.
    The provisions exempting permanently retired units from most of the 
requirements of the Transport Rule trading programs would be the same 
for each of the trading programs. The purpose of the retired units'' 
exemption would be to avoid requiring units that are permanently 
retired to continue to operate and maintain emission monitoring 
systems, to report quarterly emissions, and to hold allowances, as of 
the allowance transfer deadline, sufficient to cover their emissions 
determined in accordance with the monitoring and reporting 
requirements. Consequently, the retired unit provisions would exempt 
these units from the rule sections imposing the relevant monitoring, 
recordkeeping, and reporting requirements and allowance-holding 
requirements. However, an owner would include each of these permanently 
retired units that it owns in determining whether and, if so, how many 
allowances the owner would be required to surrender in compliance with 
the assurance provisions. As discussed earlier in this section, while 
these units would have zero emissions once they are permanently 
retired, the units could continue to receive allowance allocations for 
several years thereafter. Consequently, an owner would include these 
units in determining whether the owner's share of total emissions of 
covered units in a state exceeded its share (generally based on the 
allowances allocated to its units) of the state budget with the 
variability limit and thus whether the owner would have to surrender 
allowances under the assurance provisions.
    The exemption for a retired unit would begin on the day the unit is 
permanently retired. The unit's designated representative (i.e., the 
person authorized by the owners and operators to make submissions and 
handle other matters) would be required to submit notification to the 
Administrator within 30 days of the unit's permanent retirement.
    The retired unit exemption provisions would not directly address 
any permit-related matters concerning these units. This would be 
consistent with the general approach under the Transport Rule trading 
program rules of leaving permitting matters largely to be addressed by 
the existing, applicable state and federal title V permit programs. 
Permitting is discussed in section VIII of this preamble.
(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 proposed Transport Rule trading programs and 
presented as standard requirements would 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 Act provisions. The paragraphs, in the standard 
requirements section, that would address designated representative 
requirements and emissions monitoring, reporting, and recordkeeping

[[Page 45321]]

requirements would reference the details of these requirements in other 
sections of the proposed Transport Rule trading program rules.
    The paragraphs addressing emissions requirements would describe 
these requirements in detail and reference other sections that would 
set forth the procedures for determining compliance with the emissions 
limitations and assurance provisions. These paragraphs would also 
explain that: Transport Rule NOX Annual allowances, 
Transport Rule NOX Ozone Season allowances, Transport Rule 
SO2 Group 1 allowances, or Transport Rule SO2 
Group 2 allowances would each authorize emission of one ton of 
emissions under the applicable Transport Rule trading program; such 
authorizations could be terminated or limited by the Administrator to 
the extent necessary or appropriate to implement any provision of the 
CAA; and such allowances would not constitute a property right. The 
proposed Transport Rule SO2 trading programs use new 
SO2 allowances and not CAA Title IV allowances, thus the 
provisions allowing the Administrator to terminate or limit the 
Transport Rule trading program allowances under this rule would not be 
contrary to the Court's North Carolina decision, which addressed the 
Administrator's authority to terminate or limit Title IV SO2 
allowances through the CAIR.
    The remaining paragraphs in the standard requirements section 
concern permitting, recordkeeping and reporting, liability provisions, 
and the effect on other CAA provisions. As discussed in section VIII of 
this preamble, the paragraphs concerning permitting requirements would 
be limited to stating that no title V permit revisions would be 
necessary to account for allowance allocation, holding, deduction, or 
transfer and that the minor permit modification procedures could 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. The paragraphs on recordkeeping and reporting would 
generally require owners and operators to keep on site for 5 years 
copies (which could be electronic) of certificates of representation, 
emissions monitoring information (including quarterly emissions data), 
and submissions and records demonstrating compliance with the proposed 
Transport Rule trading programs. The paragraphs on liability would 
state that each covered source and covered unit would be required to 
meet the Transport Rule trading program requirements, any provision 
applicable to a source or designated representative would be applicable 
to the source and unit owners and operators, and any provision 
applicable to a unit or designated representative would be applicable 
to the unit owners and operators. The paragraph on the effect on other 
CAA provisions would state that the Transport Rule trading programs do 
not exempt or exclude owners and operators from any other requirements 
under the CAA, an approved SIP, or a federally enforceable permit.
(iv) Sec. Sec.  96.407, 97.507, 97.607, and 97.707--Computation of Time
    These sections would clarify how to determine the deadlines 
referenced in the proposed Transport Rule trading program rules. For 
example, deadlines falling on a weekend or holiday are extended to the 
next business day. These are the same computation-of-time provisions 
used in prior EPA-administered trading programs.
(v) Sec. Sec.  97.408, 97.508, 97.608, 97.708 and Part 78--
Administrative Appeal Procedures
    Final decisions of the Administrator under the proposed Transport 
Rule trading program rules would be appealable to EPA's Environmental 
Appeals Board under the regulations that are set forth in part 78 (40 
CFR part 78) and are proposed to be revised to accommodate such 
appeals. Specifically, the list in Sec.  78.1 of the types of final 
decisions that could be appealed under Part 78 would be expanded to 
include specific types of decisions under the proposed Transport Rule 
trading program rules.
    Further, under the approach in the existing part 78, an 
``interested person'' (in addition to the official representative of 
owners and operators or an allowance account involved in a matter) may 
petition for an administrative appeal of a final decision of the 
Administrator. In order to expand the ``interested person'' definition 
(which is currently in part 72 of the ARP regulations) and make the 
definition more readily accessible to readers of part 78, the 
definition would be removed from Sec.  72.2, added in Sec.  78.2, and 
expanded in a way that would cover the proposed trading program rules. 
Provisions concerning public availability of information, and 
provisions concerning computation of time (revised to be consistent 
with the requirements for computation of time used by the Environmental 
Appeals Board in other types of administrative proceedings), would also 
be moved to Sec.  78.2. In particular, the revised ``interested 
person'' definition would include, with regard to a decision appealable 
under Part 78, any person who--in connection with the Administrator's 
process of making that decision--submitted comments, testified at a 
public hearing, submitted objections, or submitted their name to be 
included by the Administrator in an interested persons list.
    In addition, Sec.  78.3 would be revised to allow for petitions for 
administrative appeal of decisions of the Administrator under the 
proposed Transport Rule trading programs. Further, Sec.  78.4 would be 
expanded to state that filings on behalf of owners and operators of a 
covered source or unit under the proposed Transport Rule trading 
programs would have to be signed by the designated representative of 
the source or unit. Filings on behalf of persons with an interest in 
allowances in an account in the proposed programs would have to be 
signed by the authorized account representative of the account.
(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 would 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 would include tables providing, for each 
state covered by the particular proposed Transport Rule trading program 
and for each year, the state trading budget (without the variability 
limit), new unit set-aside, and one-year and three-year variability 
limits. With regard to existing units, these sections would also state 
that existing units would be allocated the allowances set forth in 
appendix A of the relevant Transport Rule trading program rules. These 
allocations would be permanent (taking into account the reductions in 
allocations, for the Transport Rule SO2 Group 1 trading 
program, from Phase I to Phase II) with one exception. A unit that does 
not operate (i.e., has no heat input) for three consecutive years 
starting in 2012 would continue to receive its Appendix A allocation 
for those years plus only three more years. Starting in the seventh 
year, the Administrator would stop recording the allocations for the 
unit and would instead add to the new unit set-aside the allowances 
that would otherwise have been recorded for the non-operating unit. 
Because the proposed unit-by-unit allocations are set forth in the 
``State Budgets, Unit Allocations, and Unit Emissions Rates'' TSD cited 
previously,

[[Page 45322]]

the proposed Transport Rule trading program rules do not repeat these 
allocations in Appendix A to each rule. Instead, each Appendix A is 
reserved, and EPA proposes to include the unit-by-unit allocations, for 
each Transport Rule trading program, in Appendix A to the respective 
final Transport Rule trading program rules.
    With regard to new units (as well as units whose allocations are 
subject to the requirement that the Administrator not record them or 
that the Administrator deduct the amount of the allocation and units 
that lost their allocations after not operating and that subsequently 
began operating again), the owner and operator of such units could 
request, by a specified deadline each year, an allocation from the new 
unit set-aside for that year and each year thereafter. The allocation 
would equal that unit's emissions--as determined in accordance with 
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. The Administrator would determine whether the total 
number of properly requested allowance allocations for all units in a 
state for a control period would exceed the amount in the new unit set-
aside for the state for the control period. If not, the Administrator 
would allocate consistent with all proper requests. If the total number 
would exceed the new unit set-aside, the Administrator would allocate 
to each properly requesting unit its proportionate share of the new 
unit set-aside. The Administrator would provide notice of these 
determinations (which would reflect these calculations rather than any 
exercise of discretion on the part of the Administrator) through 
issuance of a notice of data availability to which parties could submit 
objections and a second notice addressing any objections. Any 
unallocated allowances in the new unit set-aside would be allocated to 
existing units in proportion to their current allocations.
    If a unit that was not really a covered unit or a unit that was not 
subject to the allowance-holding requirement were allocated allowances, 
the proposed provisions set forth a process under which the allocation 
would not be recorded or the amount of the recorded allocation would be 
deducted, with one exception. The exception would be if the process of 
determining compliance with the emission limitation for the source that 
includes the unit were already completed, in which case no action would 
be taken to account for the erroneous allocation for the control period 
involved.
(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 would 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 would also describe the designated representative's and 
alternate designated representative's responsibilities and the process 
through which he or she could delegate to an agent the authority to 
make electronic submissions to the Administrator. These provisions 
would be patterned after the provisions concerning designated 
representatives and alternates in prior EPA-administered trading 
programs.
    The designated representative would be the individual 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. This approach 
would ensure that one individual was required to be knowledgeable about 
the requirements of, and responsible for compliance with, all Transport 
Rule trading programs. One alternate designated representative could 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 would legally bind the 
owners and operators, the designated representative and alternate would 
have to submit a certificate of representation certifying that each was 
selected by an agreement binding on all such owners and operators and 
was authorized to act on their behalf.
    The designated representative and alternate would be authorized 
upon receipt by the Administrator of the certificate of representation. 
This document, in a format prescribed by the Administrator, would 
include: Specified identifying information for the covered source and 
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. All submissions (e.g., monitoring plans, 
monitoring system certifications, and allowance transfers) for a 
covered source or covered unit would have to be submitted, signed, and 
certified by the designated representative or alternate. Further, upon 
receipt of a complete certificate of representation, the Administrator 
would establish a compliance account in the Allowance Management System 
for the source involved.
    In order to change the designated representative or alternate, a 
new certificate of representation would have to be received by the 
Administrator. A new certificate of representation would also have to 
be submitted to reflect changes in the owners and operators of the 
source and units involved. However, new owners and operators would be 
bound by the existing certificate of representation even in the absence 
of such a submission.
    In addition to the flexibility provided by allowing an alternate to 
act for the designated representative (e.g., in circumstances where the 
designated representative might be unavailable), additional flexibility 
would be provided by allowing the designated representative or 
alternate to delegate authority to make electronic submissions on his 
or her behalf. The designated representative or alternate could 
designate agents to submit electronically certain specified documents. 
The previously-described requirements for designated representatives 
and alternates would provide regulated entities with flexibility in 
assigning responsibilities under the Transport Rule trading programs, 
while ensuring accountability by owners and operators and simplifying 
the administration of the proposed Transport Rule trading programs.
(4) Allowance Management System
    The Transport Rule trading program rules listed later would 
establish the procedures and requirements for using and operating the 
Allowance Management System (which is the electronic data system 
through which the Administrator would handle 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 would also provide 
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. Consistent with the approach in 
prior EPA-administered trading program, allowance price

[[Page 45323]]

information would not be included in the Allowance Management System. 
EPA's experience is that private parties (e.g., brokers) are in a 
better position to obtain and disseminate timely, accurate allowance 
price information than is EPA. For example, because not all allowance 
transfers are immediately reported to the Administrator for 
recordation, the Administrator would not be able to ensure that any 
reported price information associated with the transfers would reflect 
current market prices.
(vi) Sec. Sec.  97.420, 97.520, 97.620, and 97.720--Compliance and 
General Accounts
    The Allowance Management System would contain two types of 
accounts: compliance accounts, one of which the Administrator would 
establish for each covered source upon receipt of the certificate of 
representation for the source; and general accounts, which could be 
established by any entity upon receipt by the Administrator of an 
application for a general account. A compliance account would be the 
account in which any allowances used by the covered source for 
compliance with the emissions limitations and assurance provisions 
would have to be held. The designated representative and alternate for 
the source would also be the authorized account representative and 
alternate for the compliance account. Using source-level, rather than 
unit-level accounts, would provide owners and operators more 
flexibility in managing their allowances for compliance, without 
jeopardizing the environmental goals of the Transport Rule trading 
programs, because the source-level approach would avoid situations 
where a unit would hold insufficient allowances and would be in 
violation of allowance-holding requirements even though units at the 
same source had more than enough allowances to meet these requirements 
for the entire source.
    General accounts could be used by any person or group for holding 
or trading allowances. However, allowances could not be used for 
compliance with emissions limitations or assurance provisions so long 
as the allowances were held in, and not properly and timely transferred 
out of, a general account. To open a general account, a person or group 
would have to submit an application for a general account, which would 
be similar in many ways to a certificate of representation. The 
application would include, in a format prescribed by the Administrator: 
The name and identifying information of the individual who would be the 
authorized account representative and of any individual who would be 
the alternate authorized account representative; an identifying name 
for the account; the names of all persons with an ownership interest 
with the respect to allowances held in the account; and certification 
language and signatures of the authorized account representative and 
alternate. The authorized account representative and alternate would be 
authorized upon receipt of the application by the Administrator. The 
provisions for changing the authorized account representative and 
alternate, for changing the 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 would be 
analogous to those applicable to comparable matters for designated 
representatives and alternates.
(vii) 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
    By September 1, 2011, the Administrator would record allowance 
allocations for existing units, based on Appendix A to each proposed 
Transport Rule trading program rule, for 2012 through 2014. By June 1, 
2012 and June 1 of each year thereafter, the Administrator would record 
such allowance allocations for each proposed Transport Rule trading 
program for the third year after the year of the recordation deadline, 
e.g., for 2015 in 2012. Recording these allowance allocations about 3 
years in advance of the first year for which they could be used for 
compliance would facilitate compliance planning by owners and operators 
and promote robust allowance markets, including futures markets for 
allowances. By September 1 (for the Transport Rule NOX and 
SO2 annual trading programs and June 1, for the Transport 
Rule NOX Ozone Season program) of each year starting with 
2012, the Administrator would record allowance allocations for that 
year from the new unit set-aside. Because this would occur before the 
allowance transfer deadline for each proposed Transport Rule trading 
program involved, this would still allow for trading and thereby 
promote robust allowance markets.
    The process for transferring allowances from one account to another 
would be quite simple. A transfer would be 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 were submitted to the Administrator and, when the 
Administrator attempted to record the transfer, the transferor account 
included the allowances identified in the form, the Administrator would 
record 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.
(viii) Sec. Sec.  97.424, 97.524, 97.624, and 97.724--Compliance With 
Emissions Limitations
    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 NOX ozone season trading 
program), covered sources would have a window of opportunity (i.e., 
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 might need to cover their emissions 
during the control period. Each allowance issued in each proposed 
Transport Rule trading program would authorize emission of one ton of 
the pollutant, and so would be usable for compliance, for a control 
period in the year for which the allowance was allocated or a later 
year. Consequently, each source would need--as of the allowance 
transfer deadline--to have in its compliance account, or have a 
properly submitted transfer that would move into its compliance 
account, enough allowances usable for compliance to authorize the 
source's total emissions for the control period. The authorized account 
representative could identify specific allowances to be deducted, but, 
in the absence of such identification or in the case of a partial 
identification, the Administrator would deduct on a first-in, first-out 
basis.
    If a source were to fail to hold sufficient allowances for 
compliance, then the owners and operators would have to provide, for 
deduction by the Administrator, 2 allowances allocated for the control 
period in the next year for every allowance that the owners and 
operators failed to hold as required to cover emissions. In addition, 
the owners and operators would be subject to discretionary civil 
penalties for each violation, with each ton of unauthorized emissions 
and each day of the control

[[Page 45324]]

period involved constituting a violation of the Clean Air Act.
    EPA believes that it is important to include a requirement for an 
automatic deduction of allowances. The deduction of one allowance per 
allowance that the owners and operators failed to hold would offset 
this failure. The deduction of another allowance per allowance that the 
owners and operators failed to hold would provide an automatic penalty 
that could not be avoided, regardless of any explanation provided by 
the owners and operators for their failure, and would therefore provide 
a strong incentive for compliance with the allowance-holding 
requirement by ensuring that non-compliance would be a significantly 
more expensive option than compliance.
(ix) Sec. Sec.  97.425, 97.525, 97.625, and 97.725--Compliance With 
Assurance Provisions
    EPA proposes to include assurance provisions in the Transport Rule 
trading programs in order to ensure that each state would eliminate 
that part of its significant contribution and interference with 
maintenance that EPA has identified in today's proposed action (see 
section V.D.4.b previously). As previously discussed, a requirement 
that owners surrender allowances under the assurance provisions would 
be triggered only for owners of units in a state where the total state 
EGU emissions for a control period would exceed the applicable state 
budget with the variability limit. Moreover, only an owner whose units' 
emissions would exceed the owner's share of the state budget with the 
variability limit would be subject to the allowance surrender.
    The process of determining, for a given control period, which 
states would have total EGU emissions sufficient to trigger the 
allowance surrender requirement, which owners would be subject to the 
allowance surrender, and whether those owners were in compliance would 
be implemented in a series of steps. (The dates summarized later apply 
to the proposed annual programs; the dates for the proposed ozone 
season program would be earlier.)
    First, the Administrator would perform the calculations necessary 
to determine whether any states had total state EGU emissions for a 
control period greater than the state budget with the variability 
limit, applying both the 1-year and the 3-year variability limits 
discussed earlier. By June 1 (starting in 2015), the Administrator 
would promulgate a notice of availability of the results of these 
calculations and provide an opportunity for submission of objections. 
By August 1, the Administrator would promulgate a second notice of 
availability of any necessary adjustments to the calculations and the 
reasons for accepting or rejecting any properly submitted objections.
    Second, by August 15, the designated representative of every 
Transport Rule source in a state identified in the August 1 notice as 
having control period emissions in excess of the budget with the 
variability limit would make a submission to the Administrator that 
would identify: Each person having (as of the last day of the control 
period) a legal, equitable, leasehold, or contractual reservation or 
entitlement in the Transport Rule units at the source; and the 
percentage of each such person's reservation or entitlement.
    Third, by September 15, the Administrator would calculate, for each 
state identified in the August 1 notice and for each owner of covered 
units in the state, the owner's share of emissions, the owner's share 
of the state budget with the variability limit, and the amount (if any) 
that the owner would be required to hold for surrender under the 
assurance provisions (i.e., the owner's proportionate share of the 
excess of state emissions over the state budget with the variability 
limit). The Administrator would promulgate a notice of availability of 
the results of these calculations, provide an opportunity for 
submission of objections, and promulgate by November 15 a second notice 
of availability of any necessary adjustments to the calculations and 
the reasons for accepting or rejecting any properly submitted 
objections.
    By December 1, each owner identified in the November 15 notice as 
being required to hold allowances for surrender under the assurance 
provisions would designate a compliance account of one of its covered 
units in the state, and the authorized account representative of the 
compliance account would submit to the Administrator a statement 
designating the compliance account, as the account in which the 
required allowances would be held.
    As of midnight of December 15, the owner would have to have in its 
designated compliance account, or have a properly submitted transfer 
that would move into that compliance account, the amount of allowances 
(usable for compliance) that the Administrator determined (in the 
calculations referenced in the November 15 notice) were required to be 
held by the owner for surrender. The authorized account representative 
could identify specific allowances to be deducted but, in the absence 
of such identification or in the case of a partial identification, the 
Administrator would deduct allowances on a first-in, first-out basis.
    The potential effect of subsequent data revisions that would 
otherwise change the data used in and the results of the 
Administrator's calculations referenced in the August 1 or November 15 
notices discussed previously would be limited. If data used in a notice 
applying the assurance provisions to a given year were revised as a 
result of a decision in, or settlement of, litigation (such as an 
administrative appeal resulting in such decision or settlement or an 
administrative appeal whose results were in turn appealed in a judicial 
proceeding resulting in such decision or settlement) initiated within 
30 days of the promulgation of the notice involved, then the 
Administrator would use the revised data for the calculations in the 
respective notice. Any other data revisions would not be used to revise 
the calculations. The revised data could be used, if relevant, in the 
Administrator's calculations in future notices promulgated for a later 
year. If the revised calculations increased the amount of allowances 
that an owner was required to hold for surrender, the Administrator 
would set a new, reasonable deadline for the owner to hold the 
additional allowances in the owner's designated compliance account. The 
Administrator believes that this limitation on the effect of data 
revisions on the calculation of the amount of allowances owners would 
have to surrender under the assurance provisions is necessary. Because 
an owner's surrender obligation would be calculated using large amounts 
of data involving all the covered units in a state (including 
potentially many units owned by other owners), each owner would face 
the potential that changes in data outside of the owner's 
responsibility and control could change--after the December 15 
allowance-holding deadline--in a way that would increase his surrender 
obligation after that deadline and put him in violation of the 
regulations and the Act. EPA believes that this potential risk would be 
significant enough that it could make many owners reluctant to consider 
any compliance options involving even the limited interstate trading 
allowed under the proposed remedy. The proposal would limit this risk 
by having the Administrator only take account of data revisions 
resulting from decisions in, or settlement of, litigation initiated 
soon after promulgation of the notice involved.

[[Page 45325]]

Owners' potential allowance surrender obligations as of the December 15 
allowance-holding deadline under the assurance provisions would still 
be significant even with this limitation on the potential for the 
surrender obligations to increase after December 15 due to data 
revisions.
    As discussed previously, it would not be a violation of the CAA for 
total state EGU emissions to exceed the state budget with the 
variability limit or for an owner to become subject to allowance 
surrender under the assurance provisions. However, the failure of an 
owner to hold in the designated compliance account a sufficient amount 
of allowances to satisfy this allowance surrender would violate the CAA 
and be subject to discretionary penalties, with each required allowance 
that was not held and each day of the control period involved 
constituting a violation. EPA believes that the allowance surrender 
requirement alone--and certainly when coupled with the potential for 
large discretionary penalties--would ensure that owners would take 
actions to avoid having total state EGU emissions exceed the level that 
would trigger the allowance surrender.
(x) 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 would allow 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. Banking would allow sources to 
make emissions reductions beyond required levels and bank the unused 
allowances for use or trading later. This would encourage development 
of emissions reductions techniques and technologies and implementation 
of early reductions, stimulate the allowance markets, and provide 
flexibility to owners and operators. While this could also 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 would limit such emissions in a way that would 
ensure that the part of each state's significant contribution and 
interference with maintenance that EPA has identified in today's 
proposed action would be eliminated.
    These sections also would provide that the Administrator could, 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 could 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 would establish emissions 
monitoring, recordkeeping, and reporting requirements for Transport 
Rule units that would result in clear, consistent, rigorous, and 
transparent monitoring and reporting of all emissions. Such monitoring 
and reporting would be the basis for holding sources accountable for 
their emissions and would be essential to the success of the Transport 
Rule trading programs. This is because consistent and accurate 
measurement of emissions would be necessary to ensure that each 
allowance would actually represent one ton of emissions and that one 
ton of reported emissions from one source would be equivalent to one 
ton of reported emissions from another source. This would establish the 
integrity of each allowance and instill confidence in the underlying 
market mechanisms that would be central to providing sources with 
flexibility in achieving compliance. Moreover, given the variation in 
the type, operation, and fuel mix of sources covered by the proposed 
Transport Rule trading programs, EPA believes that emissions would need 
to be monitored continuously in order to ensure the precision, 
reliability, accuracy, and timeliness of emissions data supporting the 
trading programs.
    In Sec. Sec.  97.430 through 97.435, 97.530 through 97.535, 97.630 
through 97.635, and 97.730 through 97.735, EPA proposes the monitoring, 
recordkeeping, and reporting requirements for the Transport Rule 
NOX annual, NOX ozone season, SO2 
Group 1, and SO2 Group 2 trading programs, respectively. 
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 
found. The proposed provisions are virtually the same as the 
monitoring, recordkeeping, and reporting requirements under previous 
EPA-administered trading programs, e.g., the ARP and NOX 
Budget and CAIR trading programs.
    Part 75 was originally developed for the ARP and addressed 
SO2 mass emissions and NOX emissions rate. The 
ARP, as established by Congress in CAA Title IV, requires the use of 
continuous emission monitoring systems (CEMS) or an alternative 
monitoring system that is demonstrated to provide information with the 
same precision, reliability, accuracy, and timeliness as a CEMS. 
Subsequently, Part 75 was expanded, for purposes of the NOX 
Budget Trading Program under the NOX SIP Call, to address 
monitoring and reporting of NOX mass emissions. 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, under Part 75, the Administrator can approve 
petitions for alternatives to Part 75 requirements.
    The proposed monitoring and reporting provisions for the Transport 
Rule trading programs would allow use of these same options and 
petition procedures and would reference the applicable provisions in 
Part 75. Existing Transport Rule units would be required to install and 
certify monitoring systems by the beginning of the relevant Transport 
Rule trading program. New Transport Rule units have separate deadlines 
based upon the date of commencement of commercial operation. 
Recognizing that many of the Transport Rule units are already 
monitoring NOX and/or SO2 under Part 75 through 
existing trading programs, continued use of previously certified 
monitoring systems would be allowed when appropriate rather than 
automatically requiring recertification.
    The quality assurance (QA) requirements for the ARP that were 
mandated by Congress under CAA Title IV are codified in Appendices A 
and B of Part 75. Part 75 specifies 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 daily calibrations. A standard set of data validation rules 
apply to all of the monitoring methodologies. These stringent 
requirements result in an accurate accounting of the mass emissions 
from each unit, and EPA provides prompt feedback if the monitoring 
system is not operating properly. In addition, when the monitoring 
system is not operating

[[Page 45326]]

properly, standard substitute data procedures are applied and result in 
a conservative estimate of emissions for the period involved. This 
ensures a level playing field among the regulated units, with 
consistent accounting for every ton of emissions, and also provides an 
incentive to properly maintain, and meet the QA requirements for, each 
monitoring system. The monitoring and reporting provisions in the 
proposed Transport Rule trading program regulations would contain the 
same QA requirements and substitute data procedures as in Part 75 and 
would reference the applicable provisions in Part 75.
    Part 75 requires electronic submission, to the Administrator and in 
a format prescribed by the Administrator, of a quarterly emissions 
report containing all of the emissions data specified in the 
recordkeeping provisions of Part 75. EPA has found that centralized, 
electronic reporting using a consistent format is necessary to ensure 
consistent review and public posting of the emissions data for covered 
units, which contribute to the integrity, efficiency, and transparency 
of trading programs. Further, the inclusion of all emissions data in a 
single quarterly report for each unit means that, if the same data are 
needed for multiple trading programs, the unit only needs to report it 
once in the form of one comprehensive report. The reporting provisions 
in the proposed Transport Rule trading program regulations would 
contain the same requirements for submission to the Administrator of 
electronic, comprehensive quarterly reports as in Part 75. As discussed 
above, the reporting provisions would also include a process for 
resubmission of quarterly reports where appropriate.
5. State Budgets/Intrastate Trading Remedy Option
    As noted earlier in this preamble, in addition to the remedy option 
included in the proposed FIPs, EPA is taking comment on two alternative 
options for eliminating all or part of the emissions in upwind states 
that significantly contribute to nonattainment or interfere with 
maintenance in downwind states. The first of these alternative options 
is the State Budgets/Intrastate Trading option described below. EPA is 
considering the relative merits of this option and requests comment on 
whether it should be included in the final FIPs. EPA also identifies 
below a number of disadvantages that raise concerns for EPA and are 
explained later in this section. EPA requests comment on these issues 
and their impacts on and significance for any final rule.
a. Description of Option
    The State Budgets/Intrastate Trading option would set state-
specific caps for SO2, NOX annual, and 
NOX ozone season emissions from EGUs and create separate 
allowance trading programs within each state in the respective regions 
starting in 2012. The state-specific caps would ensure that all 
required reductions occur within the state and thus would address the 
Court's concerns about abating each individual upwind state's unlawful 
emissions under CAA section 110(a)(2)(D)(i)(I). Similar to other 
trading programs, the owners and operators of each source would be 
required to surrender to EPA one allowance for every ton of emissions 
after the end of every control period. However, a source could only 
use, for compliance with this requirement, an allowance issued for the 
state where the source was located. For purposes of obtaining 
allowances usable in compliance, sources within each state could trade 
allowances amongst themselves, but not with sources located in other 
states. Total emissions in each state could not exceed that state's 
budget and there would be no shifting of emissions to other states thus 
ensuring that each state's contribution to nonattainment and 
interference with maintenance with regard to downwind states would be 
adequately addressed. Banking of allowances for use in a later period 
would be permitted under this remedy option.
    Under this option, EPA would allocate allowances to the covered 
sources within each state, and sources in the state could use for 
compliance only allowances issued for the same state. Even a company 
that operates EGUs in multiple states would not be permitted to use for 
compliance for one of its sources allowances issued to another of its 
sources in a different state. In essence, this approach, if 
implemented, would result in 28 separate trading programs for 
NOX annual, 26 trading programs for NOX ozone 
season, and 28 trading programs for SO2 for a total of 82 
new trading programs to be administered by EPA. These 82 trading 
programs would require 82 separate sets of allowances. Companies that 
own EGUs in more than one state would also be responsible for managing 
their allowances for each program in each state separately.
    Unlike the remedy option in the proposed FIPs or the other 
alternative remedy option, this option does not include assurance 
provisions based on the variability limits described in section IV. 
This option includes a ``hard'' cap for each state equal to its budget, 
which provides assurance that reductions will occur in each state and 
which EPA believes makes additional assurance provisions unnecessary. 
The State Budgets/Intrastate Trading option does allow banking and the 
use of banked allowances to provide sources with some degree of 
operational flexibility in complying with the program. Because this 
option includes provisions for banking emissions allowances (as does 
the proposed State Budgets/Limited Trading remedy), limited year-to-
year (temporal) emissions variability is allowed. EPA requests comment 
on this approach to providing for emissions variability. EPA also 
requests comment on whether assurance provisions based on variability 
limits should be included in this option.
b. How the Option Would Be Implemented
(1) Applicability
    Applicability would be the same for the proposed remedy and for the 
two alternative options, including this one. Refer to section V.D.4 
above for detailed discussion on applicability.
(2) Allocation of Emissions Allowances
    While the general approach for calculating allowance allocations 
would be the same as described above for State Budgets/Limited Trading, 
EPA would not distribute all of the allowances into the source accounts 
each period. The distribution of allowances would be modified because 
of the concentrated nature of numerous state power markets, which would 
be reflected in the state allowance markets if all allowances were 
distributed in each state based on factors reflecting generation in 
that state. The electric power sector tends to be highly concentrated, 
and, within a state, the majority of generation is often owned by a 
relatively small number of companies. This assessment of state 
electricity markets is supported by analysis using the Herfindahl-
Hirschman Index, a way to measure the size of firms in relation to the 
industry and an indicator of the amount of competition among them (see 
Electric Generation Ownership, Market Concentration and Auction Size 
Technical Support Document). To address this potential issue concerning 
the allowance markets in many states, under this option some allowances 
would be withheld from certain sources in each state that control a 
large share of fossil-fueled power generation and

[[Page 45327]]

would be made available for companies with a small share of generation 
in the state.
    The reason for including this provision is that the dominant power 
generation companies in each state would likely receive a large share 
of the allocated allowances and as a result might be able to exert 
control over allowance prices in the state's allowance market. This 
market power and potential for allowance price manipulation could pose 
a threat to the transparency and liquidity of allowance markets and put 
small owners of fossil-fuel fired generation at a disadvantage 
regarding their compliance costs unless the owners were given 
sufficient access to allowances other than through direct purchase from 
the state's dominant companies. Some of these owners of a small share 
of generation might already face higher control costs, higher 
transaction costs, and less flexibility regarding compliance options.
    Moreover, the use of allowance market power to manipulate prices 
could have wider impacts on electricity markets as a whole, electricity 
prices, and electricity reliability both within and across state 
borders. Therefore, the State Budgets/Intrastate Trading approach needs 
to address the potential for excessive market power and ensure that 
allowances would be available to all covered sources at reasonable 
market prices.
    In order to address the potential market power issue, under this 
option, not all allowances would be allocated using the allocation 
method described above in section V.D.4. Rather, a small portion of 
allowances would be withheld from companies with a large share of a 
state's total fossil-fuel fired electricity generation. These 
allowances would be made available for purchase by companies with a 
small share of generation through an annual auction.
    EPA is soliciting comments on whether a potential market power 
problem could arise or reasons why market manipulation would not be a 
concern under this alternative remedy. EPA is also soliciting comments 
on whether the approach of using an annual auction to make allowances 
available to small generators would satisfactorily address this 
potential issue. This approach is detailed in subsection (3) below.
    The approach described for new unit set-asides and allocations to 
non-operating units above for State Budgets/Limited Trading in section 
V.D.4 would remain the same for this option.
(3) Auction of Emissions Allowances
    The use of an annual allowance auction would ensure that companies 
with a small market share in a state would have access to additional 
allowances, if needed, other than through direct purchase from a large 
owner of generation and would reduce the opportunity for market price 
manipulation by dominant companies. This means that EPA would hold a 
total of 82 auctions every year to separately auction SO2 
and NOX ozone season and NOX annual allowances in 
each of the 82 intrastate trading programs. The auction format would be 
single-round, uniform-price, sealed bid with an initial reserve price 
of 70 to 80 percent of the modeled allowance price. Reserve prices 
would be updated at regular intervals to reflect changes in average 
market prices over time. Any unsold allowances would be returned to the 
sources from which they were withheld on a proportional basis. Revenues 
from the auctions would be deposited in the U.S. Treasury, in 
accordance with 31 U.S.C. 3302.
    EPA would use auctions to address market power concerns rather than 
other options it considered. The Agency considered using a different 
allowance allocation method that would take into account an owner's 
share of total generation and distribute proportionally more allowances 
to owners of a small share of the total generation in each state. This 
would also ensure that small owners had sufficient allowances without 
relying on the open markets. However, EPA opted to use an allocation 
methodology based directly on the approach used to quantify each 
state's significant contribution to ensure that a direct link exists 
between allocations and significant contribution to nonattainment or 
interference with maintenance. EPA also considered direct sales of 
allowances withheld from dominant sources but believes that auctions 
would be better suited for determining the appropriate prices for 
allowances than EPA would be at setting fixed allowance prices for all 
trading programs in all states. For these reasons, EPA believes the use 
of auctions would be the best method to address the issue of potential 
allowance market manipulation.
    EPA prefers to use the single-round, uniform-price, sealed bid 
format because it is simple for all participants to understand, 
relatively simple to implement and administer, and deters collusion 
among bidders. In addition, the utility sector already is familiar with 
this type of format, and EPA has several years of experience running 
single-round, sealed-bid auctions for Title IV SO2 
allowances. Other formats considered such as multi-round auctions are 
believed to be more complicated for participants to understand and more 
complex to administer and do not discourage collusion.
    Entities that meet the following criteria would be eligible to 
participate in the allowance auction: (1) They are required to hold 
allowances in the state for compliance; and (2) they own no more than 
10 percent of the total fossil-fuel fired generation within the state 
based on EPA's modeled generation for 2014. EPA considered a range from 
5 to 20 percent share of ownership for all states and believes that 10 
percent ownership is appropriate for determining what constitutes a 
small market share for this rule. EPA believes that by limiting the 
auction to entities that own no more than 10 percent of the fossil-fuel 
fired generation in a state, it would ensure that each auction has 
enough participants to make auctions viable and competitive and also 
ensure that the allowances are available only to those companies that 
may be at a disadvantage in the open markets. Companies with more than 
a 10 percent share of generation tend to operate several units, have 
more flexibility, receive a significant share of allowances, and face 
lower control and transaction costs. EPA is requesting comment on the 
share of electric generation used as a threshold for determining 
participation in auctions and also the percentage of allowances 
available through auctions.
    To implement this option, EPA would withhold 2 to 5 percent of the 
allowances that would be allocated to companies with more than 10 
percent of the generation in order to supply allowances for auction 
each period. This amount is small enough not to have a significant 
impact on those EGUs from which the allowances are withheld and large 
enough to provide a sufficient number of allowances for auction. In 
more highly concentrated states where few companies control much of the 
generation, a relatively greater number of allowances would be 
available through the auction to the smaller, potentially disadvantaged 
companies. Conversely, in states where the electricity sector is less 
concentrated, there is less threat of market manipulation and greater 
likelihood of liquid markets. Thus, in these states relatively fewer 
allowances would be withheld for auction.
    Another variation on this alternative option would be to divide 
companies in each state into three groups, instead of

[[Page 45328]]

just two. The first group would be the companies that own no more than 
10 percent of the total fossil-fuel generation within the state and 
would be able to participate in EPA's allowance auctions. The second 
group would be companies that own a medium amount of fossil-fuel fired 
generation (for example, between 10 to 20 percent of the total). These 
companies would not be allowed to participate in auctions but also 
would not have to contribute any allowances to the auctions. Finally, 
the third group would be those remaining companies that own a large 
share of fossil-fuel generation (for example, more than 20 percent of 
the total). A small percentage of the allowances allocated to these 
companies would be withheld to supply the auctions. EPA is asking for 
comments on this variation on the alternative option and other ways to 
address potential market power problems and on this alternative option.
(4) Allowance Management System
    The allowance management system for the State Budgets/Intrastate 
Trading option would be consistent with the allowance management system 
for the State Budgets/Limited Trading programs described above, and 
with the data system structure EPA has developed for allowance 
management under its existing cap and trade programs such as the CAIR 
and the Acid Rain Program.
(5) Monitoring and Reporting
    Monitoring and reporting provisions would require complete, 
quality-assured monitoring, and timely reporting of emissions to assure 
accountability and provide public access to data, and would be the same 
for EPA's proposed remedy and the State Budgets/Intrastate Trading 
option. Refer to section V.D.4 above for detailed discussion on 
monitoring and reporting requirements.
(6) Penalties
    Under the State Budgets/Intrastate Trading option for an annual 
control program (i.e., any of the 28 SO2 or 28 
NOX annual programs), the requirement that each source hold 
in its compliance account one allowance for each ton of emissions, and 
the penalties for failure to meet this requirement, would be the same 
as described previously in the Penalties section for the State Budgets/
Limited Trading remedy option. However, because sources in a given 
state can only use allowances issued for that state, the penalties 
associated with failure to hold one allowance for each ton of emissions 
are adequate to ensure that emissions from the state do not exceed the 
state budget (except for some temporal variability due to banking). For 
this reason, EPA does not believe that any other penalties or assurance 
provisions (such as the assurance provisions used in the State Budgets/
Limited Trading remedy) are necessary to ensure that each state 
eliminates the portion of significant contribution and interference 
with maintenance that EPA has identified in today's action. EPA 
requests comment on this conclusion.
c. How the State Budgets/Intrastate Trading Remedy is Consistent With 
the Court's Opinions
    The state budgets/intrastate trading remedy, by establishing state-
specific caps on annual or ozone-season EGU emissions, directly 
implements the section 110(a)(2)(D)(i)(I) requirement that emissions 
from sources that contribute significantly to nonattainment in, or 
interfere with maintenance by, any other state with respect to any such 
national primary or secondary ambient air quality standard be 
prohibited. Of the three remedy options considered, this option 
provides the most certainty regarding total annual or ozone-season 
emissions from each state. For this reason, it most directly addresses 
the statutory mandate that the emissions reductions occur ``within the 
State.''
    To implement this remedy option, EPA would use the state budgets 
without variability limits, developed in accordance with the procedures 
described in sections IV.D and IV.E. These budgets represent EPA's 
projection of each affected state's EGU emissions in an average year 
(before accounting for the inherent variability in power system 
operations) after the elimination of all emissions that EPA has 
identified as significantly contributing to nonattainment or 
interference with maintenance.
    The number of allowances in each state budget would be distributed 
or made available (through an auction or otherwise) to sources in that 
state. Only allowances distributed or made available to sources in a 
particular state could be used by sources in that state to satisfy the 
requirement to hold one allowance for every ton of emissions. Thus, 
annual (or ozone season) emissions in the state would be capped at the 
level of the state budget. The limited variability due to banking of 
emissions could allow limited temporal shifting of emissions, but would 
not alter the requirement that reductions occur within the state. This 
remedy is thus sufficient to ensure that all significant contribution 
and interference with maintenance identified by EPA in today's action 
is eliminated.
d. Electric Reliability Issues
    EPA requests comments about whether the State Budgets/Intrastate 
Trading alternative option could have adverse consequences for electric 
reliability. The grid regions, and the movement of electricity within 
each grid region, do not correspond with, and are not limited by, state 
borders. For example, an increase in electricity demand (e.g., due to a 
hot summer), or a decrease in electricity supply (e.g., due to a major 
generation capacity outage), in a given state will not necessarily be 
met, or offset, through increased electricity generation in that same 
state. Instead, the increased demand or reduced supply may well result 
in increased generation outside that state. The sources of the 
increased generation will be determined by availability and economics 
and will not necessarily be confined to generation sources in that 
state. In fact, the ability to obtain additional or replacement supply 
from sources in another part of the state or from another state 
enhances electric reliability.
    Although companies in one state obtain electricity from sources in 
multiple states, the State Budgets/Intrastate Trading option would 
establish emissions budgets on a state basis and would not allow 
sources in one state to use allowances issued to sources in other 
states. A source could use, in covering emissions for the current year, 
both allowances allocated for the current year and banked allowances 
issued by its state for a past year. However, this option would provide 
sources less trading flexibility than the proposed State Budgets/
Limited Trading remedy. The other remedy options allow for emissions 
variability, which should largely address electric reliability 
concerns.
    EPA requests comment on whether the State Budgets/Intrastate 
Trading alternative would provide sufficient flexibility for reliable 
operation of the integrated grid and, if not, whether there would be 
ways of preventing or reducing adverse effects such as including 
additional emissions variability provisions in this option or other 
approaches. EPA requests comment on approaches to provide additional 
emissions variability, or other approaches to increasing flexibility, 
in this option that would be consistent with eliminating all or part of 
the significant contribution and interference with maintenance that EPA 
has identified.

[[Page 45329]]

e. How Smaller Market Trading Programs Have Worked
    These examples of small trading programs below are relevant to 
further understanding of the State Budgets/Intrastate Trading remedy 
option. While small trading programs can succeed, they can also have 
serious consequences for allowance and electricity markets. Budgets and 
caps, allowance availability, and prices all can have a profound impact 
on generation and energy prices for consumers in addition to any air 
quality benefits. In addition, states range in size and number of 
potential program participants making each state's circumstances unique 
and more challenging for EPA to monitor.
(1) Texas Mass Emissions Cap and Trade (MECT)
    EPA has approved a NOX cap and trade program as part of 
an ozone attainment SIP for the Houston Galveston Brazoria (HGB) 
nonattainment area in Texas. The program knows as the Mass Emissions 
Cap and Trade (MECT) program establishes a mandatory NOX 
annual emissions cap for stationary facilities in the HGB area located 
at sites with a collective uncontrolled design capacity to emit 10 tons 
per year or more of NOX. The MECT program source population 
is relatively small but very diverse and covers, among others, EGUs, 
refineries, chemical plants, and industrial and commercial boilers. The 
diverse source population allows the MECT program to be a viable means 
of reducing NOX emissions without impacting electric 
reliability. Overall, the MECT program has not encountered major 
problems caused by its small size and has resulted in environmental 
benefits for the HGB area.
    The MECT program establishes a hard cap for NOX 
emissions at a level modeled as necessary for the area to reach ozone 
attainment. The MECT program started January 1, 2002 and the 
NOX cap stepped down each subsequent year until reaching the 
final cap level of 80 percent of the baseline NOX emissions 
in January 2007. In the MECT program one allowance is equivalent to one 
ton of NOX emissions. Allowances are allocated to existing 
facilities on January 1 of each control period, which spans the 
calendar year. Facilities that do not receive allowances as ``existing 
facilities'' (those in operation at the time of program inception) must 
purchase excess allowances from other covered sources to operate and 
demonstrate compliance. All covered sources are required to hold 
sufficient allowances at the end of each control period to equal 
NOX emissions during the same time period. Allowances can be 
used in the control period of allocation, traded to another covered 
source in the MECT for use in the same time period, or banked for use 
in the following control period.
    Allowances can be traded in one of four ways: Vintage trades, 
current year trades, individual future year trades, or stream trades. 
Vintage trades involve the immediate transfer of vintage allowances. 
Current year trades involve the immediate transfer of current 
allowances. Individual future year and stream trades involve the 
transfer of future allowances, with stream trades involving a transfer 
of allowances in perpetuity. Analysis conducted by the Texas Commission 
on Environmental Quality of the MECT program trading history shows that 
approximately 20 percent of the allowances allocated each year are 
traded and that nearly 50 percent of all program participants have 
participated in allowance trading. Allowance prices are set by market 
demand. Prices of individual year allowances have steadily increased as 
the program has progressed, showing that the value of the allowances 
increases as the cap tightens. Stream trade prices have fluctuated 
throughout the program, but have steadily increased as the final cap 
level has been reached.
(2) Regional Clean Air Incentives Market (RECLAIM)
    In comparison to MECT, RECLAIM is a small trading program that has 
faced a number of challenges due to initial program design decisions. 
In 1994, RECLAIM established a cap and trade program for NOX 
and SO2 emissions as part of an effort to improve air 
quality in the Los Angeles area. Every year the caps decline to meet 
the objective of getting the area into compliance with ozone and 
particulate matter NAAQS. One noteworthy feature of the RECLAIM trading 
programs is the two overlapping cycles. Roughly equal numbers of 
facilities were assigned to each of the two compliance cycles. 
Facilities in compliance cycle 1 complete their twelve month cycle at 
the end of the calendar year (December 31), while facilities in 
compliance cycle 2 complete their twelve-month cycle at the end of the 
fiscal year (June 30). Around 300 facilities have participated annually 
in the RECLAIM NOX trading program. Every facility then 
complied using valid credits of either cycle, but banking of allowances 
for use in a later period was not allowed.
    RECLAIM Trading Credits (RTC) prices for NOX rose from 
about $3,000 per ton early in 2000 to nearly $20,000 per ton in June 
and up to about $70,000 per ton in August of that year. Prices of RTCs 
during the California energy crisis during 2000 and 2001 averaged in 
the $50,000 per ton range.\102\ While the California crisis was the 
result of several malfunctions in the market, the RTC price spike was 
exacerbated by a number of factors starting with the fact that few 
emissions reductions had been made in earlier years. Prior to the 
California crisis, RTCs had been over-allocated, RTC prices had 
remained low, and utilities had taken little action to install costly 
controls. When emissions increased and exceeded the level of allocated 
RTCs, prices shot up to very high levels. In addition, there has been 
speculation that high RTC prices at the time were partly caused by the 
high demand for credits resulting directly from the manipulation of the 
power market by generators.\103\
---------------------------------------------------------------------------

    \102\ Joskow, Paul and Edward Kahn, 2002. A Quantitative 
Analysis of Pricing Behavior In California's Wholesale Electricity 
Market During Summer 2000: The Final Word.
    \103\ Kolstad, Jonathan T. and Frank A. Wolak, 2003. Using 
Environmental Emissions Permit Prices to Raise Electricity Prices: 
Evidence from the California Electricity Market. Published by 
University of California Energy Institute.
---------------------------------------------------------------------------

    The operation of the RECLAIM market also contributed to the high 
prices in the overall power markets. During this period, generators 
would pay excessively high prices for RTCs in order to raise the price 
of southern California generation needed to meet demand in the 
California Independent System Operator (CAISO). Subsequently, 
generation with high RTC costs in the RECLAIM area would be used to set 
the electricity price for all of California. The result was that 
generators could then collect excessive profits on their generation 
located outside the RECLAIM area. In addition, RECLAIM's overlapping 
compliance cycles and assignment of facilities to one of two compliance 
cycles appears to have contributed to some confusion among the 
participants in the markets.\104\ Since that time, significant changes 
have been adopted to improve the program.
---------------------------------------------------------------------------

    \104\ Holland, Stephen P. and Michael Moore, 2008. When to 
Pollute, When to Abate? Intertemporal Permit Use in the Los Angeles 
NOX Market. Published by University of California Energy 
Institute.
---------------------------------------------------------------------------

    According to the audit report for the 2007 compliance period, total 
aggregate NOX emissions were below total allocations by 21 
percent and total aggregate SOX emissions were below total allocations 
by 13 percent. Since January 2008, NOX RTCs prices have been 
declining and have not exceeded $15,000 per ton.

[[Page 45330]]

f. Why This Is Not the Preferred Option
    As explained above, EPA is requesting comment on a State Budgets/
Intrastate Trading remedy as an alternative option because this option 
would provide certainty regarding emissions from each state. However, 
this option would be more resource intensive, more complex, less 
flexible, and potentially more susceptible to market manipulation than 
the other options on which EPA is taking comment.
    Although this remedy may be perceived as relatively easy to 
understand and follow, it would actually be more burdensome to 
administer due to the number of trading programs that would be required 
to operate simultaneously and annual auctions that would be held every 
year to address the issues of market power within states. It would also 
result in a greater burden for participants operating EGUs in several 
states. Finally, EPA is asking for comment on whether this option 
raises electric reliability issues since sources would have less 
flexibility and fewer options for compliance. EPA is requesting 
comments on this approach, specifically on alterations that could 
address the drawbacks identified above or on any other weaknesses of 
this option not identified by EPA. EPA also welcomes comments regarding 
the validity of the concerns with this approach identified above.
6. Direct Control Remedy Option
    The second alternative option on which EPA is requesting comment is 
the direct control option described in this section. EPA is considering 
the relative merits of this option and requests comment on whether a 
direct control remedy option should be included in the final FIPs.
    There are a variety of ways to construct a direct control option. 
The approach that EPA is presenting as an alternative to the remedy in 
the proposed FIPs would assign emissions rate limits to individual 
sources. Emissions limits would take the form of input-based emissions 
rate limits (lb/mmBtu).
    EPA requests comments on the direct control remedy summarized later 
and the approach for determining emissions rate limits, which is 
described in greater detail in the ``State Budgets, Unit Allocations, 
and Unit Emissions Rates'' TSD in the docket for this rulemaking. 
Specifically, EPA requests comment on the general use of a direct 
control remedy as well as the specific rate-based direct control 
approach described later. EPA also requests comment on the potential 
weakness of this remedy option identified in the discussion later. In 
addition, EPA requests comment on alternate methodologies which could 
be used to implement a direct control remedy.
    See section V.E. later for projected costs and emissions associated 
with this option.
a. Description of Option
    Unlike the proposed remedy option (State Budgets/Limited Trading) 
and the other alternative remedy option (Intrastate Trading) discussed 
previously, which both use flexible cap-and-trade approaches, a direct 
control remedy would directly regulate individual sources. Under this 
direct control remedy alternative, each owner of EGUs would be required 
to meet specified average emissions rate limits covering all of its 
EGUs in each covered state. In a state covered for the 24-hour and/or 
annual PM2.5 NAAQS, the direct control remedy option would 
require each company within the state to meet specified EGU annual 
emissions rate limits for SO2 and NOX. In a state 
covered for the 8-hour ozone NAAQS, this remedy would require each 
company within the state to meet specified EGU ozone season emissions 
rate limits for NOX. EPA would set emissions rates on a 
unit-by-unit basis in all covered states (see approach to determine 
emissions rate limits, later).
    While emissions rates in all states would be set on a unit-by-unit 
level, a company would be allowed to average the emissions at its units 
within each state to meet the specified within-the-state rate limits. 
Company-level average rates would be calculated as company-level total 
emissions divided by company-level total heat input in each state. 
Analogously, allowable company-level average rates would be calculated 
using unit-specific rate limits and the heat inputs used to determine 
those allowable rates (as discussed in 6.b.1). A company that exceeded 
the applicable average rate limits would be subject to penalties 
(described later).
    In addition, to address the potential variability in annual 
emissions associated with emissions rate limits (i.e., not all years 
are average), starting in 2012, each state's total annual (or ozone 
season, as applicable) EGU emissions would also be capped. Emissions 
from EGUs in each state would be limited to the state's emissions 
budget with the variability limit. Each state's EGU emissions would be 
capped in the following two ways. First, the state's EGU emissions 
would not be permitted to exceed the state budget with the state's 1-
year variability limit in any year (or ozone season, as applicable). 
Second, on average, the state's EGU emissions would not be permitted to 
exceed the budget with the state's 3-year variability limit, evaluated 
as a 3-year rolling annual (or ozone season) average (or, in 
SO2 group 1 states during 2012 and 2013, a 2-year rolling 
average). See section IV.E for lists of each state's emissions budgets. 
Section IV.F describes EPA's proposed approach to variability. Tables 
IV.F-1 through IV.F-3 present 1-year and 3-year variability limits. 
Table IV.F-4 presents 1-year and 2-year variability limits for 
SO2 group 1 states during 2012 and 2013.
    If total EGU emissions in a state exceed either of these limits 
(i.e., budget with 1-year variability limit in any year, or budget with 
2-or 3-year variability limit on average), then each company with units 
in the state whose emissions in the state exceeded the company's share 
of the state budget with variability limit would be subject to a 
penalty. These assurance provisions are designed to assure that 
emissions in each covered state do not exceed the state's budget with 
variability limit. They are described later. EPA also believes the 
penalty provisions described later are sufficient to ensure that these 
caps would not be exceeded.
    To implement this remedy option, EPA would determine unit-level 
emissions rate limits for SO2, NOX annual, and 
NOX ozone season at levels such that, if the units operated 
at the levels assumed in determining the state budgets, total emissions 
of each pollutant from these units would sum to each state's emissions 
budget for the pollutant without the variability limit. The method for 
determining these rate limits is described later.
    An alternative direct control approach would be to create 
individual unit-level annual emissions caps (e.g., tons/year) in order 
to cap emissions in each state. However, this approach would greatly 
limit operational flexibility and increase risk to electric 
reliability. For example, a unit-level annual emissions cap approach 
could prevent a peaking unit from running at a time when the unit is 
necessary for electric reliability. EPA does not believe that a unit-
level annual emissions cap approach is workable.
b. How the Option Would Be Implemented
(1) Approach To Determine Emissions Rate Limits
    To implement this remedy option, EPA would determine unit-level 
emissions rate limits for SO2, NOX annual, and 
NOX ozone season, for covered EGUs in the covered states.

[[Page 45331]]

Emissions rate limits would be set at levels such that, if the units 
operated at the levels assumed in determining the state budgets, total 
emissions from these units would sum to the state budgets. In a state 
covered for purposes of the PM2.5 NAAQS, EPA would determine 
SO2 and NOX annual emissions rate limits for each 
covered EGU. In a state covered for purposes of the 8-hour ozone NAAQS, 
EPA would determine NOX ozone season emissions rate limits 
for each covered EGU.
    Emissions rate limits for Phase I (2012 and 2013). State budgets 
were derived from the lower of available 2007-2009 quarterly emissions 
or IPM base case projections for 2012, at the state level. Analogous to 
state budget calculation, EPA would base the Phase I annual emissions 
rate limit on either the unit's reported annual emissions rate or the 
IPM projected rate. Rates based on reported data would be calculated 
using the most recent first, second, third, and fourth quarters of 
emissions data reported to EPA, between the first quarter of 2007 and 
the third quarter of 2009, where four such quarters of reported data 
are available. EPA would determine ozone season rates based on a unit's 
most recent ozone season emissions reported to EPA during the period of 
2007-2009, if available, and projections or source-specific judgments 
otherwise.
    For units where EPA is aware that SO2 or NOX 
controls will be installed by 2012 and such controls were not reflected 
in the unit's reported emissions rate as determined previously (i.e., 
the control was not in operation during the period of time on which 
emissions limits were based), EPA would determine the Phase I emissions 
rate limit as the historic rate adjusted (reduced) to reflect operation 
of the planned control equipment at an emissions rate consistent with 
operation of that equipment. Emissions rate limits would be determined 
based on the assumption that units operate all existing SO2 
and NOX control equipment, and the assumption that the type 
of fuel used does not change from that used in determining the 
unadjusted rate limit.
    For those EGUs which did not report a first, second, third, and 
fourth quarter of SO2, NOX, and/or a complete 
ozone season of NOX emissions data to EPA during the 2007-
2009 period, or for those units located in states where budgets are 
based on IPM projections, EPA would determine emissions rate limits 
based on modeling projections. Based on the analysis conducted for this 
proposed rule, EPA would use modeling projections to determine 
SO2 rates for approximately 1,600 units, annual 
NOX rates for 1,800 units, and ozone season NOX 
rates for 1,900 units. EPA seeks comment on the ability of all such 
units to achieve these limits based on IPM projections. See table 
entitled ``Phase I and Phase II unit-level emission rate limits'' 
located in the ``State Budgets, Unit Allocations, and Unit Emissions 
Rates'' TSD in the docket for this rulemaking.
    For those units that did not report data for a given pollutant and 
time frame combination and also were not included in IPM modeling, EPA 
would need to determine permissible rates based on unit characteristics 
(e.g., types and sizes of units, fuel type). The approach would also 
need to take into account the variety of controls and measures that can 
be used to limit emissions, including available fuels. While EPA does 
not believe that such units exist, EPA is taking comment on the 
existence of units that did not report first, second, third, and fourth 
quarter data to EPA between the first quarter of 2007 and the third 
quarter of 2009, and are not included in IPM modeling. If EPA is made 
aware of such units, the unit-level analysis required to establish such 
limits would be extremely complex, and could impact the ability of EPA 
to require the reductions as quickly as under other remedy approaches.
    EPA is also taking comment on an alternative approach for setting 
emissions rate limits for those units which did not report a first, 
second, third, and fourth quarter of SO2, NOX, 
and/or a complete ozone season of NOX emissions data to EPA 
during the 2007-2009 period. In this alternative approach, EPA could 
develop specific limits that would apply to a large group of units with 
varying characteristics. The numerous variables that contribute to 
differences in units'' emissions rates complicate development of limits 
for a large group of units. Therefore, to ensure that all units in a 
broadly-defined group could achieve their rate limits, it would be 
necessary to either establish limits that are fairly weak so that the 
poorest-performing units could meet the requirements (``lowest-common-
denominator'' effect), or, design more stringent requirements but 
include provisions for exceptions to the requirements. At this time, 
EPA believes using IPM projections and source-specific judgments is 
preferable to the alternative of group-based limits, and seeks comments 
on this alternative.
    Emissions rate limits for Phase II (2014 and onward). For EGUs in 
states that are in SO2 group 1 (i.e., the more stringent 
SO2 group), EPA would further adjust (reduce) SO2 
emissions rates for certain EGUs that EPA projects would install FGD in 
modeling of the proposed remedy option (at less than $2000 per ton); 
for such units EPA would determine emissions rate limits at rates 
consistent with FGD operation. For other covered units, Phase II 
emissions rate limits would be the same as Phase I limits. Again, 
emissions rate limits would be determined based on the assumption that 
units operate all existing SO2 and NOX control 
equipment, and that the type of fuel used does not change from that 
used in determining the unadjusted rate limit. Note that for ozone 
season NOX there is only one phase.
    Emissions rate limits for new units. The emissions rate limits for 
covered new units would be set equal to the permit rates for these 
units.
    EPA has calculated specific emissions rate limits for each existing 
unit that would be covered under this direct control remedy option. 
These unit-level emissions rate limits appear in a table entitled 
``Phase I and Phase II unit-level emissions rate limits'' located in 
the ``State Budgets, Unit Allocations, and Unit Emissions Rates'' TSD 
in the docket for this rulemaking. More detailed description of the 
approach is also provided in the TSD. EPA is requesting comment on this 
approach for determining the emissions rate limits described in the TSD 
and on the limits themselves.
(2) Applicability
    Applicability would be the same for all three remedies. Refer to 
section V.D.4 previously for detailed discussion on applicability.
(3) Monitoring and Reporting
    Monitoring provisions would be the same for all three remedies. The 
direct control option would require minor changes to the reporting and 
record keeping requirements due to the need to collect information on 
both emissions rates and mass. The provisions would require complete, 
accurate measurement and timely reporting of emissions to assure 
accountability and provide public access to data. Refer to section 
V.D.4 previously for detailed discussion on monitoring and reporting 
requirements.
(4) Assurance Provisions
    As discussed previously, starting in 2012, the direct control 
remedy alternative would include assurance provisions designed to 
assure that emissions in each covered state do not exceed the state's 
emissions budget with variability limit. The state's EGU emissions 
would not be permitted to

[[Page 45332]]

exceed the state budget with 1-year variability limit in any year (or 
ozone season, as applicable). Additionally, on a 3-year rolling average 
basis, the state's EGU emissions would not be permitted to exceed the 
budget with the 3-year variability limit (evaluated on an annual or 
ozone season basis, as appropriate). Furthermore, during 2012 and 2013, 
SO2 emissions from EGUs in group 1 states (i.e., the more 
stringent SO2 group) would not be permitted to exceed the 
budget with the state's 2-year variability limit, evaluated as a 2-year 
rolling annual average. Section IV.E in this preamble lists each 
state's emissions budget, and section IV.F lists the 1-, 2-, and 3-year 
variability limits, as applicable.
    Note that for EGUs in states that are in SO2 group 2 
(i.e., the less stringent SO2 group) and/or states required 
to reduce NOX emissions, EPA would apply only the 1-year 
variability limit in 2012 and 2013, and not a 2-year variability limit. 
Because emissions would be evaluated against the 3-year variability 
limit on a 3-year rolling average basis, the application of the 3-year 
variability limit in 2014 would also serve to limit emissions in 2012 
and 2013. For EGUs in SO2 group 1 states (i.e., the more 
stringent SO2 group) EPA would apply a different 1-year 
SO2 variability limit in 2012 and 2013 than for 2014 and 
later. Furthermore, in these group 1 states, EPA would apply a 2-year 
SO2 variability limit in 2012 and 2013, and a 3-year limit 
for later years (section IV.F discusses why variability limits for the 
group 1 states would differ in 2012 and 2013).
    If total EGU emissions in a state exceed either the state's budget 
with 1-year variability limit in any year, or budget with 3-year 
variability limit (or 2-year limit, as appropriate) on average, then 
each company with units in the state whose emissions in the state 
exceeded its share of the state budget with variability limit would be 
subject to a penalty for its share of emissions above the budget with 
variability limit.
    In the State Budgets/Limited Trading remedy described previously, 
the proposed assurance provisions include an allowance surrender 
requirement. Those assurance provisions would require a company to 
surrender one allowance for each ton of the company's proportional 
share of the amount the state's EGU emissions exceed the budget with 
variability limit. This allowance surrender requirement is in addition 
to the trading program requirement to surrender one allowance for every 
ton emitted.
    In the direct control alternative, however, allowances are not 
allocated to units therefore an allowance surrender requirement is not 
feasible. Instead, for this alternative, a company with emissions over 
its share of the budget with variability limit would be in violation of 
the CAA and subject to discretionary penalties. The tonnage amount of 
the company's violation, i.e., the company's excess emissions under the 
assurance provisions, would be its proportional share of the amount 
that the state's EGU emissions exceed the budget with the variability 
limit. Each ton of the company's excess emissions, as well as each day 
in the averaging period, would be a violation.
    In this direct control remedy alternative, a company's share of the 
state budget with variability limit would be determined using the same 
approach described in the State Budgets/Limited Trading option, 
previously. That approach is based on allowance allocations; although 
the direct control remedy would not allocate allowances to sources, 
this remedy would use the allocation method described in State Budgets/
Limited Trading in determining a company's share of the state budget.
    The assurance provisions would commence in 2012 for this direct 
control option. In contrast and for the reasons explained in section 
V.D.4, for the proposed State Budgets/Limited Trading remedy, EPA is 
proposing to start applying the assurance provisions in 2014. The 
combination of circumstances for State Budgets/Limited Trading--known 
locations of controls and a price on each ton emitted--provides greater 
certainty of where reductions will occur during 2012 and 2013 than 
would be provided by the direct control program. In contrast to the 
State Budgets/Limited Trading remedy, the direct control program does 
not put a price on emitting SO2 or NOX so does 
not provide that incentive to reduce emissions. Sources can increase 
generation, while meeting the emissions rate limits, and increase their 
emissions. For these reasons, the direct control program provides less 
certainty regarding the location of emissions in the short term. For 
this reason, EPA believes that it would be appropriate to apply the 
assurance provisions under this remedy option beginning in 2012.
    EPA requests comment on these assurance provisions.
(5) Penalties
    As explained previously, under this direct control remedy approach, 
each owner of EGUs within a covered state would be required to meet 
specified average emissions rate limits for SO2 and/or 
NOX emission for all of its EGUs. For the annual 
SO2 or NOX control programs, if a company were to 
exceed the applicable company-wide annual average rate limit, the 
company would be in violation of the CAA and subject to discretionary 
civil penalties.
    The excess emissions of the owner's EGUs would be calculated as the 
EGUs'' actual annual average emissions rate minus the applicable annual 
average emissions rate limit, with the difference multiplied by the 
EGUs'' total actual annual heat input. Each ton of excess emissions, as 
well as each day in the averaging period (e.g., 365 days for an annual 
program), would be a violation of the CAA. The maximum discretionary 
penalty under CAA Section 113 is $25,000 (inflation-adjusted to $37,500 
for 2009) per violation.
    For the ozone season NOX program, the penalty provisions 
would work in the same manner described herein except on an ozone 
season basis rather than annual.
    In addition, any company with EGU emissions exceeding its share of 
the state budget with variability limit for SO2, 
NOX annual or NOX ozone season would also be in 
violation of the CAA and subject to discretionary civil penalties 
explained earlier in this section if, in any year (or ozone season, as 
applicable), the state as a whole exceeds its budget with variability 
limit (see description of assurance provisions, previously).
    EPA requests comment on the penalty provisions.
c. How the Direct Control Remedy Is Consistent With the Court's 
Opinions
    The direct control remedy option would implement the section 
110(a)(2)(D)(i)(I) requirement that ``emissions from sources that 
contribute significantly and interfere with maintenance in downwind 
nonattainment areas'' be prohibited. It would do so by establishing for 
covered EGUs specific emissions rate limits, with company-wide within 
state averaging. Emissions rates in all states would be set on a unit-
by-unit basis at levels such that, if the units operated at the levels 
assumed in determining the state budgets, total emissions from these 
units would sum to each state's emissions budgets without the 
variability limits. A company could average the emissions at its units 
within each state to meet specified within-the-state rate limits. This 
approach would directly limit emissions from EGUs in each covered 
state, providing assurance that emissions reductions would occur within 
each state consistent with the mandate of section 110(a)(2)(D)(i)(I).

[[Page 45333]]

    Because individual EGUs would be required to meet specific 
emissions rate limits (with within-state company-wide averaging), this 
option would ensure that required controls and measures are installed 
and implemented within the state. The fact that emissions, after 
implementation of all controls required to meet the emissions rate 
limits, may vary based on the amount of generation in each state is not 
inconsistent with the section 110(a)(2)(D)(i)(I) requirement that all 
significant contribution and interference with maintenance be 
eliminated. As noted previously, changes in generation due to changing 
meteorology, demand growth, or disruptions in electricity supply from 
other units can all affect the amount of generation needed in a 
specific state and thus the baseline emissions from that state. Because 
baseline emissions are variable, emissions after the elimination of all 
significant contribution are also somewhat variable.
    Further, any such variation in emissions would be limited. As with 
the State Budgets/Limited Trading option described previously, no 
state's EGU emissions would be permitted to exceed the state budget 
with variability limit in any year (or ozone season, as applicable). 
Nor would any state's EGU emissions be permitted, on average, to exceed 
the budget plus a specified portion of the state's variability limit, 
evaluated as a 3-year rolling annual (or ozone season) average (or, in 
SO2 group 1 states during 2012-2013, a 2-year rolling annual 
average). Section IV in this preamble lists each state's emissions 
budget, and 1-, 2-, and 3-year variability limit, as applicable.
d. Electric Reliability Issues
    The risk to electric reliability is considered low under the direct 
control remedy option. Specifically, the provisions for the variability 
limits and company averaging within each state help to alleviate 
electric reliability concerns. Therefore, EGUs are expected to be able 
to both comply with their emissions rate limits and reliably provide 
electricity to customers. EPA requests comment on electric reliability 
issues.
e. Why This Is Not the Preferred Option
    As explained previously, EPA is requesting comment on the merits 
and weaknesses of this direct control remedy option. EPA did not 
include this remedy option in the proposed FIPs; however, we continue 
to consider this option and are taking comment on whether this option 
should be included in the FIPs. This option would provide assurance 
that companies in each state are meeting specific emissions rate limits 
and would also ensure that annual emissions from each state are capped. 
Additionally, the direct control option may be perceived as easy to 
understand and follow. Nonetheless, at this time, EPA believes the 
direct control option is inferior to the preferred approach. EPA 
requests comments on the validity of EPA's concerns regarding this 
option and alternative methods for addressing those concerns.
    EPA modeling projects fewer emissions reductions under the direct 
control alternative than the proposed State Budgets/Limited Trading 
remedy. Additionally, the reductions would be achieved at a higher cost 
than the proposed remedy. See section V.E. for projected costs and 
emissions.
    A direct control program must account for outliers, e.g., units 
that can not install controls due to space limitations. EPA believes 
that the within-the-state company-wide averaging in the direct control 
alternative on which EPA is taking comment likely mitigates this 
concern. However, this averaging approach may put an owner with a small 
number of units within a state at a disadvantage compared to an owner 
with a larger number of units. EPA requests comment on this issue.
    Within the direct control approach on which EPA is taking comment, 
the assurance provisions (which limit a company's emissions within a 
state to its share of the budget with the variability limit if the 
state's budget with variability limit is exceeded) may also put an 
owner with a small number of units at a disadvantage compared to an 
owner with a larger number of units within a state. EPA seeks comment 
on this issue.
    A direct control program based on emissions rate limits does not 
cap annual emissions; if there is growth in fossil generation within a 
state, a rate-based approach alone could allow emissions increases. In 
the direct control approach on which EPA requests comment, the 
assurance provisions provide some assurance of achieving required 
reductions.
    Notably, the direct control approach described herein restricts 
compliance options more than a trading approach. EPA generally believes 
that granting more flexibility to companies in meeting an emissions 
reductions goal results in the ability of those companies to meet that 
goal at a lower cost and decreases reliability risks in the electric 
power system. While some portion of this effect is captured in IPM 
modeling (see section V.E. for projected costs and emissions), some 
types of unforeseen innovations in technology, fuel switching, and 
management cannot be captured by modeling. Any potential innovations 
and resulting cost savings are more likely to be found and utilized in 
the presence of regulatory flexibility. Based on historical experience, 
EPA believes that the benefits offered by a flexible trading approach 
are large and should be considered qualitatively, even if they cannot 
be quantified. Many of these benefits would be foregone under the 
direct control approach.

E. Projected Costs and Emissions for Each Remedy Option

    Emission and cost projections for the three remedies discussed 
previously come from the Integrated Planning Model (IPM), a dynamic 
linear programming model of electric generation in the contiguous U.S. 
For each remedy, projected costs relative to the base case appear in 
Table V.E-1. The following section explains these projections in light 
of how the remedies differ and how they were represented in the model. 
The emissions projections below comprise fossil generation above 25 
megawatts of capacity, the units that would be subject to the rule. 
More detail on the modeling of costs and emissions can be found in the 
Regulatory Impact Analysis for the proposed Transport Rule and in the 
IPM Documentation.

 Table V.E-1--Projected Incremental Costs Due to Transport Rule Remedies
           Compared to Baseline Without Transport Rule or CAIR
                         [Billion 2006 dollars]
------------------------------------------------------------------------
                                           2012    2014    2020    2025
------------------------------------------------------------------------
Limited Interstate Trading (proposed)...     3.7     2.8     2.0     2.0
Intrastate Trading......................     4.2     2.7     2.2     2.2
Direct Control..........................     4.3     3.4     2.5     2.3
------------------------------------------------------------------------


[[Page 45334]]

1. State Budgets/Limited Trading
    The proposed remedy of State Budgets/Limited Trading was modeled 
with regional emissions caps beginning in 2012 and state-specific 
emissions limits beginning in 2014. The state-specific emissions limits 
represent state budgets plus 3-year average variability limits. Because 
banking early reductions beyond the budget levels is allowed, 2012 
SO2 reductions are greater overall than state budgets alone 
would require in that year. Table V.E-2 shows the projected emissions 
reductions from this remedy.

 Table V.E-2--Projected SO2 and NOX Electric Generating Unit Emissions Reductions in Covered States With the Transport Rule Compared to Baseline Without
                                                                 Transport Rule or CAIR
                                                                     [Million tons]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                               2012 base case    2012 transport    2012 emissions    2014 base case    2014 transport    2014 emissions
                                                  emissions      rule emissions      reductions         emissions      rule emissions      reductions
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO2.........................................               8.4               3.4               5.0               7.2               2.6               4.6
Annual NOX..................................               2.0               1.3               0.7               2.0               1.3               0.7
Ozone Season NOX............................               0.7               0.6               0.1               0.7               0.6               0.1
--------------------------------------------------------------------------------------------------------------------------------------------------------

2. State Budgets/Intrastate Trading
    Though based on the same state budgets as State Budgets/Limited 
trading, the alternative remedy of State Budgets/Intrastate Trading 
costs approximately 0.5 billion 2006 dollars more in 2012 and achieves 
slightly more SO2 reduction in 2012 (and slightly less in 
2014), as Table V.E-3 shows. In modeling this remedy, each state's 
emissions were restricted to the state budget without variability. 
Without the opportunity for even limited trading of allowances across 
state borders, more banking was projected in some states. In other 
states, more immediate emissions reductions (relative to the base case) 
are projected so that state budgets are met exactly. Both of these 
factors drive 2012 costs higher than those of limited interstate 
trading and lead to slightly greater SO2 reductions in 2012.

    Table V.E-3--Projected SO2 and NOX Electric Generating Unit Emissions Reductions in Covered States With the Intrastate Trading Alternative Remedy
                                                   Compared to Baseline Without Transport Rule or CAIR
                                                                     [Million tons]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                               2012 base case    2012 transport    2012 emissions    2014 base case    2014 transport    2014 emissions
                                                  emissions      rule emissions      reductions         emissions      rule emissions      reductions
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO2.........................................               8.4               3.2               5.2               7.2               2.7               4.5
Annual NOX..................................               2.0               1.3               0.7               2.0               1.2               0.8
Ozone Season NOX............................               0.7               0.6               0.1               0.7               0.6               0.1
--------------------------------------------------------------------------------------------------------------------------------------------------------

3. Direct Control
    The direct control alternative remedy consists of source-specific 
emissions rate limits commensurate with those used in the derivation of 
state budgets (see sections IV.D and IV.E). To represent assurance 
provisions, the emissions from each state were also constrained to the 
state's budget plus 3-year average variability limit beginning in 2012. 
For states with more stringent SO2 budgets in 2014, FGD 
retrofits were required on units shown to have cost-effective retrofit 
opportunities at $2,000 per ton.
    Compared to the proposed remedy of State Budgets/Limited Trading, 
the direct control alternative costs approximately 0.6 billion 2006 
dollars more and results in less SO2 reduction in 2012, as 
shown in Table V.E-4. Unlike remedies allowing banking for early 
reductions, the direct control alternative does not result in 
reductions below state budgets in 2012. At the same time, meeting 
specific rate requirements for every source means there is little 
incentive to achieve additional reductions with fuel switching.

 Table V.E-4--Projected SO2 and NOX Electric Generating Unit Emissions Reductions in Covered States With the Direct Control Alternative Remedy Compared
                                                       to Baseline Without Transport Rule or CAIR
                                                                     [Million tons]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                               2012 base case    2012 transport    2012 emissions    2014 base case    2014 transport    2014 emissions
                                                  emissions      rule emissions      reductions         emissions      rule emissions      reductions
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO2.........................................               8.4               3.8               4.6               7.2               2.6               4.6
Annual NOX..................................               2.0               1.3               0.7               2.0               1.2               0.8
Ozone Season NOX............................               0.7               0.6               0.1               0.7               0.6               0.1
--------------------------------------------------------------------------------------------------------------------------------------------------------


[[Page 45335]]

4. State-Level Emissions Projections
    Tables V.E-5, V.E-6, and V.E-7 show projected emissions at the 
state level from all EGUs in 2014.
---------------------------------------------------------------------------

    \105\ The modeling presented in Tables V.E-5, V.E-6, and V.E-7 
differs from the proposed Transport Rule because the District of 
Columbia (DC) is included neither in the annual SO2 and 
NOX requirements nor in the ozone season NOX 
requirement. Modeled units in DC include two small facilities, one 
of which has only units below 25 MW capacity. EPA believes the 
addition of emissions limits in DC would have little to no effect on 
the modeling results.

          Table V.E-5--Projected State-level \105\ SO2 Emissions From Electric Generating Units in 2014
                                                     [Tons]
----------------------------------------------------------------------------------------------------------------
                                                                               State budgets/
                                              Base case      State budgets/      intrastate      Direct control
                                                             limited trading       trading
----------------------------------------------------------------------------------------------------------------
Alabama.................................           322,362           172,430           162,103           172,430
Connecticut.............................             6,160             3,234             3,208             3,208
Delaware................................             8,079             9,185             8,974             9,110
District of Columbia....................               176               179               180               180
Florida.................................           194,723           139,805           159,120           135,366
Georgia.................................           173,257            92,375            89,706            92,375
Illinois................................           200,484           164,741           156,049           163,902
Indiana.................................           804,425           240,730           267,564           239,852
Iowa....................................           163,966           102,419           102,096           106,569
Kansas..................................            65,125            51,248            52,501            53,275
Kentucky................................           739,595           123,837           128,318           123,833
Louisiana...............................            94,866            94,933            92,647            96,390
Maryland................................            45,294            45,449            45,304            45,752
Massachusetts...........................            17,265            10,306             8,595             8,909
Michigan................................           275,961           173,828           188,796           172,986
Minnesota...............................            62,033            49,413            49,836            58,925
Missouri................................           500,649           192,645           190,815           190,532
Nebraska................................           115,695            75,095            73,219            75,061
New Jersey..............................            39,721            16,562            14,935            16,569
New York................................           142,762            58,455            53,373            58,455
North Carolina..........................           140,924            97,262           109,385            97,262
Ohio....................................           841,199           232,964           269,547           228,514
Pennsylvania............................           974,644           154,852           183,276           154,855
South Carolina..........................           156,200           131,232           123,525           131,232
Tennessee...............................           600,071           106,767           100,012            94,078
Virginia................................           136,573            58,329            51,633            58,330
West Virginia...........................           496,307           127,646           147,580           127,646
Wisconsin...............................           117,397            85,933            87,328            83,709
----------------------------------------------------------------------------------------------------------------


         Table V.E-6--Projected State-Level Annual NOX Emissions From Electric Generating Units in 2014
                                                     [Tons]
----------------------------------------------------------------------------------------------------------------
                                                                               State budgets/
                                              Base case      State budgets/      intrastate      Direct control
                                                             limited trading       trading
----------------------------------------------------------------------------------------------------------------
Alabama.................................           118,955            61,793            61,618            61,865
Connecticut.............................             7,991             8,003             7,986             8,004
Delaware................................             5,790             6,176             6,126             6,074
District of Columbia....................               933               946               948               948
Florida.................................           196,373           126,155           126,065            94,646
Georgia.................................            48,267            44,461            44,462            44,611
Illinois................................            80,451            57,589            54,773            57,949
Indiana.................................           201,027           112,502           112,721           108,675
Iowa....................................            68,259            53,072            50,146            52,069
Kansas..................................            79,018            40,020            40,074            39,558
Kentucky................................           148,551            71,371            71,692            69,882
Louisiana...............................            45,551            37,255            36,594            37,164
Maryland................................            36,089            36,326            33,778            36,532
Massachusetts...........................            12,650            13,047            12,219            13,064
Michigan................................            98,941            65,066            65,973            67,525
Minnesota...............................            55,283            38,969            39,114            38,039
Missouri................................            83,019            67,475            61,679            67,648
Nebraska................................            53,029            35,101            34,105            35,457
New Jersey..............................            27,127            23,377            23,358            23,338
New York................................            36,352            36,592            34,538            36,597
North Carolina..........................            62,608            60,516            54,639            60,517
Ohio....................................           164,947            99,358            95,997           100,886
Pennsylvania............................           204,950           123,629           123,095           123,409

[[Page 45336]]


South Carolina..........................            47,742            34,735            33,781            34,616
Tennessee...............................            68,914            28,212            26,874            28,873
Virginia................................            37,485            35,805            35,745            37,004
West Virginia...........................           100,095            48,180            48,987            50,555
Wisconsin...............................            54,515            41,875            42,498            42,450
----------------------------------------------------------------------------------------------------------------


      Table V.E-7--Projected State-Level Ozone-Season NOX Emissions From Electric Generating Units in 2014
                                                     [Tons]
----------------------------------------------------------------------------------------------------------------
                                                                               State budgets/
                                              Base case      State budgets/      intrastate      Direct control
                                                             limited trading       trading
----------------------------------------------------------------------------------------------------------------
Alabama.................................            26,995            26,727            26,552            26,823
Arkansas................................            21,667            12,080            12,095            12,077
Connecticut.............................             3,446             3,453             3,446             3,446
Delaware................................             2,367             2,669             2,671             2,613
District of Columbia....................               391               397               397               398
Florida.................................            94,686            62,221            62,037            48,170
Georgia.................................            21,947            19,686            19,688            19,749
Illinois................................            24,167            24,930            22,833            24,701
Indiana.................................            49,023            47,477            47,813            45,589
Kansas..................................            34,537            17,470            17,590            17,282
Kentucky................................            29,927            29,376            29,671            29,107
Louisiana...............................            21,443            17,388            17,106            17,308
Maryland................................            15,307            15,454            14,275            15,512
Michigan................................            29,934            27,778            28,052            29,415
Mississippi.............................            16,955             8,524             8,526             8,522
New Jersey..............................            10,470            10,324            10,295            10,260
New York................................            17,257            17,493            16,518            17,491
North Carolina..........................            27,018            26,117            23,459            26,004
Ohio....................................            44,753            41,141            40,051            42,789
Oklahoma................................            38,546            24,471            24,471            24,426
Pennsylvania............................            53,263            53,102            52,692            52,586
South Carolina..........................            15,730            14,818            14,666            14,753
Tennessee...............................            12,021            11,868            10,955            12,007
Texas...................................            79,572            68,769            68,874            67,832
Virginia................................            16,264            15,397            15,289            16,093
West Virginia...........................            24,339            20,249            21,466            21,500
----------------------------------------------------------------------------------------------------------------

F. Transition From the CAIR Cap and Trade Programs To Proposed Programs

    This proposed Transport Rule would replace the CAIR rule and its 
associated trading programs. This section elaborates on some of the 
areas of the CAIR program that would need to be addressed in the 
transition to the new program. EPA is taking comment on how the 
transition would occur.
1. Sunsetting of CAIR, CAIR SIPs, and CAIR FIPs
    The CAIR, CAIR SIPs, and CAIR FIPs would be replaced entirely by 
the Transport Rule provisions. If this proposed Transport Rule is 
finalized in 2011, the CAIR, CAIR SIPs, and CAIR FIPs would sunset at 
the completion of all 2011 control period activities.
    In order to implement the sunsetting of the CAIR and CAIR FIPs, the 
proposed rule includes several revisions of the CAIR, Sec. Sec.  51.123 
and 51.124, and the CAIR FIPs, Sec. Sec.  52.35 and 52.36. First, 
sunsetting the CAIR and CAIR FIPs in 2011 would mean that the 
requirements of the CAIR and CAIR FIPs would not apply to control 
periods after 2011. Specifically, the CAIR would be revised to rescind, 
with regard to any control period beginning after December 31, 2011, 
the findings that states must revise their SIPs to meet CAIR 
requirements. Similarly, the CAIR FIPs would be revised to state that, 
with regard to any post-December 31, 2011 control period, CAIR FIP 
requirements would not be applicable.
    Second, the sunsetting in 2011 would mean that the CAIR trading 
programs would not continue past 2011. Consequently, the proposed 
revisions of the CAIR and CAIR FIPs would state that, with regard to 
any post-December 31, 2011 control period, 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 the CAIR.
    Third, the sunsetting in 2011 would mean that CAIR allowances 
allocated for control periods after 2011--which have already been 
recorded by the Administrator in the Allowance Management System 
compliance accounts of sources in many states--would not be usable in 
the CAIR trading programs for control periods ending before 2012. 
Specifically, under the existing CAIR trading programs, a source that 
fails to hold sufficient allowances to cover emissions for the 2011 
control period (whether annual or ozone season) must provide for 
surrender to the Administrator three allowances (one as an offset and 
two as an automatic penalty) allocated for the 2012 control period for 
every one

[[Page 45337]]

allowance that was not held as required. However, consistent with the 
proposed termination of the CAIR trading programs for control periods 
after 2011, EPA believes that allowances allocated for such control 
periods (e.g., 2012 allowances) should not be usable for any purpose. 
In any event, because such allowances would have little or no market 
value, their deduction would impose little or no cost on the party 
holding them. Consequently, the proposed revisions of the CAIR and CAIR 
FIPs would state that the Administrator would not deduct, for excess 
emissions, any CAIR allowances allocated for control periods in 2012 or 
any year thereafter. These revisions would ensure that no CAIR 
allowances allocated for post-2011 control periods would be used as an 
offset of, or an automatic penalty for, excess emissions.
    As a result of these proposed revisions of the CAIR and CAIR FIP 
rules, there would be no offset or automatic penalty deducted for a 
source that failed to hold sufficient allowances to cover its 2011 
control period emissions unless the state SIPs are revised. In order to 
preserve the deductions for offsets and automatic penalties for 2011 
control periods, the CAIR SIPs for most states (i.e., 20 out of the 28 
states subject to at least one CAIR trading program) would need to be 
modified and the modified CAIR SIPs would need to be approved by the 
EPA ---before EPA conducts the process of determining source compliance 
after the allowance transfer deadline for the 2011 control periods --in 
order to change the allocation year of the allowances required to be 
deducted (e.g., from allowances allocated for 2012 to allowances 
allocated for 2011). Although EPA's past experience with trading 
programs strongly suggests that few sources would be out of compliance 
with the requirement to hold allowances covering 2011 emissions, all of 
these CAIR SIPs would have to be revised because there is no way to 
predict which few sources in which few states might be out of 
compliance in 2011 and the process of revising SIPs is too long to be 
started while EPA is still determining compliance. In fact, when states 
needed to revise their SIPs to include the existing requirements of 
CAIR and submit the revised SIPS to the Administrator, EPA found that 
states needed up to 3 years to develop and submit SIP revisions, and 
EPA needed about 6 months to act on the SIP revisions. In light of this 
experience with SIP revisions under CAIR, EPA believes that it would 
highly unlikely that all, or even most, state CAIR SIPs could be 
revised, submitted, and approved in time--even if the SIP revision 
process were started when a final Transport Rule is promulgated--to 
change what allowances were to be used for offsets and automatic 
penalties for excess emissions for the 2011 control periods.
    Moreover, any excess emissions for the 2011 control periods would 
be violations of the state SIPs (or of CAIR FIPs in those states with 
CAIR FIPs) and of the Clean Air Act and, therefore would be subject to 
discretionary civil penalties under CAA Section 113. Each ton of excess 
emissions, and each day in the control period involved (i.e., 365 days 
for annual control periods and 153 days for the ozone season control 
period), would be a violation, with a maximum penalty of $25,000 
(inflation adjusted to $37,500) per violation. In determining what 
level of discretionary civil penalties to impose on a source that has 
excess emissions violations, EPA routinely considers, among other 
things, whether, and if so what level of, other penalties (e.g., 
automatic excess emissions penalties) have already been imposed for the 
same violations, as well as any economic benefit of noncompliance 
(e.g., the avoidance of the cost of surrendering allowances to cover 
emissions). See, e.g., 42 U.S.C. 7413(e)(1) (including, as penalty 
assessment criteria, ``payment by the violator of penalties previously 
assessed for the same violation'' and ``the economic benefit of 
noncompliance''). Consequently, EPA believes that, regarding the CAIR 
2011 control periods (both annual and ozone season) for which it is not 
feasible to change the offset and automatic penalty provisions to make 
them workable, the potential for assessment of significant, 
discretionary civil penalties would provide a strong incentive for 
compliance with the allowance-holding requirement and avoidance of 
excess emissions.
    In addition to the previously-described, proposed revisions to 
Sec. Sec.  51.123, 51.124, 52.35, and 52.36, certain provisions in part 
52 that reflect, state by state, the CAIR SIP revisions and CAIR FIP 
requirements applicable to each state would need to be revised to 
implement the sunsetting of the CAIR, CAIR SIPs, and CAIR FIPs. 
However, the timing for proposal and adoption of revisions to part 52 
is necessarily different for the part 52 provisions addressing CAIR SIP 
revisions and those addressing revisions of the CAIR and the CAIR FIPs 
themselves.
    The part 52 provisions addressing CAIR SIP revisions for the 
individual states reflect EPA's approval of CAIR SIP revisions adopted 
and submitted to EPA by the respective states. The first step toward 
sunsetting those part 52 provisions would be that, if and after the 
proposed Transport Rule was finalized, the respective states would 
change their SIPs in order to, among other things, make the CAIR 
provisions in the SIPs inapplicable to any control period that starts 
after December 31, 2011. After the submittal by the respective states 
of these SIP revisions, EPA would review and approve such changes. 
Consequently, the rule text approving such CAIR SIP revisions would not 
be included in either the proposed Transport Rule or any final rule 
based on the proposed Transport Rule, but rather would be proposed and 
adopted only after the respective states revised their SIPs. As EPA did 
when transitioning from the NOX Budget Trading Program to 
the CAIR NOX ozone season trading program, EPA will work 
with states to transition from state CAIR programs to their replacement 
FIPs or state SIPs. This assistance will be provided through meetings 
or workshops, web-based references, one-on-one assistance through the 
EPA regions, etc.
    In contrast, the part 52 provisions adopting CAIR FIPs for 
individual states could be revised, as part of the proposed Transport 
Rule, to sunset these CAIR FIPs because no state action would be 
required to accomplish this sunsetting. EPA proposes to revise each 
state-specific part 52 provision adopting a CAIR FIP--whether for 
NOX annual or ozone season emissions or SO2 
emissions--to add a paragraph stating that: with regard to any control 
period starting after December 31, 2011, the respective CAIR FIP would 
not apply and the Administrator would not carry out any of the 
functions set forth for the Administrator in the trading program rules 
under the CAIR FIP; and the Administrator would not deduct for excess 
emissions any CAIR allowances allocated for 2012 or any year 
thereafter. The new, added rule text would be very similar to the 
proposed rule text revisions to Sec. Sec.  52.35 and 52.36 and would be 
essentially the same for each of these state-specific Part 52 
provisions. EPA has included in the proposed Transport Rule the 
proposed rule text making these state-by-state revisions for Delaware, 
District of Columbia, Indiana, Louisiana, Michigan, New Jersey, 
Tennessee, Texas, and Wisconsin. These provisions revise all of the 
state-specific Part 52 provisions adopting CAIR FIPs provisions to make 
the CAIR FIPs inapplicable to any control period that

[[Page 45338]]

starts after December 31, 2011 and state that the Administrator would 
not carry out any functions under the CAIR trading programs during any 
such control period and would not use any CAIR allowances allocated for 
any such control period.
2. Change in States Covered
    The states covered by the proposed Transport Rule differ slightly 
from states covered by the CAIR. Namely, as compared with the states 
covered by the CAIR NOX ozone season trading program, the 
states covered by the proposed Transport Rule NOX ozone 
season trading program would include Georgia, Kansas, Oklahoma, and 
Texas and would not include Iowa, Massachusetts, Missouri, and 
Wisconsin. Further, as compared with the states covered by the CAIR 
NOX annual and SO2 trading programs, the states 
covered by the proposed Transport Rule NOX Annual and 
SO2 trading programs would include Connecticut, Kansas, 
Massachusetts, Minnesota, and Nebraska and would not include 
Mississippi and Texas. (See also the discussion in section IV.D. 
regarding the possibility that the states to which this rule would 
apply could expand.)
    Consequently, sources in some states that would be covered by the 
proposed Transport Rule would have new allowance holding requirements 
beginning in 2012, but would not have been subject to the CAIR trading 
programs. Conversely, sources in some states covered by the CAIR or 
CAIR FIPs would not be subject to the proposed Transport Rule. To the 
extent that the 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 will work with individual 
states to identify state-specific options to ensure that necessary 
reductions needed for other SIP requirements can continue.
3. Applicability, CAIR Opt-ins and NOX SIP Call Units
    Except for the changes in the states covered, the general 
applicability provisions of the proposed Transport Rule would be 
essentially the same as the CAIR general applicability provisions, with 
a few exceptions. First, the proposed Transport Rule does not allow any 
units to opt into the trading programs. In contrast, under CAIR, 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, and a number of states adopted these opt-in 
provisions. However, currently no units have opted into the CAIR 
trading programs, and, even in the Acid Rain Program, where opt-in 
provisions have been in place since 1995, very few units have actually 
opted in.
    Second, under the CAIR trading programs, a state subject to the 
NOX SIP Call was allowed to expand the applicability of the 
CAIR NOX ozone season trading program in the state in order 
to include all units subject to the NOX Budget Trading 
Program (NBP) 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 NOX ozone season 
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. In expanding the applicability of the CAIR 
NOX ozone season trading program, the fourteen states 
brought into the program large industrial boilers and turbines (with 
maximum design heat input greater than 250 mmBtu/ hr) and, in some 
cases, smaller electric generating units (serving generators with 
nameplate capacity of 15 through 25 MWe), and generally the CAIR 
NOX ozone season budgets in these states were increased to 
account for these additional sources. In contrast, the proposed 
Transport Rule NOX ozone season trading program would not 
allow for expansion of applicability to include these units currently 
covered only by the NBP.
    There are several factors underlying this difference between the 
proposed Transport Rule and the CAIR. First, in determining which 
states are contributing significantly or interfering with maintenance 
of the ozone NAAQS, the Transport Rule does not cover some states 
subject to the NOX SIP Call (i.e., Massachusetts, Missouri, 
and Rhode Island). Further, the six states that chose under the CAIR to 
require the necessary NOX SIP Call reductions through 
provisions other than the CAIR NOX ozone season program 
would not likely be interested in expanding applicability under the 
Transport Rule NOX ozone season trading program to cover 
these units. In addition, EPA has determined that these units as a 
group did not actually reduce emissions as a result of the NBP or 
through their inclusion in the CAIR NOX ozone season trading 
program. In fact, their current emissions rates are nearly identical to 
what they were before the NBP started. Moreover, these units as a group 
had allowances that they did not need for compliance and that were 
available for trading to other affected units. The Transport Rule, as 
proposed, does not include these units and does not include provisions 
for allowing states expand applicability to include them. EPA is taking 
comment on this approach.
4. Early Reduction Provisions
    Substantial emissions reductions have occurred as a result of the 
CAIR programs. These reductions are greater than were expected when the 
rule was promulgated. This is evidenced in the banks of allowances that 
exist in each of the CAIR programs.
a. 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 emissions reductions for 
Title IV where allowances are used for compliance with the requirement 
to hold allowances covering emissions and early reductions for the CAIR 
SO2 trading program. EPA believes that it is advantageous to 
minimize sources'' use of the Title IV allowance bank if possible and 
recognizes that, if the bank has minimal future market value, there may 
be incentive to use as many banked allowances as possible. EPA tracks 
the SO2 emissions on a quarterly basis and makes the 
information available to the public at http://epa.gov/airmarkets/
quarterlytracking.html.
    EPA evaluated whether the Title IV allowance bank could be used in 
the proposed Transport Rule SO2 program in any way. One idea 
presented to EPA was to distribute Transport Rule SO2 
allowances based on the number of Title IV allowances a source has in 
its bank at the completion of compliance in the last year of the CAIR 
SO2 program, thereby incentivizing minimal use, by sources, 
of Title IV allowance banks and encouraging continued emission control. 
EPA is concerned that the approach would have significant legal risk 
for two reasons. First, the Court is likely to view the approach as 
imposing a significant burden on the use of Title IV allowances and 
therefore as modifying the authorization provided by such allowances. 
Second, the Court is likely to view the approach as not related to, 
much less necessary for, implementation of the section 
110(a)(2)(D)(i)(I) mandate to eliminate significant contribution and 
interference with maintenance. EPA chose instead, under the proposed 
Transport Rule, to distribute Transport Rule SO2 allowances 
in a manner directly linked to its calculation of each state's 
significant contribution and interference with maintenance and not to 
use Title IV allowances as a basis for distributing the new Transport 
Rule allowances. EPA is confident that the approach

[[Page 45339]]

selected is consistent with the Court's opinion in North Carolina v. 
EPA, 531 F.3d 896, 922 (D.C. Cir. 2008). (Additional information on 
this approach can be found in the docket.) EPA requests comment on 
whether or not an allowance distribution approach based on the number 
of Title IV allowances in a given source's account would be consistent 
with the Court opinion.
    EPA proposes that the Transport Rule provisions 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. Thus, there would be no SO2 
allowances carried over into the new SO2 program. Title IV 
allowances continue, of course, to be used for compliance with the Acid 
Rain Program.
b. NOX Allowance Banks
    Assuming that NOX emissions in 2010 and 2011 are equal 
to what they were in 2009, the CAIR NOX ozone season bank 
would contain over 600,000 allowances (which would equal more than 100 
percent of the total of the state budgets under the proposed Transport 
Rule NOX ozone season program for 2012), and the CAIR 
NOX annual bank would contain about 720,000 allowances 
(which would equal nearly 50 percent of the total of the state budgets 
under the proposed Transport Rule NOX annual program for 
2012), after completion of true-up of allowance holdings and emissions 
for 2011. Estimates of the size of the banks have only recently been 
made based on reported 2009 emissions data, and the impacts of 
different approaches to handling the banks have not yet been modeled. 
However, EPA is concerned about the potential impacts of these 
approaches. On one hand, allowing pre-2012 CAIR NOX 
allowances and CAIR NOX ozone season allowances to be used 
in the proposed Transport Rule NOX programs, and thereby 
ensuring that the allowances would continue to have some market value 
in the future, would promote the continuation--in 2010 and 2011--of the 
reductions that occurred in 2009 under the CAIR NOX 
programs. On the other hand, the amounts of the banks are so large that 
they might significantly reduce the amount of emissions reductions that 
would otherwise be achieved in the proposed Transport Rule 
NOX programs, particularly in the earlier years (e.g., 2012 
and 2013).
    EPA has identified several possible approaches for handling banked 
pre-2012 CAIR NOX allowances in the Transport Rule 
NOX programs. The first approach might be to 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 the significant contribution 
and interference with maintenance that EPA has identified in today's 
proposal. The banked CAIR allowances would be usable, and the assurance 
provisions would apply, in all states in the Transport Rule 
NOX programs. However, EPA is concerned that some parties 
may view this approach as having the effect of allowing sources that 
were advantaged by the development of state budgets using fuel 
adjustment factors--the use of which was reversed by the Court in North 
Carolina, 531 F.3d at 918-21--and that still hold part of their 
allocated allowances to continue have an advantage in the Transport 
Rule NOX trading programs. These concerns may be mitigated 
somewhat by the fact that even though the methodology used to divide 
the regional budget into state budgets used fuel factors, states had 
the flexibility to allocate allowances however they wished. EPA takes 
comment on the extent to which states have allocated differently and 
the extent to which this may mitigate concerns about allowing the use 
of banked CAIR NOX allowances in the Transport Rule annual 
NOX and ozone season NOX trading programs.
    The second approach might be to allow only a limited amount of 
banked pre-2012 CAIR allowances to be brought into the Transport Rule 
programs. This could be accomplished by allowing all such banked 
allowances to be used, but at a tonnage authorization level 
significantly lower than one ton per allowance, in the Transport Rule 
NOX programs. However, while severely limiting the tonnage 
authorization of banked allowances that is allowed into the new 
programs would limit any advantage realized by sources that received 
fuel-adjustment-factor-based CAIR allowance allocations, this would 
also limit any beneficial impact that bringing CAIR allowances into the 
new programs might have on preserving emissions reductions in 2010 and 
2011.
    The third option might be to try to factor the bank into the 
calculation of state budgets by reducing the state budgets to take 
account of the banked pre-2012 CAIR allowances. This might allow these 
allowances to be used in the Transport Rule NOX programs 
without adversely affecting the states' elimination of the part of 
significant contribution and interference with maintenance that EPA has 
identified. However, this approach would not be feasible because EPA 
cannot determine in advance in which states banked pre-2012 CAIR 
allowances might be used and so would not know which state budgets 
should be adjusted and what amount of adjustment would be necessary.
    A final approach would simply be to not allow the use of any banked 
pre-2012 CAIR allowances in the Transport Rule NOX programs. 
This approach would avoid the potential legal and practical problems 
raised by the other approaches and is the approach proposed by EPA. EPA 
requests comment on the proposed approach, the previously-discussed 
alternative approaches, and any other possible approaches for handling 
banked pre-2012 CAIR allowances in the Transport Rule NOX 
programs.
5. Source Monitoring and Reporting
    Monitoring and reporting using 40 CFR part 75 provisions is 
required for all units subject to the CAIR programs and would also be 
required for all units subject to the proposed Transport Rule programs. 
In states covered by both the CAIR and the proposed Transport Rule, 
units would generally have no changes to their monitoring and reporting 
requirements and would continue to monitor and submit reports as they 
have under the CAIR. The exceptions are units in: CAIR states subject 
to CAIR NOX ozone season requirements but NOX and 
SO2 annual requirements under the proposed Transport Rule; 
or CAIR states subject to CAIR NOX annual and ozone season 
and SO2 requirements but only to NOX ozone season 
requirements under the proposed Transport Rule. These exceptions could 
arise, in part, because under Part 75 some units (i.e., non-Acid Rain 
units) that are in NOX ozone season, and not NOX 
annual, programs have the option of monitoring and reporting 
NOX emissions for just the ozone season.
    Units in the following states monitor and report both 
SO2 and NOX year-round under the CAIR and would 
continue to do so under the Transport Rule: Alabama, Delaware, the 
District of Columbia, Florida, Georgia, Illinois, Indiana, Iowa, 
Kentucky, Louisiana, Maryland, Michigan, Missouri, New Jersey, New 
York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, 
Virginia, West Virginia, and Wisconsin. Non-Acid Rain units in Arkansas 
are currently required to monitor and report NOX in the 
ozone season under the CAIR and would continue to be required to do so 
under the proposed Transport Rule.

[[Page 45340]]

    Non-Acid Rain units in Connecticut and Massachusetts (about 15 
units total) that currently monitor and report NOX in the 
ozone season would need to monitor and report NOX and 
SO2 on an annual basis under the proposed Transport Rule.
    Non-Acid Rain units in Mississippi (about 4 units) and Texas (about 
52 units) are currently monitoring and reporting NOX and 
SO2 year-round and under the proposed Transport Rule would 
be required to monitor and report NOX in the ozone season. 
(All of these units burn natural gas and emitted approximately 12 tons 
of SO2 in 2009.)
    In states not covered by the CAIR but covered by the proposed 
Transport Rule, some units would have to meet new monitoring and 
reporting requirements under part 75. Kansas, Minnesota, and Nebraska 
are not covered by the CAIR and are covered by the Transport Rule, and 
units there would need to monitor and report NOX and 
SO2 emissions year-round. Oklahoma is not covered by the 
CAIR and is covered by the Transport Rule, and units there would need 
to monitor and report NOX in the ozone season. There are 
about 34 non-Acid Rain units total in Kansas, Nebraska and Oklahoma not 
monitoring and reporting under Part 75 that would need to begin to do 
so. Most of these units are simple-cycle combustion turbines used in 
the ozone season as peaking units and would likely be able to utilize 
the Low Mass Emissions or Appendix D and E methodologies in 40 CFR part 
75, which do not require a continuous emissions monitoring system 
(CEMS). The circulating fluidized bed (CFB) units in Oklahoma (about 4 
units) that burn coal are already monitoring and reporting under 40 CFR 
part 60, subpart Da, which requires an SO2, NOX 
and CO2/O2 (diluent) CEMS. These boilers would only have to add a flow 
monitor and upgrade the automated data acquisition and handling system. 
Non-Acid Rain units in Minnesota (about 20 units) would also need to 
monitor and report, but were already doing so under the CAIR before the 
CAIR was stayed in Minnesota (74 FR 56721, November 3, 2009); 
therefore, they would simply have to reactivate those monitoring 
systems.
    Units that have not been covered by part 75 monitoring and 
reporting in the past would likely have less than one year to install, 
certify, and operate the required monitoring systems. EPA believes that 
these units would reasonably 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 there would be sufficient time to accomplish this.

G. Interactions With Existing Title IV Program and NOX SIP Call

1. Title IV Interactions
    Promulgation of a Transport Rule would not affect any Acid Rain 
Program requirements. Any Title IV sources that are subject to final 
Transport Rule provisions would still need to continue to comply with 
all Acid Rain provisions. Acid Rain requirements are established 
independently in Title IV of the Clean Air Act and would not be 
replaced by the Transport Rule. In contrast with the CAIR, the proposed 
Transport Rule would not allow Title IV SO2 allowances to be 
used in the Transport Rule program. Similarly, Transport Rule 
SO2 allowances would not be useable in the Acid Rain 
Program. Title IV SO2 and NOX requirements will 
continue to apply independently of the Transport Rule provisions. The 
Transport Rule program as proposed has no opt-in provisions, so no 
sources, including any that have opted into the Acid Rain Program would 
be able to opt-in to the Transport Rule program.
    Compliance with the Transport Rule would reduce SO2 
emissions in the Transport Rule states below the 2010 Title IV cap. So, 
as sources complied with the Transport Rule, emissions would go down 
and with them so would the demand for Title IV allowances. Therefore, 
the Title IV allowance prices are expected to be very low once the 
Transport Rule is finalized; some analysts suggest a price of nearly 
zero. Acid Rain sources will still be required to comply with Title IV 
requirements, including the requirement to hold Title IV allowances to 
cover emissions at the end of a compliance year.
    There would likely be changes to emissions at some Acid Rain 
sources 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 sources may increase because of the change 
in the Title IV allowance price. This would be expected to occur mainly 
in the states that border the Transport Rule states. Overall, 
SO2 emissions from these non-Transport Rule Acid Rain 
sources would be expected to increase approximately 237,000 tons each 
year if the Transport Rule is implemented compared to what they would 
have been in the absence of the Transport Rule. There is more 
discussion of this effect in section IV.D.
2. NOX SIP Call Interactions
    States affected by both the NOX SIP Call and any final 
Transport Rule will be required to comply with the requirements of both 
rules. The Transport Rule does not preempt or replace the requirements 
of the NOX SIP Call. However, the proposed Transport Rule 
ozone season program would achieve the emissions reductions required by 
the NOX SIP Call from EGUs greater than 25 MW in nearly all 
NOX SIP Call states. The NOX SIP Call states used 
the NOX Budget Trading Program (NBP) 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/hr. (In some 
states, EGUs smaller than 25 MW were also part of the NBP as a 
carryover from the Ozone Transport Commission NOX Budget 
Trading Program.) EPA stopped administering the NBP after the 2008 
ozone season control period activities, and states used another 
mechanism to comply with the NOX SIP Call requirements.
    Many of the states using the NBP used the CAIR NOX ozone 
season trading program to replace the NBP. To address NOX 
SIP Call requirements, fourteen NOX SIP Call states chose to 
expand the CAIR NOX ozone season applicability to include 
all NBP-affected units. EPA has analyzed the effect of allowing states 
to expand their CAIR NOX ozone season applicability and 
consequently their CAIR NOX ozone season budgets to include 
the additional non-CAIR affected NBP units. In 2009, the additional 
units emitted about half of the amount of allowances added to the CAIR 
NOX ozone season budgets for them. The remaining allowances 
are available for the sources to trade to other affected units. As a 
group, these units did not reduce their NOX emissions or 
their NOX emissions rates as a result of their inclusion in 
the CAIR NOX ozone season program. If EPA were to allow them 
to be part of the Transport Rule NOX Ozone Season Program, 
and if states were allowed to increase the Transport Rule 
NOX Ozone Season Budgets by the amounts allowed under the 
NBP and CAIR for these units, a state's ability to eliminate the part 
of significant contribution and interference with maintenance that EPA 
has identified in today's proposal could be jeopardized. One option 
considered that could possibly address concerns about still being able 
to address significant contribution and interference with

[[Page 45341]]

maintenance would be to require the budget increase to be much less 
than allowed under the NBP and CAIR. For example, the units' 2009 
emissions (or 2012 projected emissions if they are required to install 
controls for another program) could be used to determine the budget 
increase and the elimination of emissions causing significant 
contribution and interference with maintenance might be able to be 
preserved. It is likely the budget changes would not be consistent 
across states as each state's impact would have to be considered 
individually. EPA is proposing to not allow the expansion of the 
applicability of the Transport Rule.
    Therefore, the NBP states would need to achieve their 
NOX SIP Call emissions reductions another way in order to 
continue to comply with the NOX SIP Call. If EPA promulgates 
a final rule that does not allow the expansion of the Transport Rule to 
NBP units, any state that allowed these units to participate in the 
CAIR NOX Ozone Season Program would need to submit a SIP 
revision to address their NOX SIP Call requirement for the 
reductions.
    States that were part of the CAIR NOX ozone season 
program or the NBP that are not part of a final Transport Rule ozone 
season program would need to submit SIP revisions that address the 
NOX SIP Call requirements for any emissions reductions that 
were part of either the CAIR NOX ozone season program or the 
NBP and would not continue to be addressed some other way. EPA will 
work with states to ensure that NOX SIP Call obligations 
continue to be met.

VI. Stakeholder Outreach

    In early 2009, EPA began its efforts to coordinate activities with 
state regulatory partners and other stakeholders on the new transport 
rule to replace CAIR. To establish open lines of communication and 
ensure transparency in the regulatory process, EPA participated in a 
series of ``listening sessions'' in March and April, 2009 with states, 
nongovernmental organizations, and industry. EPA also participated in 
tribal teleconferences. The same agenda was set for each of the ten 
meetings. Meeting notes were developed and distributed for concurrence 
and to ensure accuracy. Subsequent to these sessions, EPA received 
post-meeting comments and additional detailed suggestions and analyses 
on ways to address some of the issues that the court cited, most 
notably from state regional organizations in the eastern U.S. All the 
stakeholder-related materials may be found in the EPA docket for the 
transport rule (EPA-HQ-OAR-2009-0491).
    Following the remand of CAIR to EPA in December 2008, 17 states in 
the East and Midwest, under the umbrellas of the OTC and Lake Michigan 
Air Directors Consortium (LADCO) with support from southeastern states, 
worked to develop recommendations for EPA to consider in crafting a new 
transport rule to replace CAIR. The comprehensive framework presented 
the consensus approach the states reached but noted that certain 
regional differences would be addressed in separate letters with 
additional recommendations and supporting materials.
    EPA has considered and appreciates all the ideas and 
recommendations provided by the states. We are employing the technical 
work that they submitted as part of the data set we are using in this 
and later transport rules.
    Topics addressed in the listening sessions, where EPA asked 
stakeholders and regulatory partners for their thoughts on particular 
issues, included:
     Analysis and baselines.
     Linkages between a state's significant contribution and 
downwind nonattainment/interference with maintenance.
     Remedies.
     Attainment planning.
     Other areas.
    EPA continued to provide updates to regulatory partners and 
stakeholders through monthly conference calls with states, hosted by, 
e.g., NACAA, as well as industry and NGO conferences where EPA 
directors often made presentations.
    Several of the options presented in this proposal were influenced 
by feedback received from stakeholders and regulatory partners, 
including:
     2012 baseline used in the calculation of each state's 
significant contribution and interference with maintenance.
     The ``tiered'' approach to SO2 emissions 
reductions requirements.
     Threshold (1 percent of the NAAQS) used for linking upwind 
areas to downwind nonattainment and maintenance receptors.
     Approach used to give independent meaning to the interfere 
with maintenance prong of section 110(a)(2)(D)(i)(I).
     Level of reductions required.
     Use of limited interstate trading.
     Correlated and coordinated requirements and timing for the 
power industry.
    EPA looks forward to the public comment period of this rulemaking 
and is committed to establishing and maintaining close working 
relationships with a broad range of public and private sector 
organizations.

VII. State Implementation Plan Submissions

A. Section 110(a)(2)(D)(i) SIPs for the 1997 Ozone and PM2.5 NAAQS

    All states have an obligation to submit SIPs that address the 
requirements of CAA section 110(a)(2) within 3 years of promulgation or 
revision of a NAAQS. With respect to the 1997 ozone and 
PM2.5 NAAQS, EPA found in 2005 that states had failed to 
make submissions that address the requirements of section 
110(a)(2)(D)(i) related to interstate transport of pollution. See 70 FR 
21147 (April 25, 2005). Also in 2005, EPA promulgated the CAIR, which 
was intended to provide states covered by the rule with a mechanism to 
satisfy their section 110(a)(2)(D)(i)(I) obligations. In the CAIR, EPA 
concluded that the states in the CAIR region would meet their section 
110(a)(2)(D)(i) obligations to address ``significant contribution'' and 
`` interference with maintenance'' requirements by complying with the 
CAIR requirements. Consequently, states within the CAIR region did not 
need to submit a separate SIP revision to satisfy the section 
110(a)(2)(D)(i) requirements provided they submitted a SIP revision to 
satisfy CAIR. Most of the CAIR states participated in the CAIR trading 
programs and submitted SIP revisions that EPA subsequently approved. In 
2008, the Court granted several petitions for the review of the CAIR 
and found, among other things, that EPA had not demonstrated that the 
CAIR effectuates the statutory mandate of section 110(a)(2)(D)(i)(I). 
The EPA approvals of the CAIR SIPS preceded the remand of the CAIR by 
the Court. Therefore, because the D.C. Circuit Court found CAIR and the 
CAIR FIPs unlawful, EPA's approval of the provisions of a state's SIP 
submittal as addressing the requirements of the CAIR could not satisfy 
that state's section 110(a)(2)(D)(i)(I) obligation. In other words, a 
CAIR SIP submission can no longer be considered an adequate section 
110(a)(2)(D)(i)(I) SIP submission. For this reason, EPA's 2005 findings 
that states had failed to submit SIPs that satisfy section 
110(a)(2)(D)(i)(I) \106\ remain in force regardless of whether a state 
covered by the CAIR submitted

[[Page 45342]]

and/or had an approved SIP stating that compliance with the CAIR 
satisfied their 110(a)(2)(D)(i) obligations.
---------------------------------------------------------------------------

    \106\ The 2005 findings of failure to submit related to states' 
obligations pursuant to section 110(a)(2)(D)(i). The CAIR, however, 
addressed only the requirements of 110(a)(2)(D)(i)(I). The remand of 
CAIR, therefore, had no impact on state SIP submissions or EPA 
approval of state SIP submissions pursuant to section 
110(a)(2)(D)(i)(II).
---------------------------------------------------------------------------

    The 2005 findings of failure to submit also remain in force for 
many states not covered by the original CAIR. Some of these states have 
not yet submitted 110(a)(2)(D)(i)(I) SIPs and thus the findings remain 
in force. However, several states that were not covered by the CAIR 
have since 2005 submitted SIP revisions to satisfy the requirements of 
section 110(a)(2)(D)(i) for the 1997 8-hour ozone and PM2.5 
NAAQS. Some of these SIPs have been approved and some are pending 
approval.
    For the states that have now been identified to be contributing 
significantly to nonattainment or interfering with maintenance under 
this proposed rule and whose 110(a)(2)(D)(i)(I) SIPs with respect to 
the 1997 ozone and PM2.5 NAAQS are pending approval, EPA 
will finalize the FIP included in this proposed rule only if EPA either 
determines that the SIP submission is incomplete or disapproves the SIP 
submission. (Alternatively, if a state withdraws its SIP submission, 
EPA will finalize the FIP.)
    For states which are not included in a final FIP under this 
proposed transport rule and that have not submitted a 
110(a)(2)(D)(i)(I) SIP to address the 1997 ozone and PM2.5 
NAAQS, a SIP submittal is required.
    EPA has approved the 110(a)(2)(D)(i) submission from the state of 
Kansas for the 1997 ozone and PM2.5 NAAQS. The updated 
modeling done for this proposed rule demonstrates that emissions from 
Kansas significantly contribute to nonattainment or interfere with 
maintenance of the 1997 8-hour ozone NAAQS in downwind areas. Because 
Kansas' current SIP does not prohibit these emissions, it is not 
adequate to satisfy the requirements of 110(a)(2)(D)(i)(I) at this 
time. For Kansas, under a separate action, EPA plans to propose a 
finding under CAA 110(k)(5) (known as a SIP Call) that the state's 
existing SIP is substantially inadequate to meet the requirements of 
110(a)(2)(D)(i)(I) with respect to the 1997 ozone NAAQS. That SIP call, 
if finalized, would also establish a deadline for submission of a new 
110(a)(2)(D)(i)(I) SIP which EPA would review for completeness. 
Therefore, in today's notice EPA is proposing to finalize the FIP for 
Kansas for ozone only if the state fails to submit a complete and 
approvable SIP by the deadline established in any final SIP Call.

B. Section 110 (a)(2)(D)(i) SIPs for the 2006 24-Hour PM2.5 NAAQS

    With respect to the 2006 24-hour PM2.5 NAAQS, EPA has 
issued a separate Federal Register notice finding that a number of 
states failed to make the required 110(a)(2)(D)(i)(I) SIP submissions. 
None of the SIP submittals in the states that have submitted section 
110(a)(2)(D)(i)(I) transport SIPs for the 2006 24-hour PM2.5 
NAAQS have been acted on yet by EPA. For the states with SIPs that are 
pending approval, EPA is proposing to finalize the FIP with respect to 
the 2006 PM2.5 NAAQS only if EPA finds the previously 
submitted SIP incomplete or disapproves the SIP submission. 
Alternatively, if any of these states withdraws its 2006 24-hour 
PM2.5 SIP submittal, EPA plans to issue a separate notice of 
finding for such states.

C. Transport Rule SIPs

    EPA also notes that, by promulgating these Transport Rule FIPs, EPA 
would in no way affect the right of states to submit, for review and 
approval, a SIP that replaces the federal requirements of the FIP with 
state requirements. In order to replace the FIP in a state, the state's 
SIP must provide adequate provisions to prohibit NOX and 
SO2 emissions that contribute significantly to nonattainment 
or interfere with maintenance in another state or states. The Transport 
Rule FIPs would be in place in each covered state until a state's SIP 
was submitted and approved by EPA to replace a FIP.
    For each upwind state covered by the proposed Transport Rule, EPA 
proposes state-specific emissions reductions requirements 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. Again EPA 
wants to offer states substantial flexibility for addressing the 
Section 110(a)(2)(D)(i)(I) transport issues through a SIP should they 
choose to do so. The EPA's intent is to provide states with substantial 
flexibility in implementing these emissions reductions requirements. 
EPA will 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. The specific quantity of emissions 
reductions necessary for a state's SIP would be determined based on the 
state emissions budgets provided in the final transport rule. (See 
Tables IV.E-1 for proposed SO2 and annual NOX 
budgets, and IV.E-2 for proposed ozone season NOX budgets, 
in section IV.E).
    In the states for which EPA is proposing to require reductions with 
respect to both the 24-hour PM2.5 NAAQS and the annual 
PM2.5 NAAQS, there is no case where the annual standard 
drives the reduction requirements deeper than would the 24-hour 
standard alone. Thus, emissions reduction requirements for a SIP to 
address significant contribution and interference with maintenance with 
respect to the 24-hour PM2.5 NAAQS would be based on the 
SO2 and NOX emissions budgets in Table IV.E-1. 
For such a state, a SIP that addresses the requirements with respect to 
the 24-hour PM2.5 NAAQS would also by definition address the 
requirements with respect to the annual PM2.5 NAAQS.
    EPA is taking comment on all aspects of how a state could replace 
the Transport Rule FIP with a SIP and on what the SIP approval criteria 
should be.

VIII. Permitting

A. Title V Permitting

    EPA's proposed FIPs would 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.\107\ Title V requires 
that sources meeting certain criteria have permits meeting the 
requirements specified in Title V and the Title V regulations. For 
example, for sources required to have Title V permits, such permits 
must include, among other things, all ``applicable requirements,'' as 
defined in the Title V regulations (40 CFR 70.2 and 71.2 (definition of 
``applicable requirement'')).
---------------------------------------------------------------------------

    \107\ Part 70 governs approved 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 
proposed FIPs, most of the sources at which they are located would be 
subject to Title V permitting requirements. For sources subject to 
Title V, the requirements applicable to them under the proposed FIPs 
would be ``applicable requirements'' under Title V and therefore would 
need to be included in the Title V permits. For example, requirements 
under the proposed FIPs concerning designated representatives, 
monitoring, reporting, and recordkeeping, the requirement to hold 
allowances covering emissions, the assurance provisions, and liability 
would be ``applicable requirements'' and necessary to include in the 
permits.

[[Page 45343]]

    The Title V permits program includes, among other things, 
provisions for permit applications, permit content, and permit 
revisions that would address the applicable requirements under the 
proposed FIPs in a manner that would provide the flexibility necessary 
to implement a market-based program such as the one that EPA is 
proposing. 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). The trading program regulations for the proposed FIPs would 
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 would also be 
included in each Title V permit for a covered source. As a result, 
allowances could be traded (or allocated, held, or deducted) under the 
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 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 trading program regulations for the 
proposed FIPs would include provisions requiring unit owners and 
operators to submit monitoring system certification applications (or, 
for alternative monitoring systems, petitions) to EPA establishing the 
monitoring and reporting approach to be used by the unit. These 
applications and petitions are subject to EPA review and approval to 
ensure consistency in monitoring and reporting among all trading 
program participants. As provided in the proposed regulations, EPA 
would only allow use of approaches that would result in emissions data 
with an appropriate level of precision, reliability, accessibility, and 
timeliness. The proposed regulations would also include a provision 
stating that a description of the general approach that each covered 
unit is required to use for monitoring and reporting emissions (i.e., 
an approach using a continuous emissions 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) could be 
added to or changed in a Title V permit using minor permit modification 
procedures, provided that the requirements applicable to the monitoring 
and reporting addition or change were already incorporated elsewhere in 
the permit. As a result, minor permit modification procedures could be 
used to revise a unit's Title V permit to be consistent with any 
changes in the monitoring and reporting approach allowed for the unit 
by EPA through the monitoring system certification or petition process 
in the proposed trading program regulations. However, if the permit did 
not already incorporate the monitoring and reporting requirements 
applicable to the change, the permit would also have to be revised to 
incorporate these requirements, and this change would not qualify as a 
minor permit modification pursuant to 40 CFR 70.7(e)(2)(i)(B) and 40 
CFR 71.7(e)(1)(i)(B).
    As new applicable requirements under Title V, the requirements for 
covered units under the final FIPs would 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)).\108\ For sources newly 
subject to title V that would also be covered sources under the 
proposed FIPs, the initial Title V permit issued pursuant to 40 CFR 
70.7(a) would include the final FIP requirements. In order to ensure 
that covered sources' Title V permit provisions concerning the FIPs 
would reflect, properly and in a manner consistent from permit to 
permit, the trading program requirements and flexibilities, EPA intends 
to issue guidance, after promulgation of the final FIPs, to assist 
permitting authorities. This guidance would include information on 
permit issuance and permit modification requirements, as well as a 
permit content template that would identify the applicable requirements 
under the trading program and thereby ensure that they would be 
correctly and comprehensively reflected in each permit in a manner that 
would reduce the need for frequent permit revisions. Use of a permit 
content template would also reduce the burden on sources in obtaining, 
on permitting authorities in issuing, and on EPA in reviewing, permits 
or permit revisions.
---------------------------------------------------------------------------

    \108\ 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).
---------------------------------------------------------------------------

B. New Source Review

    EPA recognizes that pollution control projects, including pollution 
control projects constructed to comply with the proposed rule, have the 
potential to trigger new source review (NSR) permitting.
    On December 20, 2005, the EPA agreed to reconsider one specific 
aspect of the CAIR. In that notice, EPA granted reconsideration and 
sought comment on the potential impact of a judicial opinion, New York 
v. EPA, 413 F.3d 3 (D.C. Cir. 2005). This decision vacated the 
pollution control project exclusion in EPA's NSR regulations. (The 
exclusion allowed for certain environmentally beneficial pollution 
control projects to be excluded from certain NSR requirements.) For 
this reconsideration, EPA conducted an analysis which showed that the 
court decision did not impact the CAIR analyses. The EPA believes this 
analysis, which remains current and relevant for all pollutants except 
for greenhouse gas (GHG), shows that New Source Review (NSR) 
requirements would not significantly impact the construction of 
controls that are installed to comply with the proposed transport rule. 
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 was not considered by EPA to be a ``pollutant'', let 
alone a ``regulated pollutant,'' at the time of CAIR, GHG was not 
addressed in the previous analysis. GHG requirements related to the 
component of new source review concerning the Prevention of Significant 
Deterioration (``PSD'') program have recently been 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, once the PSD requirements for GHG take 
effect on January 2, 2011, 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

[[Page 45344]]

exceed the thresholds in the Tailoring Rule. Once the PSD requirements 
take effect, 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 tons per year of CO2 equivalent. EPA believes it is very 
unlikely that pollution control projects would cause GHG increases that 
would exceed the 75,000 tons per year threshold.
    Consistent with EPA's previous analysis and EPA's conclusions for 
GHG, EPA does not believe that there are significant impacts from NSR 
for any pollution control projects resulting from the proposed rule 
such as low-NOX burners, SO2 scrubbers, or SCR. 
EPA requests comment on this issue.

IX. What benefits are projected for the proposed rule?

    In this section, we present the results of EPA's analysis of the 
benefits of the emissions reductions in this proposal on 
PM2.5 and ozone air quality, public health, welfare, and the 
environment. These improvements were determined based upon air quality 
modeling of the 2014 base case and the ``State Budgets/Limited 
Trading'' remedy proposed in this rule, as described in section V, 
above.
    Implementation of this rule will very substantially lower the 
extent of nonattainment and maintenance problems for the annual and 24-
hour PM2.5 NAAQS and 8-hour ozone NAAQS in the eastern U.S. 
(see section IX.A, below). The improvements in air quality will 
annually prevent thousands of premature deaths and other serious health 
effects (see section IX.B, below). We estimate the total monetized 
annual benefits to be approximately $120 billion to $290 billion or 
$110 billion to $270 billion in 2014 (at a 3 percent and a 7 percent 
discount rate, respectively) for the proposed ``State Budgets/Limited 
Trading'' remedy. There will be significant benefits that are not 
quantified. Notably, in 2012 the benefits are actually larger since 
greater emissions reductions are occurring from the baseline in that 
timeframe, as indicated in Table V.E-2, above. Because the magnitude of 
the PM2.5 co-benefits is largely driven by the 
concentration-response function for premature mortality, we examined 
alternate relationships between PM2.5 and premature 
mortality supplied by experts. Higher and lower co-benefits estimates 
are plausible, but most of the expert-based estimates fall between 
these two estimates above.\109\ All monetized estimates are stated in 
2006 dollars. Also note that the analytic baseline presents a unique 
situation. EPA has been directed to replace the CAIR; yet the CAIR 
remains in place and has led to significant emissions reductions in 
many states.
---------------------------------------------------------------------------

    \109\ Roman et al., 2008. Expert Judgment Assessment of the 
Mortality Impact of Changes in Ambient Fine Particulate Matter in 
the U.S. Environ. Sci. Technol., 42, 7, 2268-2274.
---------------------------------------------------------------------------

    A key step in the process of developing a 110(a)(2)(D)(i)(I) rule 
involves analyzing existing (base case) emissions to determine which 
states significantly contribute to downwind nonattainment and 
maintenance areas. EPA cannot prejudge at this stage which states will 
be affected by the rule. For example, a state affected by CAIR may not 
be affected by the new rule and after the new rule goes into effect, 
the CAIR requirements will no longer apply. For a state covered by CAIR 
but not covered by the new rule, the CAIR requirements would not be 
replaced with new requirements, and therefore an increase in emissions 
relative to present levels could occur in that state. More 
fundamentally, the court has made clear that, due to legal flaws, the 
CAIR rule cannot remain in place and must be replaced. If EPA's base 
case analysis were to ignore this fact and assume that reductions from 
CAIR would continue indefinitely, areas that are in attainment solely 
due to controls required by CAIR would again face nonattainment 
problems because the existing protection from upwind pollution would 
not be replaced. For these reasons, EPA cannot assume in its base case 
analysis, that the reductions required by CAIR will continue to be 
achieved.
    Following this logic, the 2012 base case shows emissions higher 
than current levels in some states. Because EPA has been directed to 
replace CAIR, EPA believes that for many states, the absence of the 
CAIR NOX program will lead to the status quo of the 
NOX Budget Program, which limits ozone-season NOX 
emissions and ensures the operation of NOX controls in those 
states. Also, without the CAIR SO2 program, emission 
requirements in many areas would revert to the comparatively less 
stringent requirements of the Title IV Acid Rain program. As a result, 
SO2 emissions in many states would increase markedly in the 
2012 base case relative to the present. Efforts to comply with ARP 
rules at the least-cost would occur in many cases without the operation 
of existing scrubbers through use of readily available, inexpensive 
Title IV allowances. Notably, all known controls that are required 
under state laws, NSPS, consent decrees, and other enforceable binding 
commitments through 2014 are accounted for in the base case. It is 
against this backdrop that the Transport Rule is analyzed and that 
significant contribution to nonattainment and interference with 
maintenance must be addressed.

A. The Impacts on PM2.5 and Ozone of the Proposed SO2 and NOX Strategy

    The air quality modeling platform described in section IV.C. was 
used by EPA to model the impacts of the proposed SO2 and 
NOX emissions 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.\110\ Modeling was performed 
for the 2014 base case and the 2014 ``State Budgets/Limited Trading'' 
scenario to assess the expected effects of the proposed regional 
strategy 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 IV.C. The aggregate emissions in 2012 and 2014 for 
SO2 and NOX are provided in Table V.E-2 in 
section V.E. The emissions by state are provided in Tables V.E-5 
through V.E-7 in section V.E, and also in the Air Quality Modeling TSD.
---------------------------------------------------------------------------

    \110\ As described in the AQMTSD, 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, daily 
PM2.5, and ozone at each monitoring site in the East for 
which projections were made are provided in the AQMTSD. 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, 
daily PM2.5, and ozone are provided in Table IX-1.\111\ The 
average and peak reductions in annual PM2.5, daily 
PM2.5, and ozone predicted at 2012 nonattainment and/or 
maintenance sites due to the emissions reductions

[[Page 45345]]

between 2012 and the 2014 remedy are provided in Table IX-2.
---------------------------------------------------------------------------

    \111\ To provide a point of reference, Table IX-1 also includes 
the number of nonattainment and/maintenance sites based on ambient 
design values for the period 2003 through 2007.

                  Table IX-1--Projected Reduction in Nonattainment and/or Maintenance Problems for PM2.5 and Ozone in the Eastern U.S.
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                              Percent         Percent
                                                                                                                            reduction:      reduction:
                                                          Ambient (2003-                                   2014 proposed  2012 base case  2014 base case
                                                               2007)      2012 base case  2014 base case      remedy         vs. 2014        vs. 2014
                                                                                                                              remedy          remedy
                                                                                                                             (percent)       (percent)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Annual PM2.5 Nonattainment Sites \112\..................             102              32              15               1              97              93
Annual PM2.5 Maintenance-Only Sites.....................              21              16               7               1              94              86
Daily PM2.5 Nonattainment Sites.........................             151              92              54              17              82              69
Daily PM2.5 Maintenance-Only Sites......................              48              38              28              11              71              61
Ozone Nonattainment Sites...............................             103              11               7               7              36               0
Ozone Maintenance-Only Sites............................              67              16               6               5              69              17
--------------------------------------------------------------------------------------------------------------------------------------------------------

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

    \112\ ``Nonattainment'' is used to denote sites that are 
projected to have both nonattainment and maintenance problems.

Table IX-2--Average and Peak Reduction in Annual PM2.5, Daily PM2.5, and
     Ozone for Sites That Are Projected To Have Nonattainment and/or
               Maintenance Problems in the 2012 Base Case
------------------------------------------------------------------------
                                  Average reduction:    Peak reduction:
                                   2012 base case to   2012 base case to
                                      2014 remedy         2014 remedy
------------------------------------------------------------------------
Annual PM2.5 Nonattainment Sites  2.8 [mu]g/m\3\....  3.9 [mu]g/m\3\
Annual PM2.5 Maintenance-Only     2.6 [mu]g/m\3\....  4.2 [mu]g/m\3\
 Sites.
Daily PM2.5 Nonattainment Sites.  5.8 [mu]g/m\3\....  15.3 [mu]g/m\3\
Daily PM2.5 Maintenance-Only      5.1 [mu]g/m\3\....  13.5 [mu]g/m\3\
 Sites.
Ozone Nonattainment Sites.......  1.9 ppb...........  3.9 ppb
Ozone Maintenance-Only Sites....  2.3 ppb...........  4.2 ppb
------------------------------------------------------------------------

    The information in Table IX-1 shows that there will be significant 
reductions in the extent of nonattainment and maintenance problems for 
annual PM2.5, daily PM2.5, and ozone between 2012 
and 2014 as a result of the emissions budgets in this proposal coupled 
with emissions reductions during this time period from other existing 
control programs. Specifically, the results of the air quality modeling 
indicate that all but 1 site is projected to be in attainment and only 
1 site is projected to have a maintenance problem for annual 
PM2.5 in 2014 with the emissions reductions expected from 
this proposal. As indicated in Table IX-2, the average reduction in 
annual PM2.5 across the 32 2012 nonattainment sites is 1.9 
[mu]g/m\3\ and the peak reduction at an individual nonattainment site 
is 3.2 [mu]g/m\3\. Comparable reductions are projected at annual 
PM2.5 maintenance-only sites.
    For 24-hour PM2.5, we project that the number of 
nonattainment sites will be reduced by 82 percent and the number of 
maintenance-only sites by 71 percent in 2014 compared to the 2012 base 
case. The average reduction in 24-hour PM2.5 across the 92 
2012 nonattainment sites is 5.8 [mu]g/m\3\ and the peak reduction at an 
individual nonattainment site is 15.3 [mu]g/m\3\. Comparable reductions 
are projected at 24-hour PM2.5 maintenance-only sites.
    The emissions reductions in this proposal will result in 
considerable progress toward attainment and maintenance at the 28 sites 
that remain as nonattainment and/or maintenance for the 24-hour 
PM2.5 standard. On average for these 28 sites, the predicted 
amount of PM2.5 reduction in 2014 is more than half of what 
is needed for these sites to attain and/or maintain the 24-hour 
standard.
    Thus, the SO2 and NOX emissions reductions 
which will result from today's proposal will greatly reduce the extent 
of PM2.5 nonattainment and maintenance problems by 2014 and 
beyond. As described previously, these emissions 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 emissions reductions will also help those locations that may 
have maintenance problems.
    Based on the 2012 base air quality modeling for ozone, 27 sites in 
the East are projected to be nonattainment or have problems maintaining 
the 1997 ozone standard. The initial phase of summer NOX 
reductions in today's proposal are projected to lower 8-hour ozone 
concentration by 2.8 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 36 percent and the number of maintenance-only sites by 69 
percent in 2014 compared to the 2012 base case. For the 12 sites 
expected to have residual nonattainment/maintenance problems in 2014, 
the predicted ozone reductions provide nearly 10 percent of the amount 
needed for these sites to attain and/or maintain the ozone standard. 
Thus, our modeling indicates that by 2014 the initial phase of summer 
NOX emissions reductions in this proposal will lower ozone 
concentrations in the East and help bring areas closer to attainment 
for the 8-hour ozone NAAQS.

[[Page 45346]]

B. Human Health Benefit Analysis

    To estimate the human health benefits of the proposed Transport 
Rule, we 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. We provide such estimates for 
the proposed remedy option. Notably, EPA expects that in 2014 the other 
two alternatives that the Agency considered have the same general level 
of benefits that will result from their implementation. The results of 
the analysis for the alternate SO2 reduction scenarios are 
found in the RIA. 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 concentrations and premature 
mortality. For this proposed rule we cite two key empirical studies, 
one based on the American Cancer Society cohort study \113\ and the 
other based on the extended Six Cities cohort study.\114\
---------------------------------------------------------------------------

    \113\ 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.
    \114\ Laden et al., 2006. ``Reduction in Fine Particulate Air 
Pollution and Mortality.'' American Journal of Respiratory and 
Critical Care Medicine. 173:667-672.
---------------------------------------------------------------------------

    Table IX-3 presents the primary estimates of reduced incidence of 
PM2.5 and ozone-related health effects in 2014 for the 
proposed and alternative remedies. In 2014, we estimate that PM-related 
annual benefits of the proposed remedy include approximately 14,000 to 
36,000 fewer premature mortalities, 9,200 fewer cases of chronic 
bronchitis, 22,000 fewer non-fatal heart attacks, 11,000 fewer 
hospitalizations (for respiratory and cardiovascular disease combined), 
10 million fewer days of restricted activity due to respiratory illness 
and approximately 1.8 million fewer work-loss days. We also estimate 
substantial health improvements for children from fewer cases of upper 
and lower respiratory illness, acute bronchitis, and asthma attacks. As 
mentioned earlier, the reduced incidences of various effects would be 
greater in 2012 due to the larger emissions reductions that occur from 
the baseline. The lower reductions in emissions in 2014 result from 
further SO2 controls in the proposed remedy because the 
baseline has much greater controls resulting from state actions and 
consent decrees.
    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 50 and 230 fewer 
premature mortalities, 690 fewer hospital admissions for respiratory 
illnesses, 230 fewer emergency room admissions for asthma, 300,000 
fewer days with restricted activity levels, and 110,000 fewer days 
where children are absent from school due to illnesses. When adding the 
PM and ozone-related mortalities together, we find that the proposed 
Transport Rule will yield between 14,000 and 36,000 fewer premature 
mortalities. The following references are used in providing our 
estimates of ozone health-related benefits:

    Bell, M.L., et al. 2004. Ozone and short-term mortality in 95 
U.S. urban communities, 1987-2000. Journal of the American Medical 
Association. 292 (19): p. 2372-8.
    Laden, F., J. Schwartz, F.E. Speizer, and D.W. Dockery. 2006. 
Reduction in Fine Particulate Air Pollution and Mortality. American 
Journal of Respiratory and Critical Care Medicine 173:667-672. 
Estimating the Public Health Benefits of Proposed Air Pollution 
Regulations. Washington, DC: The National Academies Press.
    Levy JI, Baxter LK, Schwartz J. 2009. Uncertainty and 
variability in health-related damages from coal-fired power plants 
in the United States. Risk Anal. doi: 10.1111/j.1539-
6924.2009.01227.x [Online 9 Apr 2009]
    Pope, C.A., III, R.T. Burnett, M.J. Thun, E.E. Calle, D. 
Krewski, K. Ito, and G.D. Thurston. 2002. Lung Cancer, 
Cardiopulmonary Mortality, and Long-term Exposure to Fine 
Particulate Air Pollution. Journal of the American Medical 
Association 287:1132-1141.

 Table IX-3--Estimated Annual Reductions in Incidence of Health Effects
                                   \A\
------------------------------------------------------------------------
               Health effect                       Proposed remedy
------------------------------------------------------------------------
PM-Related endpoints
Premature Mortality
    Pope et al. (2002) (age >30)..........         14,000 (4,000-25,000)
    Laden et al. (2006) (age >25).........        36,000 (17,000-56,000)
    Infant (< 1 year).....................                  59 (-66-180)
    Chronic Bronchitis....................            9,200 (320-18,000)
    Non-fatal heart attacks (age > 18)....         22,000 (5,800-39,000)
    Hospital admissions--respiratory (all            3,500 (1,400-5,500)
     ages)................................
    Hospital admissions--cardiovascular              7,500 (5,200-8,900)
     (age > 18)...........................
    Emergency room visits for asthma (age          14,000 (7,200-21,000)
     < 18)................................
    Acute bronchitis (age 8-12)...........        21,000 (-4,800-46,000)
    Lower respiratory symptoms (age 7-14).      250,000 (98,000-400,000)
    Upper respiratory symptoms (asthmatics      190,000 (36,000-350,000)
     age 9-18)............................
    Asthma exacerbation (asthmatics 6-18).       240,000 (8,300-800,000)
    Lost work days (ages 18-65)...........         1,800,000 (1,500,000-
                                                              2,000,000)
    Minor restricted-activity days (ages          10,000,000 (8,600,000-
     18-65)...............................                   12,000,000)
Ozone-related endpoints
Premature mortality
    Bell et al. (2004) (all ages).........                    50 (17-84)
    Levy et al. (2005) (all ages).........                 230 (160-300)
    Hospital admissions--respiratory                       390 (-18-740)
     causes (ages > 65)...................
    Hospital admissions--respiratory                       300 (130-460)
     causes (ages < 2)....................
    Emergency room visits for asthma (all                  230 (-30-730)
     ages)................................
    Minor restricted-activity days (ages       300,000 (130,000-480,000)
     18-65)...............................

[[Page 45347]]


    School absence days...................      110,000 (38,000-160,000)
------------------------------------------------------------------------
\A\ Values rounded to two significant figures. Benefits from reducing
  other criteria pollutants and hazardous air pollutants and ecosystem
  effects are not included here.

C. Quantified and Monetized Visibility Benefits

    Only a subset of the expected visibility benefits--those for Class 
I areas--are included in the monetary benefits 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 $3.4 billion beginning in 2014 for 
visibility improvements. Methodological limitations prevented us from 
quantifying the visibility benefits of the alternate remedies. The 
value of visibility benefits in areas where we were unable to monetize 
benefits could also be substantial.

D. Benefits of Reducing GHG Emissions

    When fully implemented in 2014, the proposed Transport Rule would 
reduce emissions of CO2 from electrical generating units by 
about 15 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].

E. Total Monetized Benefits

    Table IX-4 presents the estimated 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. As the table 
indicates, total benefits are driven primarily by the reduction in 
premature fatalities each year, which account for over 90 percent of 
total benefits.
    Table IX-5 presents the total monetized net benefits for 2014. A 
listing of the benefit categories that could not be quantified or 
monetized in our benefit estimates are provided in Table IX-6.

      Table IX-4--Estimated Annual Monetary Value of Reductions in Incidence of Health and Welfare Effects
                                             (Billions Of 2006$) \A\
----------------------------------------------------------------------------------------------------------------
                 Health effect                               Pollutant                     Proposed remedy
----------------------------------------------------------------------------------------------------------------
Premature mortality (Pope et al. 2002 PM mortality and Bell et al. 2004 ozone mortality estimates)
----------------------------------------------------------------------------------------------------------------
3% discount rate...............................  PM2.5 & O3.......................              $110 ($8.8-$340)
7% discount rate...............................  PM2.5 & O3.......................              $100 ($7.9-$300)
----------------------------------------------------------------------------------------------------------------
Premature mortality (Laden et al. 2006 PM mortality and Levy et al. 2005 ozone mortality estimates)
----------------------------------------------------------------------------------------------------------------
3% discount rate...............................  PM2.5 & O3.......................               $280 ($25-$820)
7% discount rate...............................  PM2.5 & O3.......................               $260 ($22-$310)
Chronic bronchitis.............................  PM2.5............................                $4.3 $0.2-$20)
Non-fatal heart attacks........................
3% discount rate...............................  PM2.5............................                $2.5 ($0.4-$6)
7% discount rate...............................  PM2.5............................              $2.4 ($0.4-$5.9)
Hospital admissions--respiratory...............  PM2.5 & O3.......................            $0.06 ($0.03-$0.1)
Hospital admissions--cardiovascular............  PM2.5............................              $0.2 ($0.1-$0.3)
Emergency room visits for asthma...............  PM2.5 & O3.......................        $0.005 ($0.002-$0.008)
Acute bronchitis...............................  PM2.5............................       $0.009 (-$0.0004-$0.03)
Lower respiratory symptoms.....................  PM2.5............................        $0.005 ($0.002-$0.009)
Upper respiratory symptoms.....................  PM2.5............................        $0.006 ($0.001-$0.014)
Asthma exacerbation............................  PM2.5............................        $0.012 ($0.001-$0.046)
Lost work days.................................  PM2.5............................            $0.2 ($0.19-$0.24)
School loss days...............................  .................................         $0.01 ($0.004-$0.013)
Minor restricted-activity days.................  PM2.5 & O3.......................           $0.64 ($0.34-$0.97)
Recreational visibility, Class I areas.........  PM2.5............................                          $3.6
----------------------------------------------------------------------------------------------------------------
Total benefits based on Pope et al. 2002 PM mortality and Bell et al. 2004 ozone mortality estimates
----------------------------------------------------------------------------------------------------------------
3% discount rate...............................  PM2.5 & O3.......................               $120 ($10-$360)
7% discount rate...............................  PM2.5 & O3.......................                $110 ($9-$330)
----------------------------------------------------------------------------------------------------------------
Total benefits based on Laden et al. 2006 PM mortality and Levy et al. 2005 ozone mortality estimates
----------------------------------------------------------------------------------------------------------------
3% discount rate...............................  PM2.5 & O3.......................               $290 ($26-$840)
7% discount rate...............................  PM2.5 & O3.......................               $270 ($24-$760)
----------------------------------------------------------------------------------------------------------------
\A\ Estimates rounded to two significant figures.


[[Page 45348]]

E. How do the benefits compare to the costs of this proposed rule?

    The estimated annual private costs to implement the emission 
reduction requirements of the proposed rule for the Transport Rule 
region are $3.7 billion in 2012 and $2.8 billion in 2014 (2006$) for 
the proposed remedy option, $4.2 billion in 2012 and $2.7 billion in 
2014 for the State Budgets/Intrastate Trading remedy option, and $4.3 
billion in 2012 and $3.4 billion in 2014 for the direct control remedy 
option. 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 (thus reflecting the proposed remedy option) are 
estimated to be approximately $2.0 billion in 2014 assuming a 3 percent 
discount rate. These costs become $2.2 billion in 2014, if one assumes 
a 7 percent discount rate. Thus, the net benefit (social benefits minus 
social costs) as will be shown in Table IX-5 for the proposed remedy 
option is approximately $120 to 292 billion or $109 to 264 billion (3 
percent and 7 percent discount rates) in 2014. Implementation of the 
rule is expected to provide society with a substantial net gain in 
social welfare based on economic efficiency criteria.
    The annualized regional cost of the proposed rule, as quantified 
here, is EPA's best assessment of the cost of implementing the proposed 
option. These costs are generated from rigorous economic modeling of 
changes in the power sector expected from the proposed 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 proposed 
option to industry. The relatively small cost associated with 
monitoring emissions, reporting, and recordkeeping for affected sources 
is not included in these annualized cost estimates, but EPA has done a 
separate analysis and estimated the cost to less than $28 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 to the quantified costs of the program on 
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 section X of this preamble and in the RIA for this proposed rule.

 Table IX-5--Summary of Annual Benefits, Costs, and Net Benefits of the
                         Transport Rule in 2014
                       [Billions of 2006 dollars]
------------------------------------------------------------------------
           Description                        Proposed remedy
------------------------------------------------------------------------
Social costs:
    3 percent discount rate......  $2.0.
    7 percent discount rate......  $2.2.
Social benefits:
    3 percent discount rate......  $122 to 294 + B.
    7 percent discount rate......  $111 to 266 + B.
Health-related benefits:
    3 percent discount rate......  $118 to 290.
    7 percent discount rate......  $107 to 262.
Visibility benefits:
    3 percent discount rate......  $3.6.
    7 percent discount rate......  $3.6.
Annual net benefits (benefits-
 costs)
    3 percent discount rate......  $120 to 292.
    7 percent discount rate......  $109 to 264.
------------------------------------------------------------------------
\a\ All estimates are rounded to three significant digits and represent
  annualized benefits and costs anticipated for 2014. Estimates relate
  to the complete Transport Rule program.
\b\ Note that costs are the annual total costs of reducing pollutants
  including NOX and SO2 in the Transport Rule region.
\c\ As this table indicates, total benefits are driven primarily by
  PM2.5-related health benefits. The reduction in premature fatalities
  each year accounts for over 90 percent of total monetized benefits
  2014. Benefits in this table are nationwide (with the exception of
  visibility) and are associated with NOX and SO2 reductions for the EGU
  source category. Ozone benefits represent benefits in the eastern
  United States. Visibility benefits represent benefits in Class I areas
  in the southeastern United States.
\d\ Not all possible benefits or disbenefits are quantified and
  monetized in this analysis. Potential benefit categories that have not
  been quantified and monetized are listed in Table IX-6. We represent
  the value of unquantified benefits and disbenefits with a ``B.''
\e\ Valuation assumes discounting over the SAB-recommended 20 year
  segmented lag structure described in chapter 4 of the Regulatory
  Impact Analysis for the Clean Air Interstate Rule (March 2005).
  Results reflect 3 percent and 7 percent discount rates consistent with
  EPA and OMB guidelines for preparing economic analyses (U.S. EPA, 2000
  and OMB, 2003).174
\f\ Net benefits are rounded to the nearest $1 billion. Columnar totals
  may not sum due to rounding.


[[Page 45349]]

    Every benefit-cost analysis examining the potential effects of a 
change in environmental protection requirements is limited to some 
extent by data gaps, limitations in model capabilities (such as 
geographic coverage), and uncertainties in the underlying scientific 
and economic studies used to configure the benefit and cost models. 
Gaps in the scientific literature often result in the inability to 
estimate quantitative changes in health and environmental effects. Gaps 
in the economics literature often result in the inability to assign 
economic values even to those health and environmental outcomes that 
can be quantified. While uncertainties in the underlying scientific and 
economics literatures (that may result in overestimation or 
underestimation of benefits) are discussed in detail in the economic 
analyses and its supporting documents and references, the key 
uncertainties which have a bearing on the results of the benefit-cost 
analysis of this rule include the following:
     EPA's inability to quantify potentially significant 
benefit categories;
     Uncertainties in population growth and baseline incidence 
rates;
     Uncertainties in projection of emissions inventories and 
air quality into the future;
     Uncertainty in the estimated relationships of health and 
welfare effects to changes in pollutant concentrations including the 
shape of the C-R function, the size of the effect estimates, and the 
relative toxicity of the many components of the PM mixture;
     Uncertainties in exposure estimation; and
     Uncertainties associated with the effect of potential 
future actions to limit emissions.
    Despite these uncertainties, we believe the benefit-cost analysis 
provides a reasonable indication of the expected economic benefits of 
the rulemaking in future years under a set of reasonable assumptions. 
This approach calculates a mean value across VSL estimates derived from 
26 labor market and contingent valuation studies published between 1974 
and 1991. The mean VSL across these studies is $6.3 million 
(2000$).\115\ The benefits estimates generated for this rule are 
subject to a number of assumptions and uncertainties, which are 
discussed throughout the RIA document.
---------------------------------------------------------------------------

    \115\ In this analysis, we adjust the VSL to account for a 
different currency year (2006$) and to account for income growth to 
2014. After applying these adjustments to the $6.3 million value, 
the VSL is $8.5 million.
---------------------------------------------------------------------------

    As Table IX-4 indicates, total 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 daily basis. Plausible biological mechanisms for this 
effect have been hypothesized for the endpoints included in the primary 
analysis and the weight of the available epidemiological evidence 
supports an assumption of causality.
    (2) EPA assumes all fine particles, regardless of their chemical 
composition, are equally potent in causing premature mortality. This is 
an important assumption, because the proportion of certain components 
in the PM mixture produced via precursors emitted from EGUs may differ 
significantly from direct PM released from automotive engines and other 
industrial sources, but no clear scientific grounds exist for 
supporting differential effects estimates by particle type.
    (3) 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 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 IX-6.

F. What are the unquantified and unmonetized benefits of the Transport 
Rule emissions reductions?

    Important benefits beyond the human health and welfare benefits 
resulting from reductions in ambient levels of PM2.5 and 
ozone in the eastern United States are expected to occur from this 
rule. These other benefits occur both directly from NOX and 
SO2 emissions reductions. These benefits are listed in Table 
IX-6. Some of the more important examples include: Reductions in 
NOX and SO2 emissions required by the Transport 
Rule will reduce acidification and, in the case of NOX, 
eutrophication of water bodies. Reduced nitrate contamination of 
drinking water is another possible benefit of the rule. This proposed 
rule will also reduce 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 we are 
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, and reduced vegetation impairment from 
ozone.
1. 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. Together these emissions are deposited 
onto terrestrial and aquatic ecosystems across the U.S., contributing 
to the problems of acidification, nutrient enrichment, and 
methylmercury production. In addition, NOX is a precursor to 
ozone, which can impair vegetation.
a. Acid Deposition and Acidification of Lakes and Streams
    The extent of adverse effects of acid deposition on freshwater and 
forest ecosystems depends largely upon the ecosystem's ability to 
neutralize the acid. The neutralizing ability [key indicator is termed 
Acid Neutralizing Capacity (ANC)] depends largely on the watershed's 
physical characteristics, such as geology, soils, and size. 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

[[Page 45350]]

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 in the 
transport region and is likely to have positive effects on the health 
and productivity of aquatic ecosystems in the region.
b. 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 (U.S. EPA, 
2008f). 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 (Joslin et al., 
1992), leading to increased mortality of canopy trees.
    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 for 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., and 
acidifying deposition has been implicated as a causal factor (DeHayes 
et al., 1999).
    This regulatory action will decrease acid deposition in the 
transport region and is likely to have positive effects on the health 
and productivity of forest systems in the region.
c. 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 N and phosphorus, and 
a majority of these estuaries are located in the coastal area from 
North Carolina to Massachusetts (NOAA, 2007). For estuaries in the Mid-
Atlantic region, the contribution of atmospheric distribution to total 
N loads is estimated to range between 10 percent and 58 percent 
(Valigura et al., 2001).
    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 in the 
Transport Rule region. Thus, reductions in the levels of nitrogen 
deposition will have a positive impact upon current eutrophic 
conditions in estuaries and coastal areas in the region.
d. Mercury Methylation and Deposition
    Mercury is a highly neurotoxic contaminant that enters the food web 
as a methylated compound, methylmercury (U.S. EPA, 2008d). 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 (Drevnick et al., 2007; Munthe et 
al., 2007). The SO2 ISA (U.S. EPA, 2008) concluded that 
evidence is sufficient to infer a casual relationship between sulfur 
deposition and increased mercury methylation in wetlands and aquatic 
environments.
2. Ozone Vegetation Effects
    Ozone causes discernible injury to a wide array of vegetation (U.S. 
EPA, 2006; Fox and Mickler, 1996). In terms of forest productivity and 
ecosystem diversity, ozone may be the pollutant with the greatest 
potential for regional-scale forest impacts (U.S. EPA, 2006). Studies 
have demonstrated repeatedly that ozone concentrations commonly 
observed in polluted areas can have substantial impacts on plant 
function (De Steiguer et al., 1990; Pye, 1988).
    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

[[Page 45351]]

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 (Chappelka and 
Samuelson, 1998). 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 (Heck, 1997).
    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 (U.S. EPA, 2007). 
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 
(U.S. EPA, 2007). 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 (Abt 
Associates, 1995).
3. Other Health or Welfare Disbenefits of the Transport Rule That Have 
Not Been Quantified
    In contrast to the additional benefits of the proposed rule 
discussed above, it is also possible that this rule will result in 
disbenefits in some areas of the region. Current levels of nitrogen 
deposition in these areas may provide passive fertilization for forest 
and terrestrial ecosystems where nutrients are a limiting factor and 
for some croplands. The effects of ozone and PM on radiative transfer 
in the atmosphere can also lead to effects of uncertain magnitude and 
direction on the penetration of ultraviolet light and climate. Ground 
level ozone makes up a small percentage of total atmospheric ozone 
(including the stratospheric layer) that attenuates penetration of 
ultraviolet-b (UVb) radiation to the ground. The EPA's past evaluation 
of the information indicates that potential disbenefits would be small, 
variable, and with too many uncertainties to attempt quantification of 
relatively small changes in average ozone levels over the course of a 
year (EPA, 2005a). The EPA's most recent provisional assessment of the 
currently available information indicates that potential but 
unquantifiable benefits may also arise from ozone-related attenuation 
of UVb radiation (EPA, 2005b). Sulfate and nitrate particles also 
scatter UVb, which can decrease exposure of horizontal surfaces to UVb, 
but increase exposure of vertical surfaces. In this case as well, both 
the magnitude and direction of the effect of reductions in sulfate and 
nitrate particles are too uncertain to quantify (EPA, 2004). Ozone is a 
greenhouse gas, and sulfates and nitrates can reduce the amount of 
solar radiation reaching the earth, but EPA believes that we are unable 
to quantify any net climate-related disbenefit or benefit associated 
with the combined ozone and PM reductions in this rule.
    Additionally, from analyses of the benefits of the Acid Rain 
Program, EPA has seen that substantial health and environmental 
benefits that are likely to occur for Canadians because 80 percent of 
the Canadian population lives within 40 miles of the US-Canada border.

Table IX-6--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 (+/-) \c\.
PM: welfare..........................  Household soiling.
                                       Visibility in residential and non-
                                        class I areas.
                                       UVb exposure (+/-) \c\.
                                       Global climate impacts \c\.
Ozone: health........................  Chronic respiratory damage.
                                       Premature aging of the lungs.
                                       Non-asthma respiratory emergency
                                        room visits.
                                       Increased exposure to UVb (+/-)
                                        \c\.
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 (+/-)
                                        \c\.
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.
                                       Commercial fishing, agriculture
                                        and forestry from nutrient
                                        deposition.
                                       Recreation in terrestrial and
                                        estuarine ecosystems from
                                        nutrient deposition.

[[Page 45352]]


                                       Other ecosystem services and
                                        existence values for currently
                                        healthy ecosystems.
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.
                                       Recreation in terrestrial and
                                        aquatic ecosystems from acid
                                        deposition.
                                       Increased mercury methylation.
------------------------------------------------------------------------
\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\ Cohort estimates are designed to examine the effects of long term
  exposures to ambient pollution, but relative risk estimates may also
  incorporate some effects due to shorter term exposures (see Kunzli et
  al. (2001) for a discussion of this issue). While some of the effects
  of short term exposure are likely to be captured by the cohort
  estimates, there may be additional premature mortality from short term
  PM exposure not captured in the cohort estimates included in the
  primary analysis.
\c\ May result in benefits or disbenefits.

X. Economic Impacts

    For the affected region, the projected annual private incremental 
costs of the proposed remedy option to the power industry are $3.7 
billion in 2012 and $2.8 billion in 2014. For the State Budgets/
Intrastate Trading remedy, projected annual private incremental costs 
are $4.2 billion in 2012 and $2.7 billion in 2014. Finally, for the 
direct control remedy, the projected annual private incremental costs 
are $4.3 billion in 2012 and $3.4 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 2006 
dollars.
    In estimating the net benefits of regulation, the appropriate cost 
measure is ``social costs.'' Social costs represent the welfare costs 
of the rule to society. These costs do not consider transfer payments 
(such as taxes) that are simply redistributions of wealth. The social 
costs of this rule for the proposed remedy option are estimated to be 
approximately $2.0 billion in 2014 assuming a 3 percent discount rate. 
These costs become $2.2 billion in 2014 assuming a 7 percent discount 
rate. For the State Budgets/Intrastate Trading remedy, social costs are 
estimated to be approximately $2.5 billion in 2014 assuming a 3 percent 
discount rate and $2.7 billion in 2014 assuming a 7 percent discount 
rate. Finally, for the direct control remedy, social costs are 
estimated to be approximately $2.7 billion in 2014 assuming a 3 percent 
discount rate and $2.9 billion in 2014 assuming a 7 percent discount 
rate.
    Overall, the economic impacts of the Transport Rule proposal are 
modest in 2014, particularly in light of the large benefits ($122 to 
$294 billion annually at a 3 percent discount rate and $111 to $266 
billion annually at a 7 percent discount rate) we expect as shown 
earlier in this preamble (see section IX for more details). 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 proposal, please refer 
to section XII.H (Statement of Energy Effects) later in this preamble.
    For this proposed 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. Analysis of impacts on affected industries outside of the 
electric power generating sector are estimated by the Economic Model 
for Policy Analysis (EMPAX), a dynamic model that can generate price 
and output changes for output affected by electricity price changes due 
to air pollution control policies and also estimates of social costs 
associated with such policies. Documentation for EMPAX can be found in 
the docket for this rulemaking or at http://www.epa.gov/ttn/ecas/
EMPAX.htm.
    Also note that as explained in section IV.A.3, the baseline used in 
this analysis assumes no CAIR. If EPA's base case analysis were to 
assume that reductions from CAIR would continue indefinitely, areas 
that are in attainment solely due to controls required by CAIR would 
again face nonattainment problems because the existing protection from 
upwind pollution would not be replaced. 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).

XI. Incorporating End-Use Energy Efficiency Into the Proposed Transport 
Rule

A. Background

    EPA believes that achievement of energy efficiency improvements in 
homes, buildings, and industry is an important component of achieving 
emissions 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 rule. While all remedy options considered--including 
the proposed remedy (State Budgets/Limited Trading)--will lead to a 
modest increase in the relative cost-effectiveness of energy efficiency 
investments by internalizing environmental costs associated with these 
pollutants, EPA is interested in considering additional means by which 
energy efficiency can be encouraged through this proposed rule.
1. What is end-use energy efficiency?
    End-use energy efficiency (hereafter, ``energy efficiency'') in the 
context of this proposed rule refers to activities that reduce the 
demand for electricity from EGUs in affected states. Energy

[[Page 45353]]

efficiency improvements are pursued through the efforts of state 
agencies, independent program administrators (e.g. Vermont Energy 
Investment Corporation), electric utilities, energy service companies, 
and other commercial entities. Examples of common energy efficiency 
projects include re-commissioning of commercial buildings, rebates for 
energy efficient appliances, and home energy audits.
2. How does energy efficiency contribute to cost-effective reductions 
of air emissions from EGUs?
    EPA recognizes that significant opportunity remains 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 Act, including ENERGY STAR, are 
designed to address these barriers.
    By reducing the demand for electricity energy efficiency reduces 
the need for investments in EGU emissions control technologies in order 
to meet the limits of an established state emissions budget and can 
often be implemented at a lower cost than traditional control 
technologies. Section III.E in this preamble further discusses the 
importance of electricity demand reductions as a component of EPA's 
broader air quality improvement strategy for the power sector.
    EPA is available to assist states in quantifying the reduction in 
compliance costs of air regulatory programs, including the proposed 
rule, that can be realized through effective energy efficiency policies 
and programs.
3. How does the proposed rule support greater investment in energy 
efficiency?
    By requiring reductions in the emissions of NOX and 
SO2 from power plants in affected states, a transport rule 
will lead to the internalization of costs associated with reducing the 
environmental effects of these pollutants. Since the economics of 
energy efficiency investments are directly related to power generation 
costs, this will improve the relative cost-effectiveness of these 
investments. Over time, this effect is expected to lead to increases in 
energy efficiency investments and associated benefits.
4. How have EPA and states previously integrated energy efficiency into 
air regulatory programs?
    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 
projects through either the award of emissions allowances, typically 
through the use of a fixed set-aside pool, or the use of revenues 
obtained through the auction of emissions allowances. The emissions 
caps established by these programs are unaffected by this approach, 
however, compliance costs are reduced (to the extent electricity demand 
reductions are realized) as are the emissions of non-capped pollutants 
from affected EGUs. In addition to these allowance-based programs, EPA 
has also established, through Guidance,\116\ a means for recognizing 
the emissions benefits of energy efficiency in SIPs and has approved 
their use in individual state plans.
---------------------------------------------------------------------------

    \116\ U.S. EPA. 2004. Guidance on State Implementation Plan 
(SIP) Credits for Emission Reductions From Electric-Sector Energy 
Efficiency and Renewable Energy Measures. August. http://
www.epa.gov/ttn/oarpg/t1/memoranda/ereseerem_gd.pdf.
---------------------------------------------------------------------------

B. Incorporating End-Use Energy Efficiency Into the Transport Rule

    As discussed previously, EPA believes that increasing end-use 
energy efficiency can be an effective approach for reducing compliance 
costs of the proposed rule, as well as for reducing EGU emissions that 
are not the target of this rule including mercury, other toxics, and 
carbon dioxide. While EPA believes the proposed rule will make energy 
efficiency investments more competitive, the Agency is seeking comments 
on additional ways in which this rule could further encourage these 
investments.
1. Options that Could Be Used To Incorporate Energy Efficiency Into 
Allowance Based Programs
    As discussed previously, allowance-based programs (such as the 
proposed State Budgets/Limited Trading remedy and the alternative State 
Budgets/Intrastate Trading remedy) of EPA and states have supported 
energy efficiency projects through the use of auction revenues or the 
award of allowances. EPA considered these options in developing this 
proposal but, for the reasons described later, decided not to include 
either option in this proposal.
2. Why did EPA not propose these options?
    The emissions reductions requirements of the proposed rule are 
implemented through proposed FIPs. This means, among other things, that 
EPA allocates the emission allowances directly to individual sources. 
In contrast, when allowance based programs are implemented through 
SIPs, states may have significant flexibility to determine the 
methodology used to allocate or auction allowances in their budgets. 
Under the proposed FIPs, EPA would allocate allowances to sources in a 
manner consistent with the methodology used to determine each state's 
budget. EPA believes this approach is appropriate because of the link 
between the allowance allocation methodology and the significant 
contribution determinations. EPA requests comment on whether EPA has 
authority to and whether it would be appropriate for EPA to consider 
energy efficiency considerations in developing the allowance allocation 
methodology.
    In addition, because the emission reduction requirements are 
implemented through FIPs, any auction of allowances would be conducted 
by EPA. As discussed previously in section V.D.5.b, pursuant to the 
Miscellaneous Receipts Act, any revenues from a federal auction of 
allowances must go to the U.S. Treasury. This precludes the use of 
proceeds from such an auction to reward energy efficiency projects.
    In addition, and as also discussed previously in sections III.A and 
III.B.3, EPA anticipates further revisions to the PM2.5 and 
ozone NAAQS and intends to issue subsequent proposals to address the 
interstate transport requirements of section 110(a)(2)(D)(i)(I) with 
respect to those new NAAQS. The emissions reductions requirements 
identified in any such rules could be implemented through SIPs. The SIP 
process could give states significant flexibility in regards to 
allocation and auctioning of allowances. This flexibility could be used 
by states to support energy efficiency projects through the use of 
auction revenues or the award of allowances.
    EPA is seeking comment on the discussion within this section and 
the use of these and other approaches for encouraging energy efficiency 
within the proposed rule.

XII. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

    Under section 3(f)(1) of Executive Order 12866 (58 FR 51735, 
October 4,

[[Page 45354]]

1993), this action is an ``economically significant regulatory action'' 
because it is likely to have an annual effect on the economy of $100 
million. Accordingly, EPA submitted this action to the Office of 
Management and Budget (OMB) for review under EO 12866 and any changes 
made in response to OMB recommendations have been documented in the 
docket for this action. In addition, EPA prepared a Regulatory Impact 
Analysis (RIA) of the potential costs and benefits associated with this 
action.
    When estimating the PM2.5- and ozone-related human 
health benefits and compliance costs in Table 1 below, 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 the preferred and 
alternate Transport Rule remedies considered by the Agency. The 
Regulatory Impacts Analysis (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.
    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 (ISA) 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 rule, rather than segmenting out impacts predicted to 
be associated levels above and below a `bright line' threshold, EPA 
includes a ``lowest-measured-level (LML)'' that illustrates the 
increasing uncertainty that characterizes impacts attributed to levels 
of PM2.5 below the LML for each study. Figure 5-19 shows the 
distribution of avoided PM mortality impacts predicted relative to the 
baseline (i.e. pre-Transport Rule) PM2.5 levels experienced 
by the population receiving the PM2.5 mortality benefit in 
2014 (Figure 5-19). This figure also shows the lowest air quality 
levels measured in each of the two primary epidemiological studies EPA 
uses to quantify PM-related mortality. This information allows readers 
to determine the 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 decreases in areas where annual mean PM2.5 levels 
are further below the LML in the two epidemiological studies. In this 
analysis, we see that about 80% of the estimated benefits accrue among 
populations exposed to annual mean PM2.5 levels above 10ug/
m3 (the LML in the Six Cities study) and 97% of the estimated benefits 
are associated with PM levels above 7.5 mg/m3 (the LML in the American 
Cancer Society study used for this analysis). While 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.
    Table XII.A-1 shows the results of the cost and benefits analysis 
for the proposed and alternate remedies.

 Table XII.A-1--Summary of Annual Benefits, Costs, and Net Benefits of Versions of the Proposed Remedy Option in
                                                    2014 \a\
                                               [Billions of 2006$]
----------------------------------------------------------------------------------------------------------------
                                        Preferred remedy-State
             Description               budgets/limited trading       Direct control         Intrastate trading
----------------------------------------------------------------------------------------------------------------
Social costs \b\
    3% discount rate.................  $2.03..................  $2.68..................  $2.49.
    7% discount rate.................  $2.23..................  $2.91..................  $2.70.
Health-related benefits \c,d\
    3% discount rate.................  $118 to $288 + B.......  $117 to $286 + B.......  $113 to $276 + B.
    7% discount rate.................  $108 to $260 + B.......  $108 to $262 + B.......  $104 to $252 + B.
Net benefits (benefits-costs)
    3% discount rate.................  $116 to $286...........  $115 to $283...........  $110 to $273.
    7% discount rate.................  $105 to $258...........  $105 to $259...........  $101 to $249.
----------------------------------------------------------------------------------------------------------------
Notes: (a) All estimates are rounded to three significant digits and represent annualized benefits and costs
  anticipated for the year 2014. For notational purposes, unquantified benefits are indicated with a ``B'' to
  represent the sum of additional monetary benefits and disbenefits. Data limitations prevented us from
  quantifying these endpoints, and as such, these benefits are inherently more uncertain than those benefits
  that we were able to quantify. A listing of health and welfare effects is provided in RIA Table 1-6. Estimates
  here are subject to uncertainties discussed further in the body of the document. (b) The social costs are the
  loss of household utility as measured in Hicksian equivalent variation. (c) The reduction in premature
  mortalities account for over 90% of total monetized benefits. Benefit estimates are national. Valuation
  assumes discounting over the SAB-recommended 20-year segmented lag structure described in Chapter 5. Results
  reflect 3 percent and 7 percent discount rates consistent with EPA and OMB guidelines for preparing economic
  analyses (U.S. EPA, 2000; OMB, 2003). The estimate of social benefits also includes CO2-related benefits
  calculated using the social cost of carbon, discussed further in chapter 5. Benefits are shown as a range from
  Pope et al. (2002) to Laden et al. (2006). Monetized benefits do not include unquantified benefits, such as
  other health effects, reduced sulfur deposition or visibility. These models assume that all fine particles,
  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. (d) Not all possible benefits or disbenefits are quantified and monetized in this analysis. B is the sum
  of all unquantified benefits and disbenefits. Potential benefit categories that have not been quantified and
  monetized are listed in RIA Table 1-4.

B. Paperwork Reduction Act

    The information collection requirements in the proposed rule have 
been submitted for approval to OMB under the Paperwork Reduction Act, 
44 U.S.C. 3501 et seq. The information collection requirements are not 
enforceable until OMB approves them.
    The information collection activities in this proposed rule include 
monitoring and the maintenance of records. The information generated by 
these activities will be used by EPA to ensure that affected facilities 
comply with the emission limits and other requirements. Records and 
reports are necessary to enable EPA or states to identify affected 
facilities that may not be in compliance with the requirements. Based 
on reported information, EPA

[[Page 45355]]

will decide which units and what records or processes should be 
inspected. 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. These recordkeeping and reporting requirements are 
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.
    The record-keeping and reporting burden to sources resulting from 
states choosing to participate in a regional cap-and-trade program is 
approximately $28 million annually. This estimate includes the 
annualized cost of installing and operating appropriate SO2 
and NOX emissions monitoring equipment to measure and report 
the total emissions of these pollutants from affected EGUs (serving 
generators greater than 25 megawatt electrical). The burden to state 
and local air agencies includes any necessary SIP revisions, 
performance of monitoring certification, and fulfilling of audit 
responsibilities. More information on the ICR analysis is included in 
the proposed Transport Rule docket. Burden is defined at 5 CFR 
1320.3(b).
    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 proposed 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 (MW-hr) 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
------------------------------------------------------------------------
                                   NAICS       Examples of potentially
            Category               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....................   c 221112  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.

    After considering the economic impacts of this proposed rule on 
small entities, EPA is certifying that this action will not have a 
significant economic impact on a substantial number of small entities. 
This certification is based on the economic impact of this proposed 
action to all affected small entities across all industries affected. 
EPA has assessed the potential impact of this action on small entities 
and found that approximately 550 of the estimated 4,700 EGUs 
potentially affected by today's proposal are owned by the 81 
potentially affected small entities identified by EPA's analysis. EPA 
estimates that 30 of the 81 identified small entities will have 
annualized costs greater than 1 percent of their revenues, and the 
other 51 are projected to incur costs less than 1 percent of revenues. 
While there are costs greater than 1 percent of revenues for a number 
of small entities, EPA is certifying No SISNOSE for several reasons. 
First, of the 30 entities projected to have costs greater than 1 
percent of revenues, around 75 percent of them operate in cost of 
service regions and would generally be able to pass any increased costs 
along to rate-payers. This is one of the primary reasons given in the 
Regulatory Impact Assessment for the Final Clean Air Interstate Rule 
(EPA-452/R-05-002 March 2005) that supported EPA's ``No SISNOSE'' 
certification in the final CAIR FIP rule on April 28, 2006 (71 FR 
25366). Furthermore, of the approximately 550 units identified by EPA 
as being potentially owned by small entities, approximately two-thirds 
of the units that have higher costs are not expected to make 
operational changes as a result of this rule (e.g., install control 
equipment or switch fuels). Their increased costs are largely due to 
increased cost of the fuel they would be expected to use whether or not 
they had to comply with the proposed rule. Further, increased fuel 
costs are often passed through to rate-payers as common practice in 
many areas of the United States due to fuel adder arrangements 
instituted by state public utility commissions. In addition, EPA's 
decision to exclude units smaller than 25 MWe has already significantly 
reduced the burden on small entities. Hence, EPA has concluded that 
there is no SISNOSE for this rule.
    For more information on the small entity impacts associated with 
the proposed rule, please refer to the Economic Impact and Small 
Business Analyses in the public docket. These analyses can be found in 
the Regulatory Impact Analysis for this proposed rule. Finally, 
although EPA believes that the proposed rule would not have a 
significant economic impact on a

[[Page 45356]]

substantial number of small entities, EPA plans to take steps to 
conduct meetings with industry trade associations to discuss regulatory 
options and ensure that the burdens imposed on small entities are 
minimal.
    We continue to be interested in the potential impacts of the 
proposed rule on small entities and welcome comments on issues related 
to such impacts.

D. Unfunded Mandates Reform Act of 1995

    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 one year. Accordingly, EPA has 
prepared under section 202 of the UMRA a written statement which is 
summarized later.
    Consistent with section 205, EPA has identified and considered a 
reasonable number of regulatory alternatives. In today's action, EPA 
has included three remedy options that it considered when developing 
this proposed rule: (1) The proposed remedy of State Budgets/Limited 
Trading, (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 their emissions. 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.
    According to EPA's analysis, of the 84 government entities 
considered in this analysis and the 482 government entities in the 
Transport Rule region that are included in EPA's modeling, 27 may 
experience compliance costs in excess of 1 percent of revenues in 2014, 
based on our assumptions of how the affected states implement control 
measures to meet their emissions budgets as set forth in this 
rulemaking.
    Government entities projected to experience compliance costs in 
excess of 1 percent of revenues have some potential for significant 
impact resulting from implementation of the Transport Rule. However, as 
noted previously, it is EPA's position that because these government 
entities can pass on their costs of compliance to rate-payers, they 
will not be significantly affected. Furthermore, the decision to 
include only units greater than 25 MW in size exempts 380 government 
entities that would otherwise be potentially affected by the Transport 
Rule. For more information on the impacts estimated for this analysis, 
please refer to the RIA for this proposed rule.
    In addition, before EPA establishes any regulatory requirements 
that may significantly or uniquely affect small governments, including 
tribal governments, it must have developed under section 203 of the 
UMRA, a small government agency plan. The plan must provide for 
notifying potentially affected small governments, enabling officials of 
affected small governments to have meaningful and timely input in the 
development of EPA regulatory proposals with significant Federal 
intergovernmental mandates, and informing, educating, and advising 
small governments on compliance with the regulatory requirements. 
Consistent with the intergovernmental consultation provisions of 
section 204 of the UMRA, EPA has initiated consultations with 
governmental entities affected by this rule.
    The 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.

E. Executive Order 13132: Federalism

    This proposed 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 proposed 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 proposed rule.
    In the spirit of Executive Order 13132, and consistent with EPA 
policy to promote communications between EPA and state and local 
governments, EPA will specifically solicit comment on the proposed rule 
from state and local officials.

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

    This action does not have tribal implications, as specified in 
Executive Order 13175 (65 FR 67249, November 9, 2000). It will not have 
substantial direct effects on tribal governments, on the relationship 
between the Federal government and Indian tribes, or on the 
distribution of power and responsibilities between the federal 
government and Indian tribes, as specified in Executive Order 13175. 
Thus, Executive Order 13175 does not apply to the final rule.

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

    EPA interprets Executive Order 13045 (62 FR 19885, April 23, 1997) 
as applying to those regulatory actions that concern health or safety 
risks, such that the analysis required under section 5-501 of the Order 
has the potential to influence the regulation. 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. The EPA believes that the emissions reductions from 
the strategies in this rule will further improve air quality and will 
further improve children's health.

H. Executive Order 13211: Actions That Significantly Affect Energy 
Supply, Distribution, or Use

    Executive Order 13211 (66 FR 28355, May 22, 2001) provides that 
agencies shall prepare and submit to the Administrator of the Office of 
Regulatory Affairs, OMB, a Statement of Energy Effects for certain 
actions identified as ``significant energy actions.'' Section 4(b) of 
Executive Order 13211 defines ``significant energy

[[Page 45357]]

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 proposed rule is a significant regulatory action under 
Executive Order 12866, and this proposed rule may have a significant 
adverse effect on the supply, distribution, or use of energy.
    Under the provisions of this proposed rule, EPA projects that 
approximately 1.2 GW of 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. 
Assumptions of higher natural gas prices or electricity demand would 
create a greater incentive to keep these units operational. The EPA 
projects that the average retail electricity price could increase 
nationally by less than 2.5 percent in 2012 and 1.5 percent in 2014. 
This is generally less of an increase than often occurs with 
fluctuating fuel prices and other market factors. Related to this, 
delivered coal prices increase by about 7 percent in 2012 and 4 percent 
in 2014 as a result of higher demand for lower-sulfur coals. The EPA 
also projects that natural gas prices will increase by less than 1.7 
percent in 2012 and 0.5 percent in 2014 and that natural gas use for 
electricity generation will increase by less than 73 million mcf by 
2014. The price increase is also within the range we regularly see in 
delivered natural gas prices. Finally, the EPA projects coal production 
for use by the power sector, a large component of total coal 
production, will decrease by 3 million tons in 2012 and 9 million tons 
in 2014. The EPA does not believe that this rule will have any other 
impacts that exceed the significance criteria.
    The EPA believes that a number of features of the proposed 
rulemaking serve to reduce its impact on energy supply. First, the 
trading programs in State Budgets/Limited Trading provide considerable 
flexibility to the power sector and enable industry to comply with the 
emission reduction requirements in the most cost-effective manner, thus 
minimizing overall costs and the ultimate impact on energy supply. 
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 proposed Transport Rule.

I. National Technology Transfer and 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 proposed rule would 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.
1. Consideration of Environmental Justice Issues in the Rule 
Development Process
    In the rulemaking process, EPA considers whether there are positive 
or negative impacts of the action that appear to affect low-income, 
minority, or Tribal communities disproportionately, and, regardless of 
whether a disproportionate effect exists, whether there is a chance for 
these communities to meaningfully participate in the rulemaking 
process. EPA expects that this rule, ``Federal Implementation Plans to 
Reduce Interstate Transport of Fine Particulate Matter and Ozone,'' 
will provide significant health and environmental benefits to, among 
others, people with asthma, people with heart disease, and people 
living in ozone or fine particle (PM2.5) nonattainment 
areas. This rule also has the potential to affect the cost structure of 
the utility industry and could lead to regional shifts in electricity 
generation and/or emissions of various pollutants. Therefore we expect 
this rule to be of interest to many environmental justice communities. 
EPA's analysis of the effects of this proposed rule, including 
information on air quality changes and the resulting health benefits, 
is presented both in section IX of this preamble and in more detail in 
the air quality modeling Technical Support Document and 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 
Web page for the rule http:// www.epagov/airtransport. This section 
summarizes the legal basis for this rule, and provides background 
information on how this rule fits into the larger regulatory strategy 
for controlling

[[Page 45358]]

pollution from the power sector. A summary of the emissions, air 
quality, and health benefit estimates for this rule then follows.
    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. CAIR 
was vacated by the U.S. Court of Appeals for the District of Columbia 
Circuit in July 2008 in a case known as North Carolina v. EPA. In 
December 2008, the vacatur was altered to a remand based on the likely 
environmental harms of vacating the rule and EPA's stated intent to 
replace the rule promptly. At the time of the 2008 court ruling, many 
sources had already begun to install and run emissions control devices 
or otherwise alter their operations and had successfully begun reducing 
their emissions. The court decision has led to significant uncertainty 
among affected sources as to what emissions reductions will be required 
and among states and communities as to what air quality benefits will 
be achieved. By proposing this aggressive replacement rule that meets 
the legal requirements of the CAA as interpreted by the Court in the 
North Carolina decision promptly, EPA is both maximizing the likelihood 
that the goals of the CAA will be met, and helping communities receive 
the air quality benefits they need as quickly as possible by minimizing 
the chance that any emissions reductions achieved under CAIR would be 
lost.
    It is important to note that CAA section 110(a)(2)(d), which 
addresses transport of criteria pollutants between states and is the 
authority for this rule, 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 environmental justice communities, and provide 
substantial health benefits to both the general public and sensitive 
sub-populations.
    This proposed rule is one of a group of regulatory actions that EPA 
will take over the next several years to respond to statutory and 
judicial mandates that will reduce exposure to ozone and 
PM2.5, as well as to other pollutants, from power plants and 
other sources. To the extent that EPA has the legal authority to do so 
while fulfilling its obligations under the CAA and other relevant 
statutes, we will also coordinate these utility-related air pollution 
rules with upcoming regulations for the power sector from EPA's Office 
of Water (OW) and its Office of Resource Conservation and Recovery 
(ORCR). The primary actions are outlined below and presented in more 
detail in section III.E of this preamble.
    Beyond this action and any additional efforts undertaken in 
response to comment, other rules that will drive the creation of a 
clean, efficient and completely modern power sector include: CAA 
section 112(d) standards (one of which is often referred to as a 
Maximum Achievable Control Technology (MACT) standard) to reduce 
emissions of air toxics, including mercury, and particles from coal- 
and oil-fired power plants; new National Ambient Air Quality Standards 
(NAAQS) for ozone, PM2.5, sulfur dioxide, and nitrogen 
oxides; potentially one or more additional rules eliminating interstate 
transport of emissions that contribute significantly to nonattainment 
and maintenance areas for the new ozone and PM2.5 NAAQS as 
necessary; revisions to the New Source Performance Standards (NSPS) for 
steam electric generating units; and best available retrofit technology 
(BART) requirements and other requirements that address visibility and 
regional haze. Within the planning and investment horizon for 
compliance with these rules, EPA very likely will be compelled to 
respond to a pending petition to set standards for the emissions of 
greenhouse gases (GHGs) from steam electric generating units under the 
New Source Performance Standard program. Furthermore, as set forth in 
the recently promulgated reinterpretation of the Johnson Memo, 
beginning in 2011 new and modified sources of GHG emissions, including 
EGUs, will be subject to permits under the Prevention of Significant 
Deterioration program requiring them to adopt Best Available Control 
Technology for their GHGs. Finally, 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 
that the Agency wants to provide while lowering the costs of realizing 
those improvements.
    Together, these rules and actions 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 intends to provide multiple 
opportunities for comment on these actions, including during the 
comment process for this rule, and encourages environmental justice 
communities to review and comment on them.
2. Potential Environmental and Public Health Impacts to Vulnerable 
Populations
    There are several considerations to take into account when 
assessing the effects of this proposed rule on minority, low-income, 
and tribal populations. These include: Amount of emissions reductions 
and where they take place (including any potential for areas of 
increased emissions); the changes in ambient concentrations across the 
affected area; and the health benefits expected from the rules.
    Emissions reductions. This proposed rule will reduce exposure to 
PM2.5 and ozone pollution in most eastern states by reducing 
interstate transport of these pollutants and their chemical precursors 
(sulfur dioxide (SO2) and nitrogen oxides (NOX)). 
This rule has the effect of reducing emissions of these pollutants that 
affect the most-contaminated areas (i.e. areas that are not meeting the 
1997 and 2006 ozone and PM2.5 National Ambient Air Quality 
Standards (NAAQS)). This rule separately identifies both nonattainment 
areas and maintenance areas (maintenance areas are those that currently 
meet the NAAQS but that, based on past data, are in danger of exceeding 
the standards in the future). This approach of requiring emissions 
reductions to protect maintenance areas as well as nonattainment areas 
reduces the likelihood that any areas close to the level of the 
standard will exceed the current health-based standards in the future.
    Ozone and PM2.5 concentrations in both nonattainment and 
maintenance areas identified in this rule are the result of both local 
emissions and long-range transport of pollution. This rule requires 
upwind states to reduce or eliminate their significant contribution to 
nonattainment or maintenance problems in downwind states. Even when the 
significant contributions of upwind states are fully eliminated, 
additional emissions reductions within the nonattainment area and/or 
the downwind state will be needed for some areas to attain and maintain 
the NAAQS.
    The proposed remedy option for this rule would use a limited 
emissions trading mechanism among power plants to achieve significant 
emissions reductions in states covered by the rule. EPA recognizes that 
many environmental justice communities have voiced concerns about 
emissions trading and any resulting potential for any emissions 
increases in any location.

[[Page 45359]]

    This proposed rule uses EPA's authority in CAA Sec.  110(a)(2)(d) 
to require states to eliminate emissions from power plants in their 
state that contribute significantly to downwind PM2.5 or 
ozone nonattainment or maintenance areas. EPA's proposed mechanism for 
achieving these emissions reductions is to use a tightly constrained 
trading program that requires a strict emission ceiling in each state 
while allowing a limited ability to shift emissions between facilities 
or states. This approach ensures that emissions in each state that 
significantly contribute to downwind nonattainment or maintenance areas 
are controlled, while allowing power companies to adjust generation 
based on fluctuations in electricity demand, weather, availability of 
low-emitting power sources (e.g. temporary shut-down of a nuclear power 
plant for maintenance or repairs), or other unanticipated factors 
affecting the interconnected electricity grid.
    Any emissions above the state's allocated level must be offset by 
emissions reductions from another state in the region below that 
state's budget or by using extra ``banked'' allowances from earlier 
years. All sources must hold enough allowances to cover their 
emissions; therefore, if they emit more than their allocation they must 
buy allowances from another source that emitted less than its 
allocation. 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 emissions 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 recognize that the section of the Clean Air Act 
providing authority for this rule, 110(a)(2)(D), unlike some other 
provisions, does not dictate levels of control for particular 
facilities. None of EPA's alternatives within this proposal can ensure 
there will be no emission increases at any facility. Under the direct 
control alternative, the emissions rate for each facility is reduced 
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, state emissions must stay constant but 
individual facilities within each state could increase their emissions 
as long as another facility in the state had decreased theirs. By 
strictly setting state budgets to eliminate significant contributions 
to non-attainment and maintenance areas that EPA has identified in this 
action, by limiting the amount of interstate trading possible and by 
requiring any emissions above the level of the allocations to be offset 
by emission decreases elsewhere in the region, the proposed remedy 
options reduce ambient concentrations where they are most needed.
    EPA's emissions modeling data indicate that nationwide 
SO2 emissions from electric generating units (EGUs) will be 
approximately 6.4 million tons (60 percent) lower in 2014 than they 
were in 2005 (which is the year that the Clean Air Interstate Rule was 
finalized). Emissions would also decrease when compared to the base 
case (the base case estimates of SO2 emissions in 2014 in 
the absence of this proposed rule or the Clean Air Interstate Rule it 
is replacing). SO2 emissions under this proposed rule are 
projected to be approximately 4.4 million tons (50%) lower than they 
would have been in 2014 in the base case (i.e. without this rule).
    EPA's modeling does project that some states not covered by one or 
more aspects of the program may experience increases of SO2 
emissions (i.e., their emissions are greater in the control case 
modeling than in the base case modeling). These emission increases are 
the result of forecasted changes in operation of units outside of the 
controlled region (due to the interconnected nature of the utility grid 
or influence of the rule on the market for lower sulfur coal). As shown 
in Table IV.D.6, Arkansas, Mississippi, North Dakota, South Dakota, and 
Texas all exhibit 2012 SO2 emissions increases over the base 
case of more than 5,000 tons. Texas is projected to have by far the 
largest increase (136,000 tons), while the other states' increases 
ranges from 6,000 to 32,000 tons. Further analysis with the simplified 
air quality assessment tool indicates that these projected increases in 
the Texas SO2 emissions would increase Texas's contribution 
to an amount that would exceed the 0.15 [mu]g/m3 threshold 
for annual PM2.5. For this reason, EPA requests comment on 
whether Texas should be included in the program as a group 2 state. For 
additional details, see section IV.D of this preamble.
    With the exception noted above, EPA is not proposing for the 
SO2 portion of this rule to cover the states where 
SO2 emissions are projected to increase because EPA has not 
found, at this time, that they contribute significantly to 
nonattainment or interfere with maintenance of the PM2.5 
NAAQS in downwind areas. EPA's authority under Sec.  110(a)(2)(d)(i)(I) 
is limited to addressing any such significant contribution and 
interference with maintenance. EPA anticipates that additional 
rulemakings affecting utilities that will be proposed soon, such as the 
CAA Section 112(d) standards, would apply nationwide and result in 
significant additional SO2 reductions.
    EPA's emissions modeling data indicates that nationwide ozone 
season NOX emissions from EGUs will be approximately 400,000 
tons (30%) lower in 2014 than they were in 2005 (before implementation 
of the Clean Air Interstate Rule). Emissions would also decrease 
compared to the base case. Ozone season NOX emissions from 
EGUs under this proposed rule are projected to be approximately 150,000 
tons (15%) lower than they would have been in 2014 in the base case 
(i.e. without this rule). EPA anticipates that additional upcoming 
actions, and likely additional interstate transport reductions to help 
states attain the proposed 2010 ozone NAAQS, will result in significant 
additional NOX reductions.
    EPA anticipates that this proposed action will significantly 
reduce, but not eliminate, the number of nonattainment and maintenance 
areas for the 1997 ozone and PM2.5 and 2006 PM2.5 
NAAQS. Table IX-1 lists the changes in number of nonattainment sites. 
Most of these sites are located in urban areas. A single nonattainment 
area usually contains multiple monitoring sites; therefore there are 
more nonattainment sites than nonattainment counties or areas. As 
discussed in detail in section IV.D of this preamble, where this 
proposal does not fully quantify all of the significant contribution 
and interference with maintenance, EPA intends to address these 
additional requirements quickly. To the extent possible, EPA will 
supplement this proposed notice with additional information so that we 
can provide downwind states with all the certainty about upwind 
emissions reductions they need to address their own local nonattainment 
concerns. In addition, as stated above, elimination of these 
nonattainment areas may require both local and regional emissions 
reductions and this proposed action seeks only to address the regional 
transport component.
    As a result of these SO2 and NOX reductions, 
EPA's air quality modeling indicates that concentrations of fine 
particles will decline throughout the eastern U.S. and in all the 
states affected by this rule. These reductions are largest in the area 
of the Ohio River valley and

[[Page 45360]]

neighboring states and extend east through New England, west to Texas, 
south to Florida, and north through the Great Lakes states. ``Border'' 
states immediately outside the transport region are also predicted to 
see reductions in air concentrations, even though emissions increase in 
some of these states. This is because concentrations of fine particles 
in most locations are composed of both local emissions and those 
transported over hundreds of miles and emissions reductions far away 
can cause significant improvements in local air quality.
    The modeling suggests also that there may be some small increases 
in PM2.5 near locations in the western U.S. where 
SO2 emissions are forecast to increase. These increases are 
small compared to the reductions predicted to take place in the eastern 
U.S. The increases are due to the regional nature of this rule (i.e. 
these states are not covered because sources in these states have not 
been found to contribute significantly to downwind nonattainment or 
maintenance areas) and the national nature of both coal markets and the 
Acid Rain Program allowance market. They are not the result of any 
particular type of remedy option (e.g. trading). EPA anticipates that 
future rulemakings, such as CAA section 112(d) standards and 
anticipated revisions to the 2006 fine particulate standards, are 
likely to reduce emissions in the areas not covered by this rule.
    EPA's air quality modeling also indicates that concentrations of 
ozone will decline in much of the eastern U.S. These reductions are 
largest along much of the Gulf Coast and in Florida and in a region 
encompassing western Wisconsin, Iowa, Kansas, Missouri, Arkansas, and 
northeastern Oklahoma. These areas with the largest reductions are 
roughly the area immediately outside the boundaries of the 
NOX SIP Call region. States in the SIP Call region were 
required to make significant reductions in NOX beginning in 
2003 and these emissions reductions are included in the baseline 
modeling for this proposed Transport Rule and therefore not captured as 
additional benefits of this rulemaking.
    As is common when modeling many NOX control strategies, 
the air quality modeling for this proposed rule also suggests there may 
be a few small, localized areas in the eastern U.S. where there are 
small increases in ozone concentrations. These generally small 
increases are a result of reductions in NOX emissions in 
these local areas; they do not appear to represent a lack of 
NOX emissions reductions or be the result of any specific 
emission control strategy (e.g. any type of trading). Rather, this 
phenomenon can result from complex atmospheric chemistry reactions 
taking place among chemical constituents of air pollution in these 
areas. Due to the complex photochemistry of ozone production, 
NOX emissions lead to both the formation and destruction of 
ozone, depending on the relative quantities of NOX, volatile 
organic compounds, and ozone formation catalysts. In the 2014 base 
case, NOX emissions from sources in a few locations act to 
``quench'' (i.e., lower) ozone compared to ozone concentrations in 
surrounding areas. The application of NOX controls in these 
areas reduces this quenching effect, thereby increasing ozone to levels 
generally on par with those of the surrounding area. In this case it is 
uncertain whether the structure of the model itself is potentially 
exacerbating the spatial extent or magnitude of any ozone increases 
which might actually occur as a result of this rule. It should be noted 
that these same NOX emissions reductions that might be 
causing extremely localized ozone increases are certainly causing 
larger, more widespread improvements in ozone concentrations in 
downwind areas. Finally, as stated above, it is important to note that 
EPA intends to promulgate additional rules over the next few years that 
will further reduce concentrations of ozone and PM2.5 and 
that the federal government and the states can and do use many 
different legal authorities to limit exposure to ozone.
    Health benefits. This rule reduces concentrations of 
PM2.5 and ozone pollution, exposure to which can cause, or 
contribute to, adverse health effects including premature mortality and 
many types of heart and lung diseases that affect many minority and 
low-income individuals, and Tribal 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 both heart disease and asthma are a cause for 
concern in many environmental justice communities, making these 
populations more susceptible to air pollution health impacts. In 
addition, many individuals in these communities also lack access to 
high quality health care to treat these illnesses.
    We estimate that in 2014 the PM-related annual benefits of the 
proposed remedy option include approximately 14,000 to 36,000 fewer 
premature mortalities, 9,200 fewer cases of chronic bronchitis, 22,000 
fewer non-fatal heart attacks, 11,000 fewer hospitalizations (for 
respiratory and cardiovascular disease combined), 10 million fewer days 
of restricted activity due to respiratory illness and approximately 1.8 
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 between 50 and 230 fewer 
premature mortalities, 690 fewer hospital admissions for respiratory 
illnesses, 230 fewer emergency room admissions for asthma, 300,000 
fewer days with restricted activity levels, and 110,000 fewer days 
where children are absent from school due to illnesses. When adding the 
PM and ozone-related mortalities together, we find that the proposed 
remedy option for this rule will yield between 14,000 and 36,000 fewer 
premature mortalities. EPA has also estimated the benefits of the 
alternate remedies in this proposal using a benefit-per-ton estimation 
approach and found they would provide similar benefits.
    It should be noted that, as discussed in the RIA for this action, 
there are other benefits to the emissions reductions discussed here, 
such as improved visibility and, indirectly, reduced mercury 
deposition. Additional benefits of reducing emissions of SO2 
include reduced acidification of lakes and streams, and reduced mercury 
methylation; additional benefits of NOX reductions include 
reduced acidification of lakes and streams and reduced coastal 
eutrophication. Conversely, it is possible that the modest increases in 
emissions modeled for this rule in some western areas could result in 
limited increases of one or more of these effects in these locations.
3. Meaningful Public Participation
    As EPA began considering approaches to address the court remand of 
the 2005 Clean Air Interstate Rule, the agency also began gathering 
input from a larger range of stakeholders. In the spring of 2009, EPA 
held a series of listening

[[Page 45361]]

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 entitled ``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 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 this 
proposal, as they took place prior to the development of this proposal, 
but they provided valuable information that EPA used in developing this 
proposal.
    Upon proposal of this action, the Agency will begin an outreach 
effort with environmental justice communities, the public, the 
regulated community, state air regulators, and others to (1) describe 
the Transport Rule proposal, (2) provide information on the 2011 CAA 
Section 112 (d) and other upcoming EPA rulemakings affecting the power 
sector, and (3) listen to comments from stakeholders. The intent will 
be to inform all stakeholders of the industry's obligations and 
opportunities for the industry to use investments in SO2 and 
NOX reductions to help smooth transition to the CAA Section 
112(d) standards compliance in late 2014. EPA intends to continue these 
efforts over time as more information becomes available in the 
development of the various rulemakings under development for the power 
sector.
    During the comment period for this proposed rule, EPA intends to 
reach out specifically to environmental justice communities and 
organizations to notify them of the opportunity to provide comments on 
this rule and to solicit their comments on both this rule and the 
upcoming actions described above and in section III.E. EPA will hold 
public hearings on this rule; see the information at the very beginning 
of this preamble for locations, times and dates. Comments can also be 
submitted in writing or electronically by following the instructions at 
the beginning of this preamble.
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 communities in both rural areas and inner cities in the 
East, will see significant improvements in air quality and resulting 
improvements in health. EPA also recognizes that there is the potential 
for a number of communities or individuals outside the region covered 
by this rule to experience slightly worse air quality as an indirect 
result of emissions reductions required under this proposal. EPA 
requests comment on the impacts of this proposed action on low income, 
minority, and Tribal communities. EPA will further analyze 
environmental justice issues related to the impacts of the rule on 
those communities based both on additional data that may be developed 
and on comments on those issues prior to final action on this rule.

List of Subjects

40 CFR Part 51

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

40 CFR Part 52

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

40 CFR Parts 72

    Acid rain, Administrative practice and procedure, Air pollution 
control, Electric utilities, 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, 2010.
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 
proposed to be amended as follows:

PART 51--[AMENDED]

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

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


Sec.  51.121  [Amended]

    2. Section 51.121 is amended by revising paragraph (r)(2) 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''.


Sec.  51.123  [Amended]

    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 AAA through III 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; 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.

[[Page 45362]]

Sec.  51.124  [Amended]

    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]

    5. Section 51.125 is removed and reserved.

PART 52--[AMENDED]

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

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

Subpart A--General Provisions


Sec.  52.35  [Amended]

    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; 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.


Sec.  52.36  [Amended]

    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.
    9. Subpart A is amended by adding Sec. Sec.  52.37 and 52.38 to 
read as follows:


Sec.  52.37  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 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, 
regarding the TR NOX Annual Trading Program, apply to the 
sources in the following States: Alabama, Connecticut, Delaware, 
District of Columbia, Florida, Georgia, Illinois, Indiana, Iowa, 
Kansas, Kentucky, Louisiana, Maryland, Massachusetts, Michigan, 
Minnesota, Missouri, Nebraska, New Jersey, New York, North Carolina, 
Ohio, Pennsylvania, South Carolina, Tennessee, Virginia, West Virginia, 
and Wisconsin.
    (3) Following promulgation of an approval by the Administrator of a 
State's SIP as correcting the SIP's deficiency that is the basis for 
this Federal Implementation Plan, 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 is partial or conditional.
    (4) Notwithstanding the provisions of paragraph (a)(3) of this 
section, if, at the time of such approval of the State's SIP, the 
Administrator has already allocated any TR NOX Annual 
allowances to sources in the State for any years, the provisions of 
part 97 of this chapter authorizing the Administrator to complete the 
allocation of TR NOX Annual allowances for those years shall 
continue to apply, unless provided otherwise by such approval of the 
State's SIP.
    (b)(1) The TR NOX Ozone Season Trading Program 
provisions of 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, 
regarding the TR NOX Ozone Season Trading Program, apply to 
sources in each of the following States: Alabama, Arkansas, 
Connecticut, Delaware, District of Columbia, Florida, Georgia, 
Illinois, Indiana, Kansas, Kentucky, Louisiana, Maryland, Michigan, 
Mississippi, New Jersey, New York, North Carolina, Ohio, Oklahoma, 
Pennsylvania, South Carolina, Tennessee, Texas, Virginia, and West 
Virginia.
    (3) Following promulgation of an approval by the Administrator of a 
State's SIP as correcting the SIP's deficiency that is the basis for 
this Federal Implementation Plan, 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 is partial or conditional.
    (4) Notwithstanding the provisions of paragraph (b)(3) of this 
section, if, at the time of such approval of the State's SIP, the 
Administrator has already allocated any TR NOX Ozone Season 
allowances to sources in the State for any years, the provisions of 
part 97 of this chapter authorizing the Administrator to complete the 
allocation of TR NOX Ozone Season allowances for those years 
shall continue to apply, unless provided otherwise by such approval of 
the State's SIP.

[[Page 45363]]

Sec.  52.38  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 and TR 
SO2 Group 2 Trading Program provisions 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, 
regarding the TR SO2 Group 1 Trading Program, apply to 
sources in each of the following States: Georgia, Illinois, Indiana, 
Iowa, Kentucky, Michigan, Missouri, New York, North Carolina, Ohio, 
Pennsylvania, Tennessee, Virginia, West Virginia, and Wisconsin.
    (c) The provisions of subpart DDDDD of part 97 of this chapter, 
regarding the TR SO2 Group 2 Trading Program, apply to 
sources in each of the following States: Alabama, Connecticut, 
Delaware, District of Columbia, Florida, Kansas, Louisiana, Maryland, 
Massachusetts, Minnesota, Nebraska, New Jersey, and South Carolina.
    (d) Following promulgation of an approval by the Administrator of a 
State's SIP as correcting the SIP's deficiency that is the basis for 
this 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 is partial or 
conditional.
    (e) Notwithstanding the provisions of paragraph (d) of this 
section, if, at the time of such approval of the State's SIP, the 
Administrator has already allocated any TR SO2 Group 1 
allowances or any TR SO2 Group 2 allowances (as applicable) 
to sources in the State for any years, the provisions of part 97 of 
this chapter authorizing the Administrator to complete the allocation 
of TR SO2 Group 1 allowances or TR SO2 Group 2 
allowances (as applicable) for those years shall continue to apply, 
unless provided otherwise by such approval of the State's SIP.

Subpart I--Delaware

    10. 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.
    11. Section 52.441 is amended by designating the introductory 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

    12. 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.
    13. Section 52.485 is amended by designating the introductory 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 P--Indiana

    14. Section 52.789 is amended by adding a new paragraph (c) to read 
as follows:


Sec.  52.789  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.
    15. Section 52.790 is amended by designating the introductory text 
as

[[Page 45364]]

paragraph (a) and adding a new paragraph (b) to read as follows:


Sec.  52.790  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 T--Louisiana

    16. Section 52.984 is amended by adding a new paragraph (c) 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; 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.

Subpart X--Michigan

    17. Section 52.1186 is amended by adding a new paragraph (c) 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; 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.
    18. Section 52.1187 is amended by designating the introductory text 
as paragraph (a) and adding a new paragraph (b) 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.

Subpart FF--New Jersey

    19. Section 52.1584 is amended by adding a new paragraph (c) 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; 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.
    20. Section 52.1185 is amended by designating the introductory text 
as paragraph (a) and adding a new paragraph (b) 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.

Subpart RR--Tennessee

    21. Section 52.2240 is amended by adding a new paragraph (c) 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

[[Page 45365]]

allowances or CAIR NOX Ozone Season allowances allocated for 
2012 or any year thereafter.
    22. Section 52.2241 is amended by designating the introductory text 
as paragraph (a) and adding a new paragraph (b) 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.

Subpart SS--Texas

    23. Section 52.2283 is amended by adding a new paragraph (c) to 
read as follows:


Sec.  52.2283  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 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; and
    (2) The Administrator will not deduct for excess emissions any CAIR 
NOX allowances allocated for 2012 or any year thereafter.
    24. Section 52.2284 is amended by designating the introductory text 
as paragraph (a) and adding a new paragraph (b) 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.

Subpart YY--Wisconsin

    25. Section 52.8587 is amended by adding a new paragraph (c) to 
read as follows:


Sec.  52.8587  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.
    26. Section 52.8588 is amended by designating the introductory text 
as paragraph (a) and adding a new paragraph (b) to read as follows:


Sec.  52.8588  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.

PART 72--[AMENDED]

    27. 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]

    28. Section 72.2 is amended by removing the definition of 
``interested person''.

PART 78--[AMENDED]

    29. The authority citation for Part 78 continues to read as 
follows:

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


Sec.  78.1  [Amended]

    30. 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.
    (iv) 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.
    (viii) The approval or disapproval of a TR opt-in application, the 
approval or disapproval of a request to withdraw, the decision on 
allocation of TR NOX Annual allowances, and the decision on 
the deduction of TR NOX Annual allowances under Sec. Sec.  
97.441 through 97.444.
    (14) Under subpart BBBBB of part 97 of this chapter, (i) The 
decision on allocation of TR NOX Ozone Season

[[Page 45366]]

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.
    (iv) 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.
    (viii) The approval or disapproval of a TR opt-in application, the 
approval or disapproval of a request to withdraw, the decision on 
allocation of TR NOX Ozone Season allowances, and the 
decision on the deduction of TR NOX Ozone Season allowances 
under Sec. Sec.  97.541 through 97.544.
    (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.
    (iv) 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.
    (viii) The approval or disapproval of a TR opt-in application, the 
approval or disapproval of a request to withdraw, the decision on 
allocation of TR SO2 Group 1 allowances, and the decision on 
the deduction of TR SO2 Group 1 allowances under Sec. Sec.  
97.641 through 97.644.
    (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.
    (iv) 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.  97.728 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.
    (viii) The approval or disapproval of a TR opt-in application, the 
approval or disapproval of a request to withdraw, the decision on 
allocation of TR SO2 Group 2 allowances, and the decision on 
the deduction of TR SO2 Group 2 allowances under Sec. Sec.  
97.741 through 97.744.
* * * * *


Sec.  78.2  [Amended]

    31. 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, 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, who 
submitted objections pursuant to an opportunity for objections provided 
by the Administrator as part of the process of making such decision, or 
who submitted his or her name to the Administrator to be placed on a 
list of persons interested in such decision. 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.


Sec.  78.3  [Amended]

    32. Section 78.3 is amended by:
    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''.
    b. Adding paragraph (a)(10);
    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
    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.


Sec.  78.4  [Amended]

    33. Section 78.4 is amended by:
    a. Revising paragraph (a) by:
    i. Removing the first, second, third, fourth, fifth, and last 
sentences;

[[Page 45367]]

    ii. In the sixth and seventh sentences, removing the words 
``interest in'' and adding, in their place, the words ``ownership 
interest with respect to''; and
    iii. Redesignating the paragraph as paragraph (a)(1)(iii); and
    b. Adding paragraphs (a)(1) introductory text, (a)(1)(i), 
(a)(1)(ii) and (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.
* * * * *

PART 97--[AMENDED]

    34. 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.

    35. Part 97 is amended by adding subpart AAAAA to read as follows:
Subpart AAAAA TR NOX Annual Trading Program
Sec.
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, and variability limits.
97.411 Timing requirements for TR NOX Annual allowance 
allocations.
97.412 TR NOX Annual allowance allocations for 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 Allowance Management System 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.
97.440 General requirements for TR NOX Annual opt-in 
units.
97.441 Opt-in process.
97.442 Withdrawal of TR NOX Annual opt-in unit from TR 
NOX Annual Trading Program.
97.443 Change in regulatory status.
97.444 TR NOX Annual allowance allocations to TR 
NOX Annual opt-in units.

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.  52.37(a) 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) 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 of the amount 
of such TR NOX Annual allowances to be initially credited to 
a TR NOX Annual source or a new unit set-aside.
    Allowable NOX emission rate means, with regard to a unit, the 
NOX emission rate limit 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, held, deducted, or 
transferred only as whole allowances. The Allowance Management System 
is a component of the CAMD Business System, which is the system used by 
the Administrator to handle TR NOX Annual allowances and 
data related to NOX emissions.
    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, 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

[[Page 45368]]

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.  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 Sec.  72.2 of this chapter, 
Sec.  97.502, Sec.  97.602, or Sec.  97.702 respectively.
    Authorized account representative means, with regard to 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, with regard to 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 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.
    Certifying official means a natural person who is:
    (1) For a corporation, a president, secretary, treasurer, or vice-
president or 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 any solid fuel classified as anthracite, bituminous, 
subbituminous, or lignite.
    Coal-derived fuel means any fuel (whether in a solid, liquid, or 
gaseous state) produced by the mechanical, thermal, or chemical 
processing of coal.
    Coal-fired means combusting any amount of coal or coal-derived 
fuel, alone or in combination with any amount of any other fuel, during 
1990 or any year thereafter.
    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--
    (1) Operating as part of a cogeneration system; and
    (2) Producing during the later of 1990 or the 12-month period 
starting on the date that the unit first produces electricity and 
during each calendar year after the later of 1990 or the calendar year 
in which the unit first produces electricity--
    (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 then 42.5 percent of total energy input, 
if useful thermal energy produced is 15 percent or more of total energy 
output, or not less than 45 percent of total energy input, if useful 
thermal energy produced is less than 15 percent of total energy output.
    (ii) For a bottoming-cycle unit, useful power not less than 45 
percent of total energy input;
    (3) 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
    (4) Provided that, if a topping-cycle unit is operated as part of a 
cogeneration system during a calendar year and the cogeneration system 
meets on a system-wide basis the requirement in paragraph (2)(i)(B) of 
this definition, the topping-cycle unit shall be deemed to meet such 
requirement during that 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 November 15, 1990 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 (other than replacement of the unit by a unit at the same 
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 November 15, 1990 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 source, such date shall remain the replaced unit's date of 
commencement of commercial operation, and the

[[Page 45369]]

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 November 15, 1990 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 (other than 
replacement of the unit by a unit at the same 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 
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.
    Commence operation means, with regard to a unit:
    (1) To have begun any mechanical, chemical, or electronic process, 
including start-up of the unit's combustion chamber.
    (2) For a unit that undergoes a physical change (other than 
replacement of the unit by a unit at the same source) after the date 
the unit commences operation as defined in paragraph (1) of this 
definition, such date shall remain the date of commencement of 
operation of the unit, which shall continue to be treated as the same 
unit.
    (3) For a unit that is replaced by a unit at the same source after 
the date the unit commences operation as defined in paragraph (1) of 
this definition, such date shall remain the replaced unit's date of 
commencement of operation, and the replacement unit shall be treated as 
a separate unit with a separate date for commencement of operation as 
defined in paragraph (1), (2), or (3) of this definition as 
appropriate.
    Common stack means a single flue through which emissions from 2 or 
more units are exhausted.
    Compliance account means 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 for 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 complying with the source's 
TR NOX Annual emissions limitation in accordance with Sec.  
97.424 and the TR NOX Annual assurance provisions in 
accordance with Sec.  97.425.
    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 Sec.  72.2 of 
this chapter, Sec.  97.502, Sec.  97.602, or Sec.  97.702 respectively.
    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 in accordance with this subpart.
    Excess emissions means any ton of NOX emitted from the 
TR NOX Annual units at a TR NOX Annual source 
during a control period that exceeds the TR NOX Annual 
emissions limitation for the source.
    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 Sec. Sec.  97.404(b)(2)(i)(B), 
97.404(b)(2)(ii)(B), and 97.404(b)(2)(iii), 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 1990 or any calendar year thereafter.
    Fuel oil means any petroleum-based fuel (including diesel fuel or 
petroleum derivatives such as oil tar) and any

[[Page 45370]]

recycled or blended petroleum products or petroleum by-products used as 
a fuel whether in a liquid, solid, or gaseous state.
    General account means an Allowance Management System account, 
established under this subpart, that is not a compliance account.
    Generator means a device that produces electricity.
    Gross electrical output means, with regard to 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, with regard to a unit for a specified period of 
time, the product (in mmBtu/time) of the gross calorific value of the 
fuel (in mmBtu/lb) multiplied by the fuel feed rate into a combustion 
device (in lb of fuel/time), as measured, recorded, and reported to the 
Administrator by the 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 the amount of heat input (in mmBtu) divided 
by unit operating time (in hr) or, with regard to a specific fuel, the 
amount of heat input attributed to the fuel (in mmBtu) divided by the 
unit operating time (in hr) during which the unit combusts the fuel.
    Life-of-the-unit, firm power contractual arrangement means a unit 
participation power sales agreement under which a utility or industrial 
customer reserves, or is entitled to receive, a specified amount or 
percentage of nameplate capacity and associated energy generated by any 
specified unit and pays its proportional amount of such unit's total 
costs, pursuant to a contract:
    (1) For the life of the unit;
    (2) For a cumulative term of no less than 30 years, including 
contracts that permit an election for early termination; or
    (3) For a period no less than 25 years or 70 percent of the 
economic useful life of the unit determined as of the time the unit is 
built, with option rights to purchase or release some portion of the 
nameplate capacity and associated energy generated by the unit at the 
end of the period.
    Maximum design heat input means the maximum amount of fuel per hour 
(in Btu/hr) that a 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) 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 (in MWe) that the generator is 
capable of producing on a steady state basis and during continuous 
operation (when not restricted by seasonal or other deratings), such 
increased maximum amount as of such completion as specified by the 
person conducting the physical change.
    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 any person who operates, controls, or supervises a 
TR NOX Annual unit or a TR NOX Annual source and 
shall include, but not be limited to, any holding company, utility 
system, or plant manager of such a unit or source.
    Owner means, with regard to 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;
    (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;
    (4) Provided that, for purposes of applying the TR NOX 
Annual assurance provisions in Sec. Sec.  97.406(c)(2) and 97.425, if 
one or more owners (as defined in paragraphs (1) through (3) of this 
definition) of one or more TR NOX Annual units in a State 
are wholly owned by another, common owner, all such owners shall be 
treated collectively as a single owner in the State.
    Owner's assurance level means:
    (1) With regard to a State and control period for which the State 
assurance level is exceeded as described in Sec.  97.406(c)(2)(iii)(A) 
and not as described in Sec.  97.406(c)(2)(iii)(B), the owner's share 
of the State NOX Annual trading budget with the one-year 
variability limit for the State for such control period; or
    (2) With regard to a State and control period for which the State 
assurance level is exceeded as described in Sec.  97.406(c)(2)(iii)(B), 
the owner's share of the State NOX Annual trading budget 
with the three-year variability limit for the State for such control 
period.
    Owner's share means:
    (1) With regard to a total amount of NOX emissions from 
all TR NOX Annual units in a State during a control period, 
the total tonnage of NOX emissions during such control 
period from all of the owner's TR NOX Annual units in the 
State;
    (2) With regard to a State NOX Annual trading budget 
with a one-year variability limit for a control period, the amount 
(rounded to the nearest allowance) equal to the total amount of TR 
NOX Annual allowances allocated for such control period to 
all of the owner's TR NOX Annual units in the State, 
multiplied by the sum of the State NOX Annual trading budget 
under Sec.  97.410(a) and the State's one-year variability limit under 
Sec.  97.410(b) and divided by such State NOX Annual trading 
budget;
    (3) With regard to a State NOX Annual trading budget 
with a three-year variability limit for a control period, the amount 
(rounded to the nearest allowance) equal to the total amount of TR 
NOX Annual allowances allocated for such control period to 
all of the owner's TR NOX Annual units in the State, 
multiplied by the sum of the State NOX Annual trading budget 
under Sec.  97.410(a) and the State's three-year variability limit 
under Sec.  97.410(b) and divided by such State NOX Annual 
trading budget;
    (4) Provided that, in the case of a unit with more than one owner, 
the amount of tonnage of NOX emissions and of TR 
NOX Annual allowances allocated for a control period, with 
regard to such unit, used in determining each owner's share

[[Page 45371]]

shall be the amount (rounded to the nearest ton and the nearest 
allowance) equal to the unit's NOX emissions and allocation 
of such allowances, respectively, for such control period multiplied by 
the percentage of ownership in the unit that the owner's legal, 
equitable, leasehold, or contractual reservation or entitlement in the 
unit comprises as of December 31 of such control period;
    (5) Provided that, where two or more units emit through a common 
stack that is the monitoring location from which NOX mass 
emissions are reported for a control period for a year, the amount of 
tonnage of each unit's NOX emissions used in determining 
each owner's share for such control period shall be:
    (i) The amount (rounded to the nearest ton) of NOX 
emissions reported at the common stack multiplied by the quotient of 
such unit's heat input for such control period divided by the total 
heat input reported from the common stack for such control period;
    (ii) An amount determined in accordance with a methodology that the 
Administrator determines is consistent with the purposes of this 
definition and whose adverse effect (if any) the Administrator 
determines will be de minimis; or
    (iii) An amount approved by the Administrator in response to a 
petition for an alternative requirement submitted in accordance with 
Sec.  97.435; and
    (6) Provided that, in the case of a unit that operates during, but 
is allocated no TR NOX Annual allowances for, a 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 lesser of--
    (i) The unit's allowable NOX emission rate (in lb per 
MWe) applicable to such control period, multiplied by a capacity factor 
of 0.84 (if the unit is a coal-fired boiler), 0.15 (if the unit is a 
simple combustion turbine), or 0.66 (if the unit is a combined cycle 
turbine), 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; or
    (ii) For a unit listed in appendix A to this subpart, the sum of 
the unit's NOX emissions in the control period in the last 
three years during which the unit operated during the control period, 
divided by three.
    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 33 percent of a unit's 
maximum design heat input, divided by 3,413 Btu/kWh, divided by 1,000 
kWh/MWh, and multiplied by 8,760 hr/yr.
    Receive or receipt of means, when referring to the 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 
Annual allowances by the Administrator into, out of, or between 
Allowance Management System accounts, for purposes of allocation, 
transfer, or deduction.
    Reference method means any direct test method of sampling and 
analyzing for an air pollutant as specified in Sec.  75.22 of this 
chapter.
    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) For a topping-cycle unit, the use of reject heat from 
electricity production in a useful thermal energy application or 
process; or
    (2) For a bottoming-cycle unit, 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 or the District of Columbia that is 
subject to the TR NOX Annual Trading Program pursuant to 
Sec.  52.37(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 total energy of all forms supplied to a 
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 the sum of useful power and useful 
thermal energy produced by the unit.
    TR NOX Annual allowance means a limited authorization issued and 
allocated by the Administrator under this subpart to emit one ton of 
NOX during a control period of the specified calendar year 
for which the authorization is allocated or of any calendar year 
thereafter under the TR NOX Annual 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 assurance provisions.
    TR NOX Annual allowances held or hold TR NOX Annual allowances 
means the TR NOX Annual allowances treated

[[Page 45372]]

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 Trading Program means a multi-state NOX 
air pollution control and emission reduction program established by the 
Administrator in accordance with this subpart and 52.37(a) of this 
chapter, as a means of mitigating interstate transport of fine 
particulates and NOX.
    TR NOX Annual emissions limitation means, for a TR NOX 
Annual source, the tonnage of NOX emissions authorized in a 
control period 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 unit means a unit that is subject to the TR 
NOX Annual Trading Program under Sec.  97.404.
    TR NOX Ozone Season Trading Program means a multi-state 
NOX air pollution control and emission reduction program 
established by the Administrator in accordance with subpart BBBBB of 
this part and 52.37(b) 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 by the 
Administrator in accordance with subpart CCCCC of this part and 
52.38(b) 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 by the 
Administrator in accordance with subpart DDDDD of this part and 
52.38(c) 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.
Unit operating day means a calendar day in which a unit combusts any 
fuel.
    Unit operating hour or hour of unit operation means an hour in 
which a unit combusts any fuel.
    Useful power means electricity or mechanical energy that a 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 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, since the 
later of November 15, 1990 or the start-up of the unit's combustion 
chamber, 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 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), (b)(2)(i), or (b)(2)(ii) 
of this section shall not be a TR NOX Annual unit:
    (1)(i) Any unit:
    (A) Qualifying as a cogeneration unit during the later of 1990 or 
the 12-month period starting on the date the unit first produces 
electricity and continuing to qualify as a cogeneration unit; and
    (B) Not serving at any time, since the later of November 15, 1990 
or the start-up of the unit's combustion chamber, a generator with 
nameplate capacity of more than 25 MWe supplying in any calendar year 
more than one-third of the unit's potential electric output capacity or 
219,000 MWh, whichever is greater, to any utility power distribution 
system for sale.
    (ii) If a unit qualifies as a cogeneration unit during the later of 
1990 or the 12-month period starting on the date the unit first 
produces electricity and meets the requirements of paragraphs (b)(1)(i) 
of this section for at least one calendar year, but subsequently no 
longer meets such qualification and requirements, 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.
    (2)(i) Any unit commencing operation before January 1, 1985:
    (A) Qualifying as a solid waste incineration unit during the later 
of 1990 or the 12-month period starting on the date the unit first 
produces electricity and continuing to qualify as a solid waste 
incineration unit; and
    (B) With an average annual fuel consumption of fossil fuel for 
1985-1987 less than 20 percent (on a Btu basis) and an average annual 
fuel consumption of fossil fuel for any 3 consecutive calendar years 
after 1990 less than 20 percent (on a Btu basis).
    (ii) Any unit commencing operation on or after January 1, 1985:

[[Page 45373]]

    (A) Qualifying as a solid waste incineration unit during the later 
of 1990 or the 12-month period starting on the date the unit first 
produces electricity and continuing to qualify as a solid waste 
incineration unit; and
    (B) With an average annual fuel consumption of fossil fuel for the 
first 3 calendar years of operation less than 20 percent (on a Btu 
basis) and an average annual fuel consumption of fossil fuel for any 3 
consecutive calendar years after 1990 less than 20 percent (on a Btu 
basis).
    (iii) If a unit qualifies as a solid waste incineration unit during 
the later of 1990 or the 12-month period starting on the date the unit 
first produces electricity and meets the requirements of paragraph 
(b)(2)(i) or (ii) of this section for at least 3 consecutive calendar 
years, but subsequently no longer meets such qualification and 
requirements, 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 1990 for which the unit has an average annual fuel 
consumption of fossil fuel of 20 percent or more.
    (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, 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 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 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 and is not a TR NOX Annual opt-in unit 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, 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 a TR NOX Annual source emits NOX 
during any control period in excess of the TR NOX Annual 
emissions limitation set forth in paragraph (c)(1)(i) of this section, 
then:

[[Page 45374]]

    (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 pay any fine, penalty, or assessment or comply with any 
other remedy imposed, for the same violations, under the Clean Air Act; 
and
    (B) 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 the total 
amount of NOX emissions from all TR NOX Annual 
units in a State during a control period in 2014 or any year thereafter 
exceeds the State assurance level as described in paragraph (c)(2)(iii) 
of this section, then each owner whose share of such NOX 
emissions during such control period exceeds the owner's assurance 
level for the State and such control period shall hold, in a compliance 
account designated by the owner in accordance with Sec.  
97.425(b)(4)(ii), TR NOX Annual allowances available for 
deduction for such control period under Sec.  97.425(a) in an amount 
equal to the product, as determined by the Administrator in accordance 
with Sec.  97.425(b), of multiplying--
    (A) The quotient (rounded to the nearest whole number) of the 
amount by which the owner's share of such NOX emissions 
exceeds the owner's assurance level divided by the sum of the amounts, 
determined for all such owners, by which each owner's share of such 
NOX emissions exceeds that owner's assurance level; and
    (B) The amount by which total NOX emissions for all TR 
NOX Annual units in the State for such control period exceed 
the State assurance level as determined in accordance with paragraph 
(c)(2)(iii) of this section.
    (ii) The owner 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) The total amount of NOX emissions from all TR 
NOX Annual units in a State during a control period in 2014 
or any year thereafter exceeds the State assurance level:
    (A) If such total amount of NOX emissions exceeds the 
sum, for such control period, of the State NOX Annual 
trading budget and the State's one-year variability limit under Sec.  
97.410(b); or
    (B) If, with regard to a control period in 2016 or any year 
thereafter, the sum, divided by three, of such total amount of 
NOX emissions and the total amounts of NOX 
emissions from all TR NOX Annual units in the State during 
the control periods in the immediately preceding two years exceeds the 
sum, for such control period, of the State NOX Annual 
trading budget and the State's three-year variability limit under Sec.  
97.410(b);
    (C) Provided that the amount by which such total amount of 
NOX emissions exceeds the State assurance level shall be the 
greater of the amounts of the exceedance calculated under paragraph 
(c)(2)(iii)(A) of this section and under paragraph (c)(2)(iii)(B) of 
this section.
    (iv) It shall not be a violation of this subpart or of the Clean 
Air Act if the total amount of NOX emissions from all TR 
NOX Annual units in a State during a control period exceeds 
the State assurance level or if an owner's share of total 
NOX emissions from the TR NOX Annual units in a 
State during a control period exceeds the owner's assurance level.
    (v) To the extent an owner fails to hold TR NOX Annual 
allowances for a control period in accordance with paragraphs (c)(2)(i) 
and (ii) of this section,
    (A) The owner 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 owner fails to 
hold for a control period in accordance with paragraphs (c)(2)(i) and 
(ii) 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:
    (i) Under paragraph (c)(1) 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; and
    (ii) Under paragraph (c)(2) of this section for the control period 
starting on the later of January 1, 2014 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 deducted allowances. A TR NOX Annual 
allowance shall not be deducted, for compliance with the requirements 
under paragraphs (c)(1) and (2) of this section, for a control period 
in a calendar year before the year for which the TR NOX 
Annual allowance was allocated.
    (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. (i) A TR NOX Annual allowance 
is a limited authorization to emit one ton of NOX in 
accordance with the TR NOX Annual Trading Program.
    (ii) Notwithstanding any other provision of this subpart, the 
Administrator has the authority to terminate or limit 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

[[Page 45375]]

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 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, including any monitoring plans and monitoring system 
certification and recertification applications.
    (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, including any submissions required for compliance with the TR 
NOX Annual assurance provisions. 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 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, falls on a weekend 
or a State or Federal holiday, 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, 
and variability limits.

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

------------------------------------------------------------------------
                                            NOX annual    New-unit  set-
                                          trading budget   aside  (tons)
                                              (tons) *   ---------------
                  State                  ----------------
                                           For 2012 and    For 2012 and
                                            thereafter      thereafter
------------------------------------------------------------------------
Alabama.................................          69,169           2,075
Connecticut.............................           2,775              83
Delaware................................           6,206             186
District of Columbia....................             170               5
Florida.................................         120,001           3,600
Georgia.................................          73,801           2,214
Illinois................................          56,040           1,681
Indiana.................................         115,687           3,471
Iowa....................................          46,068           1,382
Kansas..................................          51,321           1,540
Kentucky................................          74,117           2,224
Louisiana...............................          43,946           1,318
Maryland................................          17,044             511
Massachusetts...........................           5,960             179
Michigan................................          64,932           1,948
Minnesota...............................          41,322           1,240
Missouri................................          57,681           1,730
Nebraska................................          43,228           1,297
New Jersey..............................          11,826             355
New York................................          23,341             700
North Carolina..........................          51,800           1,554
Ohio....................................          97,313           2,919
Pennsylvania............................         113,903           3,417
South Carolina..........................          33,882           1,016
Tennessee...............................          28,362             851
Virginia................................          29,581             887
West Virginia...........................          51,990           1,560
Wisconsin...............................          44,846           1,345
¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤

[[Page 45376]]


    Total...............................       1,376,312          41,288
------------------------------------------------------------------------
* Without variability limits.

    (b) The States' one-year and three-year variability limits for the 
State NOX Annual trading budgets for the control periods in 
2014 and thereafter are as follows:

------------------------------------------------------------------------
                                             One-year       Three-year
                                            variability     variability
                                              limits          limits
                  State                  -------------------------------
                                             2014 and        2016 and
                                            thereafter      thereafter
                                              (tons)          (tons)
------------------------------------------------------------------------
Alabama.................................           6,917           3,993
Connecticut.............................           5,000           2,887
Delaware................................           5,000           2,887
District of Columbia....................           5,000           2,887
Florida.................................          12,000           6,928
Georgia.................................           7,380           4,261
Illinois................................           5,604           3,235
Indiana.................................          11,569           6,679
Iowa....................................           5,000           2,887
Kansas..................................           5,132           2,963
Kentucky................................           7,412           4,279
Louisiana...............................           5,000           2,887
Maryland................................           5,000           2,887
Massachusetts...........................           5,000           2,887
Michigan................................           6,493           3,749
Minnesota...............................           5,000           2,887
Missouri................................           5,768           3,330
Nebraska................................           5,000           2,887
New Jersey..............................           5,000           2,887
New York................................           5,000           2,887
North Carolina..........................           5,180           2,991
Ohio....................................           9,731           5,618
Pennsylvania............................          11,390           6,576
South Carolina..........................           5,000           2,887
Tennessee...............................           5,000           2,887
Virginia................................           5,000           2,887
West Virginia...........................           5,199           3,002
Wisconsin...............................           5,000           2,887
------------------------------------------------------------------------

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 
set forth in appendix A to this subpart. Listing a unit in such 
appendix does not constitute a determination that the unit is a TR 
NOX Annual unit, and not listing a unit in such appendix 
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 
listed in appendix A to this subpart as being allocated TR 
NOX Annual allowances does not operate, starting after 2011, 
during the control period in three consecutive years, such unit will 
not be allocated the TR NOX Annual allowances set forth in 
appendix A to this subpart for the unit for the control periods in the 
seventh year after the first such year and in each year after that 
seventh 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 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) By July 1, 2012 and July 1 of each year 
thereafter, the Administrator will calculate the TR NOX 
Annual allowance allocation for each TR NOX Annual unit, in 
accordance with Sec.  97.412, for the control period in the year of the 
applicable calculation deadline under this paragraph and will 
promulgate a notice of availability of the results of the calculations.
    (2) For each notice of data availability required in paragraph 
(b)(1) of this section, the Administrator will provide an opportunity 
for submission of objections to the calculations referenced in such 
notice.
    (i) Objections shall be submitted by the deadline specified in such 
notice and shall be limited to addressing whether the calculations are 
in accordance with Sec.  97.412 and Sec. Sec.  97.406(b)(2) and 97.430 
through 97.435.

[[Page 45377]]

    (ii) 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)(i) of this section. By September 1 
immediately after the promulgation of such notice, the Administrator 
will promulgate a notice of 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)(i) of this section.
    (c) Units that are not TR NOX Annual units. 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 for the control period to a recipient that is not actually 
a TR NOX Annual unit under Sec.  97.404 as of January 1, 
2012 or whose deadline for meeting monitor certification requirements 
under Sec.  97.430(b)(1) and (2) is after January 1, 2012 or if the 
Administrator determines that TR NOX Annual allowances were 
allocated under paragraph (b) of this section and Sec.  97.412 for the 
control period to a recipient that is not actually a TR NOX 
Annual unit under Sec.  97.404 as of January 1 of the control period, 
then the Administrator will notify the designated representative and 
will act in accordance with the following procedures:
    (1) Except as provided in paragraph (c)(2) or (3) of this section, 
the Administrator will not record such TR NOX Annual 
allowances under Sec.  97.421.
    (2) If the Administrator already recorded such TR NOX 
Annual allowances under Sec.  97.421 and if the Administrator makes 
such determination 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.
    (3) If the Administrator already recorded such TR NOX 
Annual allowances under Sec.  97.421 and if the Administrator makes 
such determination 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.
    (4) The Administrator will transfer the TR NOX Annual 
allowances that are not recorded, or that are deducted, in accordance 
with paragraphs (c)(1) and (2) of this section to the new unit set-
aside, for the State in which such recipient is located, for the 
control period in the year of such transfer if the notice required in 
paragraph (b)(1) of this section for the control period in that year 
has not been promulgated or, if such notice has been promulgated, in 
the next year.


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

    (a) For each control period in 2012 and thereafter, the 
Administrator will allocate, in accordance with the following 
procedures, TR NOX Annual allowances to TR NOX 
Annual units in a State that are not listed in appendix A to this 
subpart, to TR NOX Annual units that are so listed and whose 
allocation of NOX Annual allowances for such control period 
is covered by Sec.  97.411(c)(1) or (2), and to TR NOX 
Annual units that are so listed and, pursuant to Sec.  97.411(a)(2), 
are not allocated TR NOX Annual allowances for such control 
period but operate during the immediately preceding control period:
    (1) The Administrator will establish a separate new unit set-aside 
for each State for each control period in a given year. Each 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). Each new unit set-aside will 
be allocated additional TR NOX Annual allowances in 
accordance with Sec.  97.411(a)(2) and (c)(4).
    (2) The designated representative of such TR NOX Annual 
unit may submit to the Administrator a request, in a format prescribed 
by the Administrator, to be allocated TR NOX Annual 
allowances for a control period, starting with the later of the control 
period in 2012, the first control period after the control period in 
which the TR NOX Annual unit commences commercial operation 
(for a unit not listed in appendix A to this subpart), or the first 
control period after the control period in which the unit resumes 
operation (for a unit listed in appendix A of this subpart) and for 
each subsequent control period.
    (i) The request must be submitted on or before May 1 of the first 
control period for which TR NOX Annual allowances are sought 
and after the date on which the TR NOX Annual unit commences 
commercial operation (for a unit not listed in appendix A of this 
subpart) or on which the unit resumes operation (for a unit listed in 
appendix A of this subpart).
    (ii) For each control period for which an allocation is sought, the 
request must be for TR NOX Annual allowances in an amount 
equal to the unit's total tons of NOX emissions during the 
immediately preceding control period.
    (3) The Administrator will review each TR NOX Annual 
allowance allocation request under paragraph (a)(2) of this section and 
will accept the request only if it meets the requirements of paragraph 
(a)(2) of this section. The Administrator will allocate TR 
NOX Annual allowances for each control period pursuant to an 
accepted request as follows:
    (i) After May 1 of such control period, the Administrator will 
determine the sum of the TR NOX Annual allowances requested 
in all accepted allowance allocation requests for such control period.
    (ii) If the amount of TR NOX Annual allowances in the 
new unit set-aside for such control period is greater than or equal to 
the sum under paragraph (a)(3)(i) of this section, then the 
Administrator will allocate the amount of TR NOX Annual 
allowances requested to each TR NOX Annual unit covered by 
an accepted allowance allocation request.
    (iii) If the amount of TR NOX Annual allowances in the 
new unit set-aside for such control period is less than the sum under 
paragraph (a)(3)(i) of this section, then the Administrator will 
allocate to each TR NOX Annual unit covered by an accepted 
allowance allocation request the amount of the TR NOX Annual 
allowances requested, multiplied by the amount of TR NOX 
Annual allowances in the new unit set-aside for such control period, 
divided by the sum determined under paragraph (a)(3)(i) of this 
section, and rounded to the nearest allowance.
    (iv) The Administrator will notify, through the promulgation of the 
notices of data availability described in Sec.  97.411(b), each 
designated representative that submitted an allowance allocation 
request of the amount of TR NOX Annual allowances (if any) 
allocated for such control period to the TR NOX Annual unit 
covered by the request.
    (b) If, after completion of the procedures under paragraph (a)(4) 
of this section for a control period, any unallocated TR NOX 
Annual allowances remain in the new unit set-aside under paragraph (a) 
of this section for a State for such control period, the Administrator 
will allocate to each TR

[[Page 45378]]

NOX Annual unit that is in the State, is listed in appendix 
A to this subpart, 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 amount of tons in such 
new unit set-aside, and rounded to the nearest allowance.


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'' 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.

    (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 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 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, 
including the addition of a new

[[Page 45379]]

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 include the change.


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, and actual or projected date of commencement of 
commercial operation.
    (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 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 Sec.  97.415(a) or (b), 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 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 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 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

[[Page 45380]]

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 Allowance Management System 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) 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 order or decision 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 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 order or decision issued to the authorized account 
representative or alternate authorized account representative by the 
Administrator regarding the general account.
    (ii) Except as provided in paragraph (b)(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

[[Page 45381]]

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 (b)(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 (b)(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 of a new 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 (b)(1) of this 
section has been submitted and received, the Administrator will rely on 
the application unless and until a superseding complete application for 
a general account under paragraph (b)(1) of this section is received by 
the Administrator.
    (ii) Except as provided in paragraph (b)(3)(i) or (ii) of this 
section, no objection or other communication submitted to the 
Administrator concerning the authorization, or any representation, 
action, inaction, or submission of the 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 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 make an electronic 
submission to the Administrator in accordance with paragraph (b)(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 as an ``agent'');
    (C) For each such natural person, a list of the type or types of 
electronic submissions under paragraph (b)(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(b)(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(b)(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(b)(5) is terminated.''.
    (iv) A notice of delegation submitted under paragraph (b)(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 (b)(5)(iii)(D) of this section and made in accordance with a 
notice of delegation effective under paragraph (b)(5)(iv) of this 
section shall be deemed to be an electronic submission by the 
designated

[[Page 45382]]

representative or alternate designated representative submitting such 
notice of delegation.
    (6)(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 20 business days after 
the notice is sent. The account will be closed after the 20-day period 
unless, before the end of the 20-day period, the Administrator receives 
a correctly submitted 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.
    (c) Account identification. The Administrator will assign a unique 
identifying number to each account established under paragraph (a) or 
(b) of this section.
    (d) Responsibilities of authorized account representative and 
alternate authorized account representative. After the establishment of 
an Allowance Management System 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 (b)(2)(ii) and (b)(5) of this 
section.


Sec.  97.421  Recordation of TR NOX Annual allowance allocations.

    (a) By September 1, 2011, the Administrator will record in each TR 
NOX Annual source's compliance account the TR NOX 
Annual allowances allocated for the TR NOX Annual units at 
the source in accordance with Sec. Sec.  97.411(a) for the control 
periods in 2012, 2013, and 2014.
    (b) By June 1, 2012 and June 1 of each year thereafter, the 
Administrator will record in each TR NOX Annual source's 
compliance account the TR NOX Annual allowances allocated 
for the TR NOX Annual units at the source in accordance with 
Sec.  97.411(a) for the control period in the third year after the year 
of the applicable recordation deadline under this paragraph.
    (c) By September 1, 2012 and September 1 of each year thereafter, 
the Administrator will record in each TR NOX Annual source's 
compliance account the TR NOX Annual allowances allocated 
for the TR NOX Annual units at the source in accordance with 
Sec.  97.412 for the control period in the year of the applicable 
recordation deadline under this paragraph.
    (d) When recording the allocation of TR NOX Annual 
allowances for a TR NOX Annual unit in a compliance 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.


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, 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 by 
the request, provided that the transfer is correctly submitted under 
Sec.  97.422.
    (b)(1) A TR NOX Annual allowance transfer 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 under Sec.  97.424 for the control period 
immediately before such allowance transfer deadline.
    (2) A TR NOX Annual allowance transfer that is submitted 
for recordation after the deadline for holding TR NOX Annual 
allowances described in Sec.  97.425(b)(5) and that includes any TR 
NOX Annual allowances allocated for a control period before 
the year of such deadline will not be recorded until after the 
Administrator completes the deductions under Sec.  97.425 for the 
control period immediately before the year of such 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 the control period in the year or 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.  97.423, of TR NOX Annual allowance transfers 
submitted by the allowance transfer deadline for a control period, the 
Administrator will deduct from the compliance account TR NOX 
Annual allowances available under paragraph

[[Page 45383]]

(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 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 (FIFO) 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 
the control period 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 an 
owner of one or more TR NOX Annual units in a State only if 
the TR NOX Annual allowances:
    (1) Were allocated for the control period in the year or a prior 
year; and
    (2) Are held in a compliance account, designated by the owner in 
accordance with paragraph (b)(4)(ii) of this section, of one of the 
owner's TR NOX Annual sources in the State as of the 
deadline established in paragraph (b)(5) 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, 2015 and June 1 of each year thereafter, the 
Administrator will:
    (i) Calculate, separately for each State, the total amount of 
NOX emissions from all TR NOX Annual units in the 
State during the control period in the year before the year of this 
calculation deadline and the amount, if any, by which such total amount 
of NOX emissions exceeds the State assurance level as 
described in Sec.  97.406(c)(2)(iii); and
    (ii) Promulgate a notice of availability of the results of the 
calculations required in paragraph (b)(1)(i) of this section, including 
separate calculations of the NOX emissions for each TR 
NOX Annual unit and of the amounts described in Sec. Sec.  
97.406(c)(2)(iii)(A) and (B) for each State.
    (2) The Administrator will provide an opportunity for submission of 
objections to the calculations referenced by each notice described in 
paragraph (b)(1) of this section.
    (i) Objections shall be submitted by the deadline specified in such 
notice and shall be limited to addressing whether the calculations for 
each TR NOX Annual unit and each State for the control 
period in the year involved are in accordance with Sec.  
97.406(c)(2)(iii) and Sec. Sec.  97.406(b) and 97.430 through 97.435.
    (ii) 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)(i) of this section. By August 1 
immediately after the promulgation of such notice, the Administrator 
will promulgate a notice of 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)(i) of this section.
    (3) For each notice of data availability required in paragraph 
(b)(2)(ii) of this section and for any State identified in such notice 
as having TR NOX Annual sources with total NOX 
emissions exceeding the State assurance level for a control period, as 
described in Sec.  97.406(c)(2)(iii):
    (i) By August 15 immediately after the promulgation of such notice, 
the designated representative of each TR NOX Annual source 
in each such State shall submit a statement, in a format prescribed by 
the Administrator:
    (A) Listing all the owners of each TR NOX Annual unit at 
the source, explaining how the selection of each owner for inclusion on 
the list is consistent with the definition of ``owner'' in Sec.  
97.402, and listing, separately for each unit, the percentage of the 
legal, equitable, leasehold, or contractual reservation or entitlement 
for each such owner as of midnight of December 31 of the control period 
in the year involved; and
    (B) For each TR NOX Annual unit at the source that 
operates during, but is allocated no TR NOX Annual 
allowances for, the control period in the year involved, identifying 
whether the unit is a coal-fired boiler, simple combustion turbine, or 
combined cycle turbine cycle and providing the unit's allowable 
NOX emission rate for such control period.
    (ii) By September 15 immediately after the promulgation of such 
notice, the Administrator will calculate, for each such State and each 
owner of one or more TR NOX Annual units in the State and 
for the control period in the year involved, each owner's share of the 
total NOX emissions from all TR NOX Annual units 
in the State, each owner's assurance level, and the amount (if any) of 
TR NOX Annual allowances that each owner must hold in 
accordance with the calculation formula in Sec.  97.406(c)(2)(i) and 
will promulgate a notice of 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

[[Page 45384]]

required in paragraph (b)(3)(ii) of this section.
    (A) Objections shall be submitted by the deadline specified in such 
notice and shall be limited to addressing whether the calculations for 
each owner for the control period in the year involved are consistent 
with the NOX emissions for the relevant TR NOX 
Annual units as set forth in the notice required in paragraph 
(b)(2)(ii) of this section, the definitions of ``owner'', ``owner's 
assurance level'', and ``owner's share'' in Sec.  97.402, and the 
calculation formula in Sec.  97.406(c)(2)(i) and shall not raise any 
issues about any data used in the notice of data availability required 
in paragraph (b)(2)(ii) of this section.
    (B) The Administrator will adjust the calculations to the extent 
necessary to ensure that they are consistent with the data and 
provisions referenced in paragraph (b)(3)(iii)(A) of this section. By 
November 15 immediately after the promulgation of such notice, the 
Administrator will promulgate a notice of 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)(3)(iii)(A) of this section.
    (4) By December 1 immediately after the promulgation of each notice 
of data availability required in paragraph (b)(3)(iii)(B) of this 
section:
    (i) Each owner identified, in such notice, as owning one or more TR 
NOX Annual units in a State and as being required to hold TR 
NOX Annual allowances shall designate the compliance account 
of one of the sources at which such unit or units are located to hold 
such required TR NOX Annual allowances;
    (ii) The authorized account representative for the compliance 
account designated under paragraph (b)(4)(i) of this section shall 
submit to the Administrator a statement, in a format prescribed by the 
Administrator, making this designation.
    (5)(i) As of midnight of December 15 immediately after the 
promulgation of each notice of data availability required in paragraph 
(b)(3)(iii)(B) of this section, each owner described in paragraph 
(b)(4)(i) of this section shall hold in the compliance account 
designated by the owner in accordance with paragraph (b)(4)(ii) of this 
section the total amount of TR NOX Annual allowances, 
available for deduction under paragraph (a) of this section, equal to 
the amount the owner is required to hold as calculated by the 
Administrator and referenced in such notice.
    (ii) Notwithstanding the allowance-holding deadline specified in 
paragraph (b)(5)(i) of this section, if December 15 is not a business 
day, then such allowance-holding deadline shall be midnight of the 
first business day thereafter.
    (6) After December 15 (or the date described in paragraph 
(b)(5)(ii) of this section) immediately after the promulgation of each 
notice of data availability required in paragraph (b)(3)(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 deduct from each 
compliance account designated in accordance with paragraph (b)(4)(ii) 
of this section, TR NOX Annual allowances available under 
paragraph (a) of this section, as follows:
    (i) Until the amount of TR NOX Annual allowances 
deducted equals the amount that the owner designating the compliance 
account is required to hold as calculated by the Administrator and 
referenced in the notice required in paragraph (b)(3)(iii)(B) of this 
section; or
    (ii) If there are insufficient TR NOX Annual allowances 
to complete the deductions in paragraph (b)(6)(i) of this section, 
until no more TR NOX Annual allowances available under 
paragraph (a) of this section remain in the compliance account.
    (7) Notwithstanding any other provision of this subpart and any 
revision, made by or submitted to the Administrator after the 
promulgation of the notices of data availability required in paragraphs 
(b)(2)(ii) and (b)(3)(iii)(B) of this section respectively for a 
control period, of any data used in making the calculations referenced 
in such notice, the amount of TR NOX Annual allowances that 
each owner is required to hold in accordance with Sec.  97.406(c)(2)(i) 
for the control period in the year involved shall continue to be such 
amount as calculated by the Administrator and referenced in such notice 
required in paragraph (b)(3)(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 are required to hold in 
accordance with the calculation formula in Sec.  97.406(c)(2)(i) for 
the control period in the year involved with regard to the State 
involved, provided that--
    (A) With regard to such litigation involving such notice required 
in paragraph (b)(2)(ii) of this section, 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)(ii) of this 
section; and
    (B) With regard to such litigation involving such notice required 
in paragraph (b)(3)(iii) of this section, 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)(3)(iii) of this 
section.
    (ii) If any such data are revised by the owners and operators of a 
source whose designated representative submitted such data under 
paragraph (b)(3)(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 are required 
to hold in accordance with the calculation formula in Sec.  
97.406(c)(2)(i) for the control period in the year involved with regard 
to the State involved, provided that such litigation was initiated no 
later than 30 days after promulgation of such notice required in 
paragraph (b)(3)(iii)(B) of this section.
    (iii) If the revised data are used to recalculate, in accordance 
with paragraphs (b)(7)(i) and (b)(7)(ii) of this section, the amount of 
TR NOX Annual allowances that an owner is required to hold 
for the control period in the year involved with regard to the State 
involved-
    (A) Where the amount of TR NOX Annual allowances that an 
owner is 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 owner shall hold the additional amount of TR 
NOX Annual allowances in the compliance account designated 
by the owner in accordance with paragraph (b)(4)(ii) of this section. 
The owner's failure to hold such additional amount, as required, before 
the new deadline shall not be a violation of the Clean Air Act. The 
owner's 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 Annual allowance that the owner fails to hold as 
required as of the new deadline, and each day in the control period in 
the

[[Page 45385]]

year involved, shall be a separate violation of the Clean Air Act. 
After such deadline, the Administrator will make the appropriate 
deductions from the compliance account.
    (B) For an owner 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 the compliance 
account that the owner designated in accordance with paragraph 
(b)(4)(ii) of this section, an amount of TR NOX Annual 
allowances equal to the amount of the decrease to the extent such 
amount was previously deducted from the compliance account under 
paragraph (b)(6) of this section (and has not already been restored to 
the compliance account) for the control period in the year involved.
    (C) Each TR NOX Annual allowance held and deducted under 
paragraph (b)(7)(iii)(A) of this section, or recorded under paragraph 
(b)(7)(iii)(B) of this section, as a result of recalculation of 
requirements under the TR NOX Annual assurance provisions 
for a control period in a given year must be a TR NOX Annual 
allowance allocated for a control period in the same or a prior year.
    (c)(1) Identification of TR NOX Annual allowances by serial number. 
The authorized account representative for each source's compliance 
account designated in accordance with paragraph (b)(4)(ii) of this 
section may request that specific TR NOX Annual allowances, 
identified by serial number, in the compliance account be deducted in 
accordance with paragraph (b)(6) or (7) of this section. In order to be 
complete, such request shall be submitted to the Administrator by the 
allowance-holding deadline described in paragraph (b)(5) of this 
section and include, in a format prescribed by the Administrator, the 
identification of the compliance account and the appropriate serial 
numbers.
    (2) First-in, first-out. The Administrator will deduct TR 
NOX Annual allowances under paragraphs (b)(6) and (7) of 
this section from each source's compliance account designated under 
paragraph (b)(4)(ii) of this section 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 (FIFO) 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) Recordation of deductions. The Administrator will record in the 
appropriate compliance account all deductions from such an account 
under paragraph (b) of this section.


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, 97.428, 97.442, or 97.443.


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 
source's compliance 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, whichever occurs first, after the date on 
which the unit commences commercial operation;
    (3) For 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

[[Page 45386]]

controls is completed after the applicable deadline under paragraph 
(b)(1) or (2) of this section, by 90 unit operating days or 180 
calendar days, whichever occurs first, after the date on which 
emissions first exit to the atmosphere through the new stack or flue or 
add-on NOX emissions controls;
    (4) Notwithstanding the dates in paragraphs (b)(1) and (2) of this 
section, for the owner or operator of a unit for which a TR opt-in 
application is submitted and not withdrawn and is not yet approved or 
disapproved, by the date specified in Sec.  97.441(c); and
    (5) Notwithstanding the dates in paragraphs (b)(1) and (2) of this 
section, for the owner or operator of a TR NOX Annual opt-in 
unit, by the date on which the TR NOX Annual opt-in unit 
enters the TR NOX Annual Trading Program as provided in 
Sec.  97.441(h).
    (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 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 emissions to the atmosphere without accounting for all 
such emissions in accordance with the applicable provisions of this 
subpart and part 75 of this chapter.
    (3) No owner or operator of a 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 emissions 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

[[Page 45387]]

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.
    (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. The 120-day 
review period specified in paragraph (d)(3) of this section shall not 
begin before receipt of a complete certification application.
    (C) Disapproval notice. If the certification application shows that 
any monitoring system does not meet the performance requirements of 
part 75 of this chapter or if the certification application is 
incomplete and the requirement for disapproval under paragraph 
(d)(3)(iv)(B) of this section is met, then the 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

[[Page 45388]]

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 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 
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;
    (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;
    (iii) Notwithstanding paragraphs (d)(1)(i) and (ii) of this 
section, for a unit for which a TR opt-in application is submitted and 
not withdrawn and is not yet approved or disapproved, the calendar 
quarter corresponding to the date specified in Sec.  97.441(c); and
    (iv) Notwithstanding paragraphs (d)(1)(i) and (ii) of this section, 
for a TR NOX Annual opt-in unit, the calendar quarter 
corresponding to the date on which the TR NOX Annual opt-in 
unit enters the TR NOX Annual Trading Program as provided in 
Sec.  97.441(h).
    (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

[[Page 45389]]

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 or paragraph (5)(i) or 
(ii) of the definition of ``owner's share'' in Sec.  97.402.
    (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.


Sec.  97.440  General requirements for TR NOX Annual opt-in units.

    (a) A TR NOX Annual opt-in unit must be a unit that:
    (1) Is located in a State;
    (2) Is not a TR NOX Annual unit under Sec.  97.404;
    (3) Is not covered by a retired unit exemption under Sec.  72.8 of 
this chapter that is in effect; and
    (4) Vents all of its emissions to a stack and can meet the 
monitoring, recordkeeping, and reporting requirements of this subpart.
    (b) A TR NOX Annual opt-in unit shall be deemed to be a 
TR NOX Annual unit for purposes of applying this subpart, 
except for Sec. Sec.  97.405, 97.411, and 97.412.
    (c) Solely for purposes of applying the requirements of Sec. Sec.  
97.413 through 97.418 and Sec. Sec.  97.430 through 97.435, a unit for 
which a TR opt-in application is submitted and not withdrawn and is not 
yet approved or disapproved under Sec.  97.442 shall be deemed to be a 
TR NOX Annual unit.
    (d) Any TR NOX Annual opt-in unit, and any unit for 
which a TR opt-in application is submitted and not withdrawn and is not 
yet approved or disapproved under Sec.  97.442, located at the same 
source as one or more TR NOX Annual units shall have the 
same designated representative and alternate designated representative 
as such TR NOX Annual units.


Sec.  97.441  Opt-In process.

    A unit meeting the requirements for a TR NOX Annual opt-
in unit in Sec.  97.440(a) may become a TR NOX Annual opt-in 
unit only if, in accordance with this section, the designated 
representative of the unit submits a complete TR opt-in application for 
the unit and the Administrator approves the application.
    (a) Applying to opt in. The designated representative of the unit 
may submit a complete TR opt-in application for the unit at any time, 
except as provided under Sec.  97.442(e). A complete TR opt-in 
application shall include the following elements in a format prescribed 
by the Administrator:
    (1) Identification of the unit and the source where the unit is 
located, 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, and unit identification number and 
type;
    (2) A certification that the unit:
    (i) Is not a TR NOX Annual unit under Sec.  97.404;
    (ii) Is not covered by a retired unit exemption under Sec.  72.8 of 
this chapter that is in effect;
    (iii) Vents all of its emissions to a stack; and
    (iv) Has documented heat input (greater than 0 mmBtu) for more than 
876 hours during the 6 months immediately preceding submission of the 
TR opt-in application;
    (3) A monitoring plan in accordance with Sec. Sec.  97.430 through 
97.435;
    (4) A statement that the unit, if approved to become a TR 
NOX Annual unit under paragraph (g) of this section, may 
withdraw from the TR NOX Annual Trading Program only in 
accordance with Sec.  97.442;
    (5) A statement that the unit, if approved to become a TR 
NOX Annual unit under paragraph (g) of this section, is 
subject to, and the owners and operators of the unit must comply with, 
the requirements of Sec.  97.443;
    (6) A complete certificate of representation under Sec.  97.416 
consistent with Sec.  97.440, if no designated representative has been 
previously designated for the source that includes the unit; and
    (7) The signature of the designated representative and the date 
signed.
    (b) Interim review of monitoring plan. The Administrator will 
determine, on an interim basis, the sufficiency of the monitoring plan 
submitted under paragraph (a)(3) of this section. The monitoring plan 
is sufficient, for purposes of interim review, if the plan appears to 
contain information demonstrating that the NOX emission rate 
and heat input of the unit and all other applicable parameters are 
monitored and reported in accordance with Sec. Sec.  97.430 through 
97.435. A determination of sufficiency shall not be construed as 
acceptance or approval of the monitoring plan.
    (c) Monitoring and reporting. (1)(i) If the Administrator 
determines that the monitoring plan is sufficient under paragraph (b) 
of this section, the owner or operator of the unit shall monitor and 
report the NOX emission rate and the heat input of the unit 
and all other applicable parameters, in accordance with Sec. Sec.  
97.430 through 97.435, starting on the date of certification of the 
necessary monitoring systems under Sec. Sec.  97.430 through 97.435 and 
continuing until the TR opt-in application submitted under paragraph 
(a) of this section is disapproved under this section or, if such TR 
opt-in application is approved, the date and time when the unit is 
withdrawn from the TR NOX Annual Trading Program in 
accordance with Sec.  97.442.
    (ii) The monitoring and reporting under paragraph (c)(1)(i) of this 
section shall cover the entire control period immediately before the 
date on which the unit enters the TR NOX Annual Trading 
Program under paragraph (h) of this section, during which period 
monitoring system availability must not

[[Page 45390]]

be less than 98 percent under Sec. Sec.  97.430 through 97.435 and the 
unit must be in full compliance with any applicable State or Federal 
emissions or emissions-related requirements.
    (2) To the extent the NOX emission rate and the heat 
input of the unit are monitored and reported in accordance with 
Sec. Sec.  97.430 through 97.435 for one or more entire control 
periods, in addition to the control period under paragraph (c)(1)(ii) 
of this section, during which control periods monitoring system 
availability is not less than 98 percent under Sec. Sec.  97.430 
through 97.435 and the unit is in full compliance with any applicable 
State or Federal emissions or emissions-related requirements and which 
control periods begin not more than 3 years before the unit enters the 
TR NOX Annual Trading Program under paragraph (h) of this 
section, such information shall be used as provided in paragraphs (e) 
and (f) of this section.
    (d) Statement on compliance. After submitting to the Administrator 
all quarterly reports required for the unit under paragraph (c) of this 
section, the designated representative shall submit, in a format 
prescribed by the Administrator, to the Administrator a statement that, 
for the years covered by such quarterly reports, the unit was in full 
compliance with any applicable State or Federal emissions or emissions-
related requirements.
    (e) Baseline heat input. The unit's baseline heat input shall 
equal:
    (1) If the unit's NOX emission rate and heat input are 
monitored and reported for only one entire control period, in 
accordance with paragraph (c) of this section, the unit's total heat 
input (in mmBtu) for such control period; or
    (2) If the unit's NOX emission rate and heat input are 
monitored and reported for more than one entire control period, in 
accordance with paragraph (c) of this section, the average of the 
amounts of the unit's total heat input (in mmBtu) for such control 
periods.
    (f) Baseline NOX emission rate. The unit's baseline NOX 
emission rate shall equal:
    (1) If the unit's NOX emission rate and heat input are 
monitored and reported for only one entire control period, in 
accordance with paragraph (c) of this section, the unit's 
NOX emission rate (in lb/mmBtu) for such control period;
    (2) If the unit's NOX emission rate and heat input are 
monitored and reported for more than one entire control period, in 
accordance with paragraph (c) of this section, and the unit does not 
have add-on NOX emission controls during any such control 
periods, the average of the amounts of the unit's NOX 
emission rate (in lb/mmBtu) for such control periods; or
    (3) If the unit's NOX emission rate and heat input are 
monitored and reported for more than one entire control period, in 
accordance with paragraph (c) of this section, and the unit has add-on 
NOX emission controls during any such control periods, the 
average of the amounts of the unit's NOX emission rate (in 
lb/mmBtu) for such control periods during which the unit has add-on 
NOX emission controls.
    (g) Review of TR opt-in application.
    (1) After the designated representative submits the complete TR 
opt-in application, quarterly reports, and statement required in 
paragraphs (a), (c), and (d) of this section and if the Administrator 
determines that the designated representative shows that the unit meets 
the requirements for a TR NOX Annual opt-in unit in Sec.  
97.440, the element certified in paragraph (a)(2)(iv) of this section, 
and the monitoring and reporting requirements of paragraph (c) of this 
section, the Administrator will issue a written approval of the TR opt-
in application for the unit. The written approval will state the unit's 
baseline heat input and baseline NOX emission rate. The 
Administrator will thereafter establish a compliance account for the 
source that includes the unit unless the source already has a 
compliance account.
    (2) Notwithstanding paragraphs (a) through (f) of this section, if, 
at any time before the TR opt-in application is approved under 
paragraph (g)(1) of this section, the Administrator determines that the 
unit cannot meet the requirements for a TR NOX Annual opt-in 
unit in Sec.  97.440, the element certified in paragraph (a)(2)(iv) of 
this section, or the monitoring and reporting requirements in paragraph 
(c) of this section, the Administrator will issue a written disapproval 
of the TR opt-in application for the unit.
    (h) Date of entry into TR NOX Annual Trading Program. A unit for 
which a TR opt-in application is approved under paragraph (g)(1) of 
this section shall become a TR NOX Annual opt-in unit, and a 
TR NOX Annual unit, effective as of the later of January 1, 
2012 or January 1 of the first control period during which such 
approval is issued.


Sec.  97.442  Withdrawal of TR NOX Annual opt-in unit from TR NOX 
Annual Trading Program.

    A TR NOX Annual opt-in unit may withdraw from the TR 
NOX Annual Trading Program only if, in accordance with this 
section, the designated representative of the unit submits a request to 
withdraw the unit and the Administrator issues a written approval of 
the request.
    (a) Requesting withdrawal. In order to withdraw the TR 
NOX Annual opt-in unit from the TR NOX Annual 
Trading Program, the designated representative of the unit shall submit 
to the Administrator a request to withdraw the unit effective as of 
midnight of December 31 of a specified calendar year, which date must 
be at least 4 years after December 31 of the year of the unit's entry 
into the TR NOX Annual Trading Program under Sec.  
97.441(h). The request shall be in a format prescribed by the 
Administrator and shall be submitted no later than 90 days before the 
requested effective date of withdrawal.
    (b) Conditions for withdrawal. Before a TR NOX Annual 
opt-in unit covered by the request to withdraw may withdraw from the TR 
NOX Annual Trading Program, the following conditions must be 
met:
    (1) For the control period ending on the date on which the 
withdrawal is to be effective, the source that includes the TR 
NOX Annual opt-in unit must meet the requirement to hold TR 
NOX Annual allowances under Sec. Sec.  97.424 and 97.425 and 
cannot have any excess emissions.
    (2) After the requirement under paragraph (b)(1) of this section is 
met, the Administrator will deduct from the compliance account of the 
source that includes the TR NOX Annual opt-in unit TR 
NOX Annual allowances equal in amount to and allocated for 
the same or a prior control period as any TR NOX Annual 
allowances allocated to the TR NOX Annual opt-in unit under 
Sec.  97.444 for any control period after the date on which the 
withdrawal is to be effective. If there are no other TR NOX 
Annual units at the source, the Administrator will close the compliance 
account, and the owners and operators of the TR NOX Annual 
opt-in unit may submit a TR NOX Annual allowance transfer 
for any remaining TR NOX Annual allowances to another 
Allowance Management System account in accordance with Sec. Sec.  
97.422 and 97.423.
    (c) Approving withdrawal. (1) After the requirements for withdrawal 
under paragraphs (a) and (b) of this section are met (including 
deduction of the full amount of TR NOX Annual allowances 
required), the Administrator will issue a written approval of the 
request to withdraw, which will become effective as of midnight on 
December 31 of the calendar year for which the withdrawal was 
requested. The unit covered by the request shall continue to be a TR 
NOX Annual opt-in unit until the effective date of the 
withdrawal and shall comply with all requirements under the TR 
NOX

[[Page 45391]]

Annual Trading Program concerning any control periods for which the 
unit is a TR NOX Annual opt-in unit, even if such 
requirements arise or must be complied with after the withdrawal takes 
effect.
    (2) If the requirements for withdrawal under paragraphs (a) and (b) 
of this section are not met, the Administrator will issue a written 
disapproval of the request to withdraw. The unit covered by the request 
shall continue to be a TR NOX Annual opt-in unit.
    (d) Reapplication upon failure to meet conditions of withdrawal. If 
the Administrator disapproves the request to withdraw, the designated 
representative of the unit may submit another request to withdraw in 
accordance with paragraphs (a) and (b) of this section.
    (e) Ability to reapply to the TR NOX Annual Trading Program. Once a 
TR NOX Annual opt-in unit withdraws from the TR 
NOX Annual Trading Program, the designated representative 
may not submit another opt-in application under Sec.  97.441 for such 
unit before the date that is 4 years after the date on which the 
withdrawal became effective.


Sec.  97.443  Change in regulatory status.

    (a) Notification. If a TR NOX Annual opt-in unit becomes 
a TR NOX Annual unit under Sec.  97.404, then the designated 
representative of the unit shall notify the Administrator in writing of 
such change in the TR NOX Annual opt-in unit's regulatory 
status, within 30 days of such change.
    (b) Administrator's actions. (1) If a TR NOX Annual opt-
in unit becomes a TR NOX Annual unit under Sec.  97.404, the 
Administrator will deduct, from the compliance account of the source 
that includes the TR NOX Annual opt-in unit that becomes a 
TR NOX Annual unit under Sec.  97.404, TR NOX 
Annual allowances equal in amount to and allocated for the same or a 
prior control period as:
    (i) Any TR NOX Annual allowances allocated to the TR 
NOX Annual opt-in unit under Sec.  97.444 for any control 
period starting after the date on which the TR NOX Annual 
opt-in unit becomes a TR NOX Annual unit under Sec.  97.404; 
and
    (ii) If the date on which the TR NOX Annual opt-in unit 
becomes a TR NOX Annual unit under Sec.  97.404 is not 
December 31, the TR NOX Annual allowances allocated to the 
TR NOX Annual opt-in unit under Sec.  97.444 for the control 
period that includes the date on which the TR NOX Annual 
opt-in unit becomes a TR NOX Annual unit under Sec.  
97.404--
    (A) Multiplied by the ratio of the number of days, in the control 
period, starting with the date on which the TR NOX Annual 
opt-in unit becomes a TR NOX Annual unit under Sec.  97.404, 
divided by the total number of days in the control period, and
    (B) Rounded to the nearest allowance.
    (2) The designated representative shall ensure that the compliance 
account of the source that includes the TR NOX Annual opt-in 
unit that becomes a TR NOX Annual unit under Sec.  97.404 
contains the TR NOX Annual allowances necessary for 
completion of the deduction under paragraph (b)(1) of this section.
    (3)(i) For control periods starting after the date on which the TR 
NOX Annual opt-in unit becomes a TR NOX Annual 
unit under Sec.  97.404, the TR NOX Annual opt-in unit will 
be allocated TR NOX Annual allowances in accordance with 
Sec.  97.412.
    (ii) If the date on which the TR NOX Annual opt-in unit 
becomes a TR NOX Annual unit under Sec.  97.404 is not 
December 31, the following amount of TR NOX Annual 
allowances will be allocated to the TR NOX Annual opt-in 
unit (as a TR NOX Annual unit) in accordance with Sec.  
97.412 for the control period that includes the date on which the TR 
NOX Annual opt-in unit becomes a TR NOX Annual 
unit under Sec.  97.404:
    (A) The amount of TR NOX Annual allowances otherwise 
allocated to the TR NOX Annual opt-in unit (as a TR 
NOX Annual unit) in accordance with Sec.  97.412 for the 
control period;
    (B) Multiplied by the ratio of the number of days, in the control 
period, starting with the date on which the TR NOX Annual 
opt-in unit becomes a TR NOX Annual unit under Sec.  97.404, 
divided by the total number of days in the control period; and (C) 
Rounded to the nearest allowance.


Sec.  97.444  TR NOX Annual allowance allocations to TR NOX Annual opt-
in units.

    (a) Timing requirements. (1) When the TR opt-in application is 
approved for a unit under Sec.  97.441(g), the Administrator will issue 
TR NOX Annual allowances and allocate them to the unit for 
the control period in which the unit enters the TR NOX 
Annual Trading Program under Sec.  97.441(h), in accordance with 
paragraph (b) of this section.
    (2) By no later than October 31 of the control period after the 
control period in which a TR NOX Annual opt-in unit enters 
the TR NOX Annual Trading Program under Sec.  97.441(h) and 
October 31 of each year thereafter, the Administrator will issue TR 
NOX Annual allowances and allocate them to the TR 
NOX Annual opt-in unit for the control period that includes 
such allocation deadline and in which the unit is a TR NOX 
Annual opt-in unit, in accordance with paragraph (b) of this section.
    (b) Calculation of allocation. For each control period for which a 
TR NOX Annual opt-in unit is to be allocated TR 
NOX Annual allowances, the Administrator will issue and 
allocate TR NOX Annual allowances in accordance with the 
following procedures:
    (1) The heat input (in mmBtu) used for calculating the TR 
NOX Annual allowance allocation will be the lesser of:
    (i) The TR NOX Annual opt-in unit's baseline heat input 
determined under Sec.  97.441(g); or
    (ii) The TR NOX Annual opt-in unit's heat input, as 
determined in accordance with Sec. Sec.  97.430 through 97.435, for the 
immediately prior control period, except when the allocation is being 
calculated for the control period in which the TR NOX Annual 
opt-in unit enters the TR NOX Annual Trading Program under 
Sec.  97.441(h).
    (2) The NOX emission rate (in lb/mmBtu) used for 
calculating TR NOX Annual allowance allocations will be the 
lesser of:
    (i) The TR NOX Annual opt-in unit's baseline 
NOX emission rate (in lb/mmBtu) determined under Sec.  
97.441(g) and multiplied by 70 percent; or
    (ii) The most stringent State or Federal NOX emissions 
limitation applicable to the TR NOX Annual opt-in unit at 
any time during the control period for which TR NOX Annual 
allowances are to be allocated.
    (3) The Administrator will issue TR NOX Annual 
allowances and allocate them to the TR NOX Annual opt-in 
unit in an amount equaling the heat input under paragraph (b)(1) of 
this section, multiplied by the NOX emission rate under 
paragraph (b)(2) of this section, divided by 2,000 lb/ton, and rounded 
to the nearest allowance.
    (c) Recordation. (1) The Administrator will record, in the 
compliance account of the source that includes the TR NOX 
Annual opt-in unit, the TR NOX Annual allowances allocated 
to the TR NOX Annual opt-in unit under paragraph (a)(1) of 
this section.
    (2) By December 1 of the control period after the control period in 
which a TR NOX Annual opt-in unit enters the TR 
NOX Annual Trading Program under Sec.  97.441(h) and 
December 1 of each year thereafter, the Administrator will record, in 
the compliance account of the source that includes the TR 
NOX Annual opt-in unit, the TR NOX Annual 
allowances allocated to the TR NOX

[[Page 45392]]

Annual opt-in unit under paragraph (a)(2) of this section.
    36. Part 97 is amended by adding subpart BBBBB to read as follows:
Subpart BBBBB--TR NOX Ozone Season Trading Program
Sec.
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, and variability limits.
97.511 Timing requirements for TR NOX Ozone Season 
allowance allocations.
97.512 TR NOX Ozone Season allowance allocations for 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 Allowance Management System 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.
97.540 General requirements for TR NOX Ozone Season opt-
in units.
97.541 Opt-in process.
97.542 Withdrawal of TR NOX Ozone Season opt-in unit from 
TR NOX Ozone Season Trading Program.
97.543 Change in regulatory status.
97.544 TR NOX Ozone Season allowance allocations to TR 
NOX Ozone Season opt-in units.

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.  52.37(b) of this chapter, as a means of 
mitigating interstate transport of fine particulates 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) 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 of the 
amount of such TR NOX Ozone Season allowances to be 
initially credited to a TR NOX Ozone Season source or a new 
unit set-aside.
    Allowable NOX emission rate means, with regard to a unit, the 
NOX emission rate limit 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, held, 
deducted, or transferred only as whole allowances. The Allowance 
Management System is a component of the CAMD Business System, which is 
the system used by the Administrator to handle TR NOX Ozone 
Season allowances and data related to NOX emissions.
    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, 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.  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 Sec.  
72.2 of this chapter, Sec.  97.402, Sec.  97.602, or Sec.  97.702 
respectively.
    Authorized account representative means, with regard to 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, with regard to 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;

[[Page 45393]]

    (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.
    Certifying official means a natural person who is:
    (1) For a corporation, a president, secretary, treasurer, or vice-
president or 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 any solid fuel classified as anthracite, bituminous, 
subbituminous, or lignite.
    Coal-derived fuel means any fuel (whether in a solid, liquid, or 
gaseous state) produced by the mechanical, thermal, or chemical 
processing of coal.
    Coal-fired means combusting any amount of coal or coal-derived 
fuel, alone or in combination with any amount of any other fuel, during 
1990 or any year thereafter.
    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--
    (1) Operating as part of a cogeneration system; and
    (2) Producing during the later of 1990 or the 12-month period 
starting on the date that the unit first produces electricity and 
during each calendar year after the later of 1990 or the calendar year 
in which the unit first produces electricity--
    (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 then 42.5 percent of total energy input, 
if useful thermal energy produced is 15 percent or more of total energy 
output, or not less than 45 percent of total energy input, if useful 
thermal energy produced is less than 15 percent of total energy output.
    (ii) For a bottoming-cycle unit, useful power not less than 45 
percent of total energy input;
    (3) 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
    (4) Provided that, if a topping-cycle unit is operated as part of a 
cogeneration system during a calendar year and the cogeneration system 
meets on a system-wide basis the requirement in paragraph (2)(i)(B) of 
this definition, the topping-cycle unit shall be deemed to meet such 
requirement during that 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 November 15, 1990 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 (other than replacement of the unit by a unit at the 
same 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 November 15, 1990 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 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 November 15, 1990 
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 
and that subsequently undergoes a physical change (other than 
replacement of the unit by a unit at the same source), such date shall 
remain the 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 
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.
    Commence operation means, with regard to a unit:
    (1) To have begun any mechanical, chemical, or electronic process, 
including start-up of the unit's combustion chamber.
    (2) For a unit that undergoes a physical change (other than 
replacement of the unit by a unit at the same source)

[[Page 45394]]

after the date the unit commences operation as defined in paragraph (1) 
of this definition, such date shall remain the date of commencement of 
operation of the unit, which shall continue to be treated as the same 
unit.
    (3) For a unit that is replaced by a unit at the same source after 
the date the unit commences operation as defined in paragraph (1) of 
this definition, such date shall remain the replaced unit's date of 
commencement of operation, and the replacement unit shall be treated as 
a separate unit with a separate date for commencement of operation as 
defined in paragraph (1), (2), or (3) of this definition as 
appropriate.
    Common stack means a single flue through which emissions from 2 or 
more units are exhausted.
    Compliance account means 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 for 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 
complying with the source's TR NOX Ozone Season emissions 
limitation in accordance with Sec.  97.524 and the TR NOX 
Ozone Season assurance provisions in accordance with Sec.  97.525.
    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 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 Sec.  72.2 of this chapter, Sec.  97.402, Sec.  97.602, or Sec.  
97.702 respectively.
    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 in accordance with this subpart.
    Excess emissions means any ton of NOX emitted from the 
TR NOX Ozone Season units at a TR NOX Ozone 
Season source during a control period that exceeds the TR 
NOX Ozone Season emissions limitation for the source.
    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 Sec. Sec.  97.504(b)(2)(i)(B), 
97.504(b)(2)(ii)(B), and 97.504(b)(2)(iii), 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 1990 or any calendar year thereafter.
    Fuel oil means any petroleum-based fuel (including diesel fuel or 
petroleum derivatives such as oil tar) and any recycled or blended 
petroleum products or petroleum by-products used as a fuel whether in a 
liquid, solid, or gaseous state.
    General account means an Allowance Management System account, 
established under this subpart, that is not a compliance account.
    Generator means a device that produces electricity.
    Gross electrical output means, with regard to 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, with regard to a unit for a specified period of 
time, the product (in mmBtu/time) of the gross calorific value of the 
fuel (in mmBtu/lb) multiplied by the fuel feed rate into a combustion 
device (in lb of fuel/time), as measured, recorded, and reported to the 
Administrator by the 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 the amount of heat input (in mmBtu) divided 
by unit operating time (in hr) or, with regard to a specific fuel, the 
amount of heat input attributed to the fuel (in mmBtu) divided by the 
unit operating time (in hr) during which the unit combusts the fuel.
    Life-of-the-unit, firm power contractual arrangement means a unit 
participation power sales agreement under which a utility or industrial 
customer reserves, or is entitled to receive, a specified amount or 
percentage of nameplate capacity and associated energy generated by any 
specified unit and pays its proportional amount of such unit's total 
costs, pursuant to a contract:
    (1) For the life of the unit;

[[Page 45395]]

    (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 the maximum amount of fuel per hour 
(in Btu/hr) that a 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) 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 (in MWe) that the generator is 
capable of producing on a steady state basis and during continuous 
operation (when not restricted by seasonal or other deratings), such 
increased maximum amount as of such completion as specified by the 
person conducting the physical change.
    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 any person who operates, controls, or supervises a 
TR NOX Ozone Season unit or a TR NOX Ozone Season 
source and shall include, but not be limited to, any holding company, 
utility system, or plant manager of such a unit or source.
    Owner means, with regard to 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;
    (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;
    (4) Provided that, for purposes of applying the TR NOX 
Ozone Season assurance provisions in Sec. Sec.  97.506(c)(2) and 
97.525, if one or more owners (as defined in paragraphs (1) through (3) 
of this definition) of one or more TR NOX Ozone Season units 
in a State are wholly owned by another, common owner, all such owners 
shall be treated collectively as a single owner in the State.
    Owner's assurance level means:
    (1) With regard to a State and control period for which the State 
assurance level is exceeded as described in Sec.  97.506(c)(2)(iii)(A) 
and not as described in Sec.  97.506(c)(2)(iii)(B), the owner's share 
of the State NOX Ozone Season trading budget with the one-
year variability limit for the State for such control period; or
    (2) With regard to a State and control period for which the State 
assurance level is exceeded as described in Sec.  97.506(c)(2)(iii)(B), 
the owner's share of the State NOX Ozone Season trading 
budget with the three-year variability limit for the State for such 
control period.
    Owner's share means:
    (1) With regard to a total amount of NOX emissions from 
all TR NOX Ozone Season units in a State during a control 
period, the total tonnage of NOX emissions during such 
control period from all of the owner's TR NOX Ozone Season 
units in the State;
    (2) With regard to a State NOX Ozone Season trading 
budget with a one-year variability limit for a control period, the 
amount (rounded to the nearest allowance) equal to the total amount of 
TR NOX Ozone Season allowances allocated for such control 
period to all of the owner's TR NOX Ozone Season units in 
the State, multiplied by the sum of the State NOX Ozone 
Season trading budget under Sec.  97.510(a) and the State's one-year 
variability limit under Sec.  97.510(b) and divided by such State 
NOX Ozone Season trading budget;
    (3) With regard to a State NOX Ozone Season trading 
budget with a three-year variability limit for a control period, the 
amount (rounded to the nearest allowance) equal to the total amount of 
TR NOX Ozone Season allowances allocated for such control 
period to all of the owner's TR NOX Ozone Season units in 
the State, multiplied by the sum of the State NOX Ozone 
Season trading budget under Sec.  97.510(a) and the State's three-year 
variability limit under Sec.  97.510(b) and divided by such State 
NOX Ozone Season trading budget;
    (4) Provided that, in the case of a unit with more than one owner, 
the amount of tonnage of NOX emissions and of TR 
NOX Ozone Season allowances allocated for a control period, 
with regard to such unit, used in determining each owner's share shall 
be the amount (rounded to the nearest ton and the nearest allowance) 
equal to the unit's NOX emissions and allocation of such 
allowances, respectively, for such control period multiplied by the 
percentage of ownership in the unit that the owner's legal, equitable, 
leasehold, or contractual reservation or entitlement in the unit 
comprises as of September 30 of such control period;
    (5) Provided that, where two or more units emit through a common 
stack that is the monitoring location from which NOX mass 
emissions are reported for a control period for a year, the amount of 
tonnage of each unit's NOX emissions used in determining 
each owner's share for such control period shall be:
    (i) The amount (rounded to the nearest ton) of NOX 
emissions reported at the common stack multiplied by the quotient of 
such unit's heat input for such control period divided by the total 
heat input reported from the common stack for such control period;
    (ii) An amount determined in accordance with a methodology that the 
Administrator determines is consistent with the purposes of this 
definition and whose adverse effect (if any) the Administrator 
determines will be de minimis; or
    (iii) An amount approved by the Administrator in response to a 
petition for an alternative requirement submitted in accordance with 
Sec.  97.535; and
    (6) Provided that, in the case of a unit that operates during, but 
is allocated no TR NOX Ozone Season allowances for, a 
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 lesser of--

[[Page 45396]]

    (i) The unit's allowable NOX emission rate (in lb per 
MWe) applicable to such control period, multiplied by a capacity factor 
of 0.89 (if the unit is a coal-fired boiler), 0.22 (if the unit is a 
simple combustion turbine), or 0.72 (if the unit is a combined cycle 
turbine), 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; or
    (ii) For a unit listed in appendix A to this subpart, the sum of 
the unit's NOX emissions in the control period in the last 
three years during which the unit operated during the control period, 
divided by three.
    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 33 percent of a unit's 
maximum design heat input, divided by 3,413 Btu/kWh, divided by 1,000 
kWh/MWh, and multiplied by 8,760 hr/yr.
    Receive or receipt of means, when referring to the 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, 
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) For a topping-cycle unit, the use of reject heat from 
electricity production in a useful thermal energy application or 
process; or
    (2) For a bottoming-cycle unit, 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 or the District of Columbia that is 
subject to the TR NOX Ozone Season Trading Program pursuant 
to Sec.  52.37(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 total energy of all forms supplied to a 
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 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 by the 
Administrator in accordance with subpart AAAAA of this part and 
52.37(a) 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 by the Administrator under this subpart to emit one ton 
of NOX during a control period of the specified calendar 
year for which the authorization is allocated or of any calendar year 
thereafter under the TR NOX Ozone Season 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 assurance provisions.
    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 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 Trading Program means a multi-state 
NOX air pollution control and emission reduction program 
established by the Administrator in accordance with this subpart and 
52.37(b) of this chapter, as a means of mitigating interstate transport 
of ozone and NOX.
    TR NOX Ozone Season source means a source that includes one or more 
TR NOX Ozone Season units.

[[Page 45397]]

    TR NOX Ozone Season unit means a unit that is subject to the TR 
NOX Ozone Season Trading Program under Sec.  97.504.
    TR SO2 Group 1 Trading Program means a multi-state SO2 
air pollution control and emission reduction program established by the 
Administrator in accordance with subpart CCCCC of this part and 
52.38(b) 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 by the 
Administrator in accordance with subpart DDDDD of this part and 
52.38(c) 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.
    Unit operating day means a calendar day in which a unit combusts 
any fuel.
    Unit operating hour or hour of unit operation means an hour in 
which a unit combusts any fuel.
    Useful power means electricity or mechanical energy that a 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 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, 
since the later of November 15, 1990 or the start-up of the unit's 
combustion chamber, 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 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), (b)(2)(i), or (b)(2)(ii) 
of this section shall not be a TR NOX Ozone Season unit:
    (1)(i) Any unit:
    (A) Qualifying as a cogeneration unit during the later of 1990 or 
the 12-month period starting on the date the unit first produces 
electricity and continuing to qualify as a cogeneration unit; and
    (B) Not serving at any time, since the later of November 15, 1990 
or the start-up of the unit's combustion chamber, a generator with 
nameplate capacity of more than 25 MWe supplying in any calendar year 
more than one-third of the unit's potential electric output capacity or 
219,000 MWh, whichever is greater, to any utility power distribution 
system for sale.
    (ii) If a unit qualifies as a cogeneration unit during the later of 
1990 or the 12-month period starting on the date the unit first 
produces electricity and meets the requirements of paragraphs (b)(1)(i) 
of this section for at least one calendar year, but subsequently no 
longer meets such qualification and requirements, 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.
    (2)(i) Any unit commencing operation before January 1, 1985:
    (A) Qualifying as a solid waste incineration unit during the later 
of 1990 or the 12-month period starting on the date the unit first 
produces electricity and continuing to qualify as a solid waste 
incineration unit; and
    (B) With an average Ozone Season fuel consumption of fossil fuel 
for 1985-1987 less than 20 percent (on a Btu basis) and an average 
Ozone Season fuel consumption of fossil fuel for any 3 consecutive 
calendar years after 1990 less than 20 percent (on a Btu basis).
    (ii) Any unit commencing operation on or after January 1, 1985:
    (A) Qualifying as a solid waste incineration unit during the later 
of 1990 or the 12-month period starting on the date the unit first 
produces electricity and continuing to qualify as a solid waste 
incineration unit; and
    (B) With an average Ozone Season fuel consumption of fossil fuel 
for the first 3 calendar years of operation less than 20 percent (on a 
Btu basis) and an average Ozone Season fuel consumption of fossil fuel 
for any 3 consecutive calendar years after 1990 less than 20 percent 
(on a Btu basis).
    (iii) If a unit qualifies as a solid waste incineration unit during 
the later of 1990 or the 12-month period starting on the date the unit 
first produces electricity and meets the requirements of paragraph 
(b)(2)(i) or (ii) of this section for at least 3 consecutive calendar 
years, but subsequently no longer meets such qualification and 
requirements, 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 1990 for which the unit has an average Ozone Season fuel 
consumption of fossil fuel of 20 percent or more.
    (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, 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

[[Page 45398]]

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 
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 and is not a TR NOX Ozone Season opt-in unit 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, 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 a TR NOX Ozone Season source emits 
NOX during any control period 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 pay any fine, penalty, or assessment or comply with 
any other remedy imposed, for the same violations, under the Clean Air 
Act; and
    (B) 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 the 
total amount of NOX emissions from all TR NOX 
Ozone Season units in a State during a control period in 2014 or any 
year thereafter exceeds the State assurance level as described in 
paragraph (c)(2)(iii) of this section, then each owner whose share of 
such NOX emissions during such control period exceeds the 
owner's assurance level for the State and such control period shall 
hold, in a compliance account designated by the owner in accordance 
with Sec.  97.525(b)(4)(ii), TR NOX Ozone Season allowances 
available for deduction for such control period under Sec.  97.525(a) 
in an amount equal to the product, as determined by the Administrator 
in accordance with Sec.  97.525(b), of multiplying--
    (A) The quotient (rounded to the nearest whole number) of the 
amount by which the owner's share of such NOX emissions 
exceeds the owner's assurance level divided by the sum of the amounts, 
determined for all such owners, by which each owner's share of such 
NOX emissions exceeds that owner's assurance level; and
    (B) The amount by which total NOX emissions for all TR 
NOX Ozone Season

[[Page 45399]]

units in the State for such control period exceed the State assurance 
level as determined in accordance with paragraph (c)(2)(iii) of this 
section.
    (ii) The owner shall hold the TR NOX Ozone Season 
allowances required under paragraph (c)(2)(i) of this section, as of 
midnight of August 1 (if it is a business day), or midnight of the 
first business day thereafter (if August 1 is not a business day), 
immediately after such control period.
    (iii) The total amount of NOX emissions from all TR 
NOX Ozone Season units in a State during a control period in 
2014 or any year thereafter exceeds the State assurance level:
    (A) If such total amount of NOX emissions exceeds the 
sum, for such control period, of the State NOX Ozone Season 
trading budget and the State's one-year variability limit under Sec.  
97.510(b); or
    (B) If, with regard to a control period in 2016 or any year 
thereafter, the sum, divided by three, of such total amount of 
NOX emissions and the total amounts of NOX 
emissions from all TR NOX Ozone Season units in the State 
during the control periods in the immediately preceding two years 
exceeds the sum, for such control period, of the State NOX 
Ozone Season trading budget and the State's three-year variability 
limit under Sec.  97.510(b);
    (C) Provided that the amount by which such total amount of 
NOX emissions exceeds the State assurance level shall be the 
greater of the amounts of the exceedance calculated under paragraph 
(c)(2)(iii)(A) of this section and under paragraph (c)(2)(iii)(B) of 
this section.
    (iv) It shall not be a violation of this subpart or of the Clean 
Air Act if the total amount of NOX emissions from all TR 
NOX Ozone Season units in a State during a control period 
exceeds the State assurance level or if an owner's share of total 
NOX emissions from the TR NOX Ozone Season units 
in a State during a control period exceeds the owner's assurance level.
    (v) To the extent an owner fails to hold TR NOX Ozone 
Season allowances for a control period in accordance with paragraphs 
(c)(2)(i) and (ii) of this section,
    (A) The owner 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 owner 
fails to hold for a control period in accordance with paragraphs 
(c)(2)(i) and (ii) 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:
    (i) Under paragraph (c)(1) of this section for the control period 
starting on the later of September 1, 2012 or the deadline for meeting 
the unit's monitor certification requirements under Sec.  97.530(b) and 
for each control period thereafter; and
    (ii) Under paragraph (c)(2) of this section for the control period 
starting on the later of September 1, 2014 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 deducted allowances. A TR NOX Ozone 
Season allowance shall not be deducted, for compliance with the 
requirements under paragraphs (c)(1) and (2) of this section, for a 
control period in a calendar year before the year for which the TR 
NOX Ozone Season allowance was allocated.
    (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. (i) A TR NOX Ozone Season 
allowance is a limited authorization to emit one ton of NOX 
in accordance with the TR NOX Ozone Season Trading Program.
    (ii) Notwithstanding any other provision of this subpart, the 
Administrator has the authority to terminate or limit 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 documents are superseded 
because of the submission of a new certificate of representation under 
Sec.  97.516 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 Ozone Season 
Trading Program, including any monitoring plans and monitoring system 
certification and recertification applications.
    (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, including any submissions required for 
compliance with the TR NOX Ozone Season assurance 
provisions. This requirement does not change, create an exemption from, 
or or otherwise affect the responsible official submission requirements 
under a title V operating

[[Page 45400]]

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, falls on a 
weekend or a State or Federal holiday, 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, and variability limits.

    (a) The State NOX Ozone Season trading budgets and 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    New-unit set-
                                      trading budget      aside (tons)
                                         (tons)*      ------------------
               State               -------------------
                                       For 2012 and       For 2012 and
                                        thereafter         thereafter
------------------------------------------------------------------------
Alabama...........................             29,738                892
Arkansas..........................             16,660                500
Connecticut.......................              1,315                 39
Delaware..........................              2,450                 74
District of Columbia..............                105                  3
Florida...........................             56,939              1,708
Georgia...........................             32,144                964
Illinois..........................             23,570                707
Indiana...........................             49,987              1,500
Kansas............................             21,433                643
Kentucky..........................             30,908                927
Louisiana.........................             21,220                637
Maryland..........................              7,232                217
Michigan..........................             28,253                848
Mississippi.......................             16,530                496
New Jersey........................              5,269                158
New York..........................             11,090                333
North Carolina....................             23,539                706
Ohio..............................             40,661              1,220
Oklahoma..........................             37,087              1,113
Pennsylvania......................             48,271              1,448
South Carolina....................             15,222                457
Tennessee.........................             11,575                347
Texas.............................             75,574              2,267
Virginia..........................             12,608                378
West Virginia.....................             22,234                667
                                   -------------------------------------
    Total.........................            641,614             19,249
------------------------------------------------------------------------
* Without variability limits.

    (b) The States' one-year and three-year variability limits for the 
State NOX Ozone Season trading budgets for the control 
periods in 2014 and thereafter are as follows:

[[Page 45401]]



------------------------------------------------------------------------
                                         One-year          Three-year
                                       variability        variability
                                          limits             limits
               State               -------------------------------------
                                         2014 and           2016 and
                                    thereafter (tons)  thereafter (tons)
------------------------------------------------------------------------
Alabama...........................              2,974              1,717
Arkansas..........................              2,100              1,212
Connecticut.......................              2,100              1,212
Delaware..........................              2,100              1,212
District of Columbia..............              2,100              1,212
Florida...........................              5,694              3,287
Georgia...........................              3,214              1,856
Illinois..........................              2,357              1,361
Indiana...........................              4,999              2,886
Kansas............................              2,143              1,237
Kentucky..........................              3,091              1,784
Louisiana.........................              2,122              1,225
Maryland..........................              2,100              1,212
Michigan..........................              2,825              1,631
Mississippi.......................              2,100              1,212
New Jersey........................              2,100              1,212
New York..........................              2,100              1,212
North Carolina....................              2,354              1,359
Ohio..............................              4,066              2,348
Oklahoma..........................              3,709              2,141
Pennsylvania......................              4,827              2,787
South Carolina....................              2,100              1,212
Tennessee.........................              2,100              1,212
Texas.............................              7,557              4,363
Virginia..........................              2,100              1,212
West Virginia.....................              2,223              1,284
------------------------------------------------------------------------

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 set forth in appendix A to this subpart. Listing a unit 
in such appendix does not constitute a determination that the unit is a 
TR NOX Ozone Season unit, and not listing a unit in such 
appendix 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 
listed in appendix A to this subpart as being allocated TR 
NOX Ozone Season allowances does not operate, starting after 
2011, during the control period in three consecutive years, such unit 
will not be allocated the TR NOX Ozone Season allowances set 
forth in appendix A to this subpart for the unit for the control 
periods in the seventh year after the first such year and in each year 
after that seventh 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 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) By April 1, 2012 and April 1 of each year 
thereafter, the Administrator will calculate the TR NOX 
Ozone Season allowance allocation for each TR NOX Ozone 
Season unit, in accordance with Sec.  97.512, for the control period in 
the year of the applicable calculation deadline under this paragraph 
and will promulgate a notice of availability of the results of the 
calculations.
    (2) For each notice of data availability required in paragraph 
(b)(1) of this section, the Administrator will provide an opportunity 
for submission of objections to the calculations referenced in such 
notice.
    (i) Objections shall be submitted by the deadline specified in such 
notice and shall be limited to addressing whether the calculations are 
in accordance with Sec.  97.512 and Sec. Sec.  97.506(b)(2) and 97.530 
through 97.535.
    (ii) 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)(i) of this section. By June 1 
immediately after the promulgation of such notice, the Administrator 
will promulgate a notice of 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)(i) of this section.
    (c) Units that are not TR NOX Ozone Season units. 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 for the control period to a recipient that is not 
actually a TR NOX Ozone Season unit under Sec.  97.504 as of 
May 1, 2012 or whose deadline for meeting monitor certification 
requirements under Sec.  97.530(b)(1) and (2) is after May 1, 2012 or 
if the Administrator determines that TR NOX Ozone Season 
allowances were allocated under paragraph (b) of this section and Sec.  
97.512 for the control period to a recipient that is not actually a TR 
NOX Ozone Season unit under Sec.  97.504 as of May 1 of the 
control period, then the Administrator will notify the designated 
representative and will act in accordance with the following 
procedures:
    (1) Except as provided in paragraph (c)(2) or (3) of this section, 
the Administrator will not record such TR NOX Ozone Season 
allowances under Sec.  97.521.
    (2) If the Administrator already recorded such TR NOX 
Ozone Season allowances under Sec.  97.521 and if the Administrator 
makes such determination 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

[[Page 45402]]

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.
    (3) If the Administrator already recorded such TR NOX 
Ozone Season allowances under Sec.  97.521 and if the Administrator 
makes such determination 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.
    (4) The Administrator will transfer the TR NOX Ozone 
Season allowances that are not recorded, or that are deducted, in 
accordance with paragraphs (c)(1) and (2) of this section to the new 
unit set-aside, for the State in which such recipient is located, for 
the control period in the year of such transfer if the notice required 
in paragraph (b)(1) of this section for the control period in that year 
has not been promulgated or, if such notice has been promulgated, in 
the next year.


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

    (a) For each control period in 2012 and thereafter, the 
Administrator will allocate, in accordance with the following 
procedures, TR NOX Ozone Season allowances to TR 
NOX Ozone Season units in a State that are not listed in 
appendix A to this subpart, to TR NOX Ozone Season units 
that are so listed and whose allocation of NOX Ozone Season 
allowances for such control period is covered by Sec.  97.511(c)(1) or 
(2), and to TR NOX Ozone Season units that are so listed 
and, pursuant to Sec.  97.511(a)(2), are not allocated TR 
NOX Ozone Season allowances for such control period but that 
operate during the immediately preceding control period:
    (1) The Administrator will establish a separate new unit set-aside 
for each State for each control period in a given year. Each 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). Each new unit set-aside will 
be allocated additional TR NOX Ozone Season allowances in 
accordance with Sec.  97.511(a)(2) and (c)(4).
    (2) The designated representative of such TR NOX Ozone 
Season unit may submit to the Administrator a request, in a format 
prescribed by the Administrator, to be allocated TR NOX 
Ozone Season allowances for a control period, starting with the later 
of the control period in 2012, the first control period after the 
control period in which the TR NOX Ozone Season unit 
commences commercial operation (for a unit not listed in appendix A to 
this subpart), or the first control period after the control period in 
which the unit resumes operation (for a unit listed in appendix A of 
this subpart) and for each subsequent control period.
    (i) The request must be submitted on or before February 1 
immediately preceding the first control period for which TR 
NOX Ozone Season allowances are sought and after the date on 
which the TR NOX Ozone Season unit commences commercial 
operation (for a unit not listed in appendix A of this subpart) or on 
which the unit resumes operation (for a unit listed in appendix A of 
this subpart).
    (ii) For each control period for which an allocation is sought, the 
request must be for TR NOX Ozone Season allowances in an 
amount equal to the unit's total tons of NOX emissions 
during the immediately preceding control period.
    (3) The Administrator will review each TR NOX Ozone 
Season allowance allocation request under paragraph (a)(2) of this 
section and will accept the request only if it meets the requirements 
of paragraph (a)(2) of this section. The Administrator will allocate TR 
NOX Ozone Season allowances for each control period pursuant 
to an accepted request as follows:
    (i) After February 1 immediately preceding such control period, the 
Administrator will determine the sum of the TR NOX Ozone 
Season allowances requested in all accepted allowance allocation 
requests for such control period.
    (ii) If the amount of TR NOX Ozone Season allowances in 
the new unit set-aside for such control period is greater than or equal 
to the sum under paragraph (a)(3)(i) of this section, then the 
Administrator will allocate the amount of TR NOX Ozone 
Season allowances requested to each TR NOX Ozone Season unit 
covered by an accepted allowance allocation request.
    (iii) If the amount of TR NOX Ozone Season allowances in 
the new unit set-aside for such control period is less than the sum 
under paragraph (a)(3)(i) of this section, then the Administrator will 
allocate to each TR NOX Ozone Season unit covered by an 
accepted allowance allocation request the amount of the TR 
NOX Ozone Season allowances requested, multiplied by the 
amount of TR NOX Ozone Season allowances in the new unit 
set-aside for such control period, divided by the sum determined under 
paragraph (a)(3)(i) of this section, and rounded to the nearest 
allowance.
    (iv) The Administrator will notify, through the promulgation of the 
notices of data availability described in Sec.  97.511(b), each 
designated representative that submitted an allowance allocation 
request of the amount of TR NOX Ozone Season allowances (if 
any) allocated for such control period to the TR NOX Ozone 
Season unit covered by the request.
    (b) If, after completion of the procedures under paragraph (a)(4) 
of this section for a control period, any unallocated TR NOX 
Ozone Season allowances remain in the new unit set-aside under 
paragraph (a) of this section for a State for such control period, the 
Administrator will allocate to each TR NOX Ozone Season unit 
that is in the State, is listed in appendix A to this subpart, 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 amount of tons in 
such new unit set-aside, and rounded to the nearest allowance.


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

[[Page 45403]]

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'' 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 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.

    (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 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, including the addition of a new 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 include the 
change.


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, and actual or projected date of 
commencement of commercial operation.
    (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--

[[Page 45404]]

    (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 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.
    (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 Sec.  97.515(a) or (b), 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 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 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 Allowance Management System 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

[[Page 45405]]

shall be the authorized account representative and the alternate 
authorized account representative respectively of the compliance 
account.
    (b) General accounts--(1) Application for general account. (i) Any 
person may apply to open a general account, for the purpose of holding 
and transferring 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 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 order or decision 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 order or decision issued to the authorized 
account representative or alternate authorized account representative 
by the Administrator regarding the general account.
    (ii) Except as provided in paragraph (b)(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 (b)(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 (b)(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

[[Page 45406]]

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 of a new 
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 (b)(1) of this 
section has been submitted and received, the Administrator will rely on 
the application unless and until a superseding complete application for 
a general account under paragraph (b)(1) of this section is received by 
the Administrator.
    (ii) Except as provided in paragraph (b)(3)(i) or (ii) of this 
section, no objection or other communication submitted to the 
Administrator concerning the authorization, or any representation, 
action, inaction, or submission of the 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 make an electronic 
submission to the Administrator in accordance with paragraph (b)(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 as an ``agent'');
    (C) For each such natural person, a list of the type or types of 
electronic submissions under paragraph (b)(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(b)(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(b)(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(b)(5) is terminated.''.
    (iv) A notice of delegation submitted under paragraph (b)(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 (b)(5)(iii)(D) of this section and made in accordance with a 
notice of delegation effective under paragraph (b)(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)(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 20 
business days after the notice is sent. The account will be closed 
after the 20-day period unless, before the end of the 20-day period, 
the Administrator receives a correctly submitted 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

[[Page 45407]]

cause as to why the account should not be closed.
    (c) Account identification. The Administrator will assign a unique 
identifying number to each account established under paragraph (a) or 
(b) of this section.
    (d) Responsibilities of authorized account representative and 
alternate authorized account representative. After the establishment of 
an Allowance Management System 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 (b)(2)(ii) and (b)(5) of 
this section.


Sec.  97.521  Recordation of TR NOX Ozone Season allowance allocations.

    (a) By September 1, 2011, the Administrator will record in each TR 
NOX Ozone Season source's compliance account the TR 
NOX Ozone Season allowances allocated for the TR 
NOX Ozone Season units at the source in accordance with 
Sec. Sec.  97.511(a) for the control periods in 2012, 2013, and 2014.
    (b) By June 1, 2012 and June 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 for the TR NOX Ozone Season units at 
the source in accordance with Sec.  97.511(a) for the control period in 
the third year after the year of the applicable recordation deadline 
under this paragraph.
    (c) By June 1, 2012 and June 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 for the TR NOX Ozone Season units at 
the source in accordance with Sec.  97.512 for the control period in 
the year of the applicable recordation deadline under this paragraph.
    (d) When recording the allocation of TR NOX Ozone Season 
allowances for a TR NOX Ozone Season unit in a compliance 
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.


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, 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 by the request, provided that the transfer is correctly 
submitted under Sec.  97.522.
    (b)(1) A TR NOX Ozone Season allowance transfer 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 under Sec.  97.524 for the control period 
immediately before such allowance transfer deadline.
    (2) A TR NOX Ozone Season allowance transfer that is 
submitted for recordation after the deadline for holding TR 
NOX Ozone Season allowances described in Sec.  97.525(b)(5) 
and that includes any TR NOX Ozone Season allowances 
allocated for a control period before the year of such deadline will 
not be recorded until after the Administrator completes the deductions 
under Sec.  97.525 for the control period immediately before the year 
of such 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 the control period in the year or 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, the Administrator will deduct from the 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

[[Page 45408]]

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 (FIFO) 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 the control period 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 an owner of one or more TR NOX Ozone 
Season units in a State only if the TR NOX Ozone Season 
allowances:
    (1) Were allocated for the control period in the year or a prior 
year; and
    (2) Are held in a compliance account, designated by the owner in 
accordance with paragraph (b)(4)(ii) of this section, of one of the 
owner's TR NOX Ozone Season sources in the State as of the 
deadline established in paragraph (b)(5) 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 March 1, 2015 and March 1 of each year thereafter, the 
Administrator will:
    (i) Calculate, separately for each State, the total amount of 
NOX emissions from all TR NOX Ozone Season units 
in the State during the control period in the year before the year of 
this calculation deadline and the amount, if any, by which such total 
amount of NOX emissions exceeds the State assurance level as 
described in Sec.  97.506(c)(2)(iii); and
    (ii) Promulgate a notice of availability of the results of the 
calculations required in paragraph (b)(1)(i) of this section, including 
separate calculations of the NOX emissions for each TR 
NOX Ozone Season unit and of the amounts described in 
Sec. Sec.  97.506(c)(2)(iii)(A) and (B) for each State.
    (2) The Administrator will provide an opportunity for submission of 
objections to the calculations referenced by each notice described in 
paragraph (b)(1) of this section.
    (i) Objections shall be submitted by the deadline specified in such 
notice and shall be limited to addressing whether the calculations for 
each TR NOX Ozone Season unit and each State for the control 
period in the year involved are in accordance with Sec.  
97.506(c)(2)(iii) and Sec. Sec.  97.506(b) and 97.530 through 97.535.
    (ii) 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)(i) of this section. By May 1 immediately 
after the promulgation of such notice, the Administrator will 
promulgate a notice of 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)(i) of this section.
    (3) For each notice of data availability required in paragraph 
(b)(2)(ii) of this section and for any State identified in such notice 
as having TR NOX Ozone Season sources with total 
NOX emissions exceeding the State assurance level for a 
control period, as described in Sec.  97.506(c)(2)(iii):
    (i) By May 15 immediately after the promulgation of such notice, 
the designated representative of each TR NOX Ozone Season 
source in each such State shall submit a statement, in a format 
prescribed by the Administrator:
    (A) Listing all the owners of each TR NOX Ozone Season 
unit at the source, explaining how the selection of each owner for 
inclusion on the list is consistent with the definition of ``owner'' in 
Sec.  97.502, and listing, separately for each unit, the percentage of 
the legal, equitable, leasehold, or contractual reservation or 
entitlement for each such owner as of midnight of December 31 of the 
control period in the year involved; and
    (B) For each TR NOX Ozone Season unit at the source that 
operates during, but is allocated no TR NOX Ozone Season 
allowances for, the control period in the year involved, identifying 
whether the unit is a coal-fired boiler, simple combustion turbine, or 
combined cycle turbine cycle and providing the unit's allowable 
NOX emission rate for such control period.
    (ii) By June 15 immediately after the promulgation of such notice, 
the Administrator will calculate, for each such State and each owner of 
one or more TR NOX Ozone Season units in the State and for 
the control period in the year involved, each owner's share of the 
total NOX emissions from all TR NOX Ozone Season 
units in the State, each owner's assurance level, and the amount (if 
any) of TR NOX Ozone Season allowances that each owner must 
hold in accordance with the calculation formula in Sec.  
97.506(c)(2)(i) and will promulgate a notice of 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)(3)(ii) of this section.
    (A) Objections shall be submitted by the deadline specified in such 
notice and shall be limited to addressing whether the calculations for 
each owner for the control period in the year involved are consistent 
with the NOX emissions for the relevant TR NOX 
Ozone Season units as set forth in the notice required in paragraph 
(b)(2)(ii) of this section, the definitions of ``owner'', ``owner's 
assurance level'', and ``owner's share'' in Sec.  97.502, and the 
calculation formula in Sec.  97.506(c)(2)(i) and shall not raise any 
issues about any data used in the notice of data availability required 
in paragraph (b)(2)(ii) of this section.
    (B) The Administrator will adjust the calculations to the extent 
necessary to ensure that they are consistent with the data and 
provisions referenced in paragraph (b)(3)(iii)(A) of this section.

[[Page 45409]]

By August 15 immediately after the promulgation of such notice, the 
Administrator will promulgate a notice of 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)(3)(iii)(A) of this section.
    (4) By September 1 immediately after the promulgation of each 
notice of data availability required in paragraph (b)(3)(iii)(B) of 
this section:
    (i) Each owner identified, in such notice, as owning one or more TR 
NOX Ozone Season units in a State and as being required to 
hold TR NOX Ozone Season allowances shall designate the 
compliance account of one of the sources at which such unit or units 
are located to hold such required TR NOX Ozone Season 
allowances;
    (ii) The authorized account representative for the compliance 
account designated under paragraph (b)(4)(i) of this section shall 
submit to the Administrator a statement, in a format prescribed by the 
Administrator, making this designation.
    (5)(i) As of midnight of September 15 immediately after the 
promulgation of each notice of data availability required in paragraph 
(b)(3)(iii)(B) of this section, each owner described in paragraph 
(b)(4)(i) of this section shall hold in the compliance account 
designated by the owner in accordance with paragraph (b)(4)(ii) of this 
section the total amount of TR NOX Ozone Season allowances, 
available for deduction under paragraph (a) of this section, equal to 
the amount the owner is required to hold as calculated by the 
Administrator and referenced in such notice.
    (ii) Notwithstanding the allowance-holding deadline specified in 
paragraph (b)(5)(i) of this section, if September 15 is not a business 
day, then such allowance-holding deadline shall be midnight of the 
first business day thereafter.
    (6) After September 15 (or the date described in paragraph 
(b)(5)(ii) of this section) immediately after the promulgation of each 
notice of data availability required in paragraph (b)(3)(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 deduct from each 
compliance account designated in accordance with paragraph (b)(4)(ii) 
of this section, TR NOX Ozone Season allowances available 
under paragraph (a) of this section, as follows:
    (i) Until the amount of TR NOX Ozone Season allowances 
deducted equals the amount that the owner designating the compliance 
account is required to hold as calculated by the Administrator and 
referenced in the notice required in paragraph (b)(3)(iii)(B) of this 
section; or
    (ii) If there are insufficient TR NOX Ozone Season 
allowances to complete the deductions in paragraph (b)(6)(i) of this 
section, until no more TR NOX Ozone Season allowances 
available under paragraph (a) of this section remain in the compliance 
account.
    (7) Notwithstanding any other provision of this subpart and any 
revision, made by or submitted to the Administrator after the 
promulgation of the notices of data availability required in paragraphs 
(b)(2)(ii) and (b)(3)(iii)(B) of this section respectively for a 
control period, of any data used in making the calculations referenced 
in such notice, the amount of TR NOX Ozone Season allowances 
that each owner is required to hold in accordance with Sec.  
97.506(c)(2)(i) for the control period in the year involved shall 
continue to be such amount as calculated by the Administrator and 
referenced in such notice required in paragraph (b)(3)(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 are required to hold 
in accordance with the calculation formula in Sec.  97.506(c)(2)(i) for 
the control period in the year involved with regard to the State 
involved, provided that--
    (A) With regard to such litigation involving such notice required 
in paragraph (b)(2)(ii) of this section, 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)(ii) of this 
section; and
    (B) With regard to such litigation involving such notice required 
in paragraph (b)(3)(iii) of this section, 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)(3)(iii) of this 
section.
    (ii) If any such data are revised by the owners and operators of a 
source whose designated representative submitted such data under 
paragraph (b)(3)(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 are 
required to hold in accordance with the calculation formula in Sec.  
97.506(c)(2)(i) for the control period in the year involved with regard 
to the State involved, provided that such litigation was initiated no 
later than 30 days after promulgation of such notice required in 
paragraph (b)(3)(iii)(B) of this section.
    (iii) If the revised data are used to recalculate, in accordance 
with paragraphs (b)(7)(i) and (b)(7)(ii) of this section, the amount of 
TR NOX Ozone Season allowances that an owner is required to 
hold for the control period in the year involved with regard to the 
State involved-
    (A) Where the amount of TR NOX Ozone Season allowances 
that an owner is 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 owner shall hold the additional amount 
of TR NOX Ozone Season allowances in the compliance account 
designated by the owner in accordance with paragraph (b)(4)(ii) of this 
section. The owner's failure to hold such additional amount, as 
required, before the new deadline shall not be a violation of the Clean 
Air Act. The owner's 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 owner fails 
to hold as required as of the new deadline, and each day in the control 
period in the year involved, shall be a separate violation of the Clean 
Air Act. After such deadline, the Administrator will make the 
appropriate deductions from the compliance account.
    (B) For an owner 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 the 
compliance account that the owner designated in accordance with 
paragraph (b)(4)(ii) of this section, an amount of TR NOX 
Ozone Season allowances equal to the amount of the decrease to the 
extent such amount was previously deducted from the compliance account 
under paragraph (b)(6) of this section (and has not already been 
restored to the compliance

[[Page 45410]]

account) for the control period in the year involved.
    (C) Each TR NOX Ozone Season allowance held and deducted 
under paragraph (b)(7)(iii)(A) of this section, or recorded under 
paragraph (b)(7)(iii)(B) of this section, as a result of recalculation 
of requirements for compliance with the TR NOX Ozone Season 
assurance provisions for a control period in a given year must be a TR 
NOX Ozone Season allowance allocated for a control period in 
the same or a prior year.
    (c)(1) Identification of TR NOX Ozone Season allowances by serial 
number. The authorized account representative for each source's 
compliance account designated in accordance with paragraph (b)(4)(ii) 
of this section may request that specific TR NOX Ozone 
Season allowances, identified by serial number, in the compliance 
account be deducted in accordance with paragraph (b)(6) or (7) of this 
section. In order to be complete, such request shall be submitted to 
the Administrator by the allowance-holding deadline described in 
paragraph (b)(5) of this section and include, in a format prescribed by 
the Administrator, the identification of the compliance account and the 
appropriate serial numbers.
    (2) First-in, first-out. The Administrator will deduct TR 
NOX Ozone Season allowances under paragraphs (b)(6) and (7) 
of this section from each source's compliance account designated under 
paragraph (b)(4)(ii) of this section 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 (FIFO) 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) Recordation of deductions. The Administrator will record in the 
appropriate compliance account all deductions from such an account 
under paragraph (b) of this section.


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, 97.527, 97.528, 97.542, or 97.543.


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 source's compliance 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.
    (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. The owner or operator 
shall record, report, and quality-assure the data from the monitoring 
systems under paragraph (a)(1) of this section on and after the 
following dates.
    (1) For the owner or operator of a TR NOX Ozone Season 
unit that commences commercial operation before July 1, 2011, by 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 dates:
    (i) 180 calendar days, whichever occurs first, 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 later of the following dates:
    (i) 180 calendar days, whichever occurs first, after the date on 
which the unit commences commercial operation; or
    (ii) If the compliance date under paragraph (b)(3)(i) of this 
section is not during a control period, May 1 immediately after the 
compliance date under paragraph (b)(3)(i) of this section.
    (4) For the owner or operator of a TR NOX Ozone Season 
unit for which

[[Page 45411]]

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 and that reports 
on an annual basis under Sec.  97.534(d), by 90 unit operating days or 
180 calendar days, whichever occurs first, after the date on which 
emissions first exit to the atmosphere through the new stack or flue or 
add-on NOX emissions controls.
    (5) For the owner or operator of a 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) or (3) of this section and 
that reports on a control period basis under Sec.  97.534(d)(2)(ii), by 
the later of the following dates:
    (i) 90 unit operating days or 180 calendar days, whichever occurs 
first, after the date on which emissions first exit to the atmosphere 
through the new stack or flue or add-on NOX emissions 
controls; or
    (ii) If the compliance date under paragraph (b)(5)(i) of this 
section is not during a control period, May 1 immediately after the 
compliance date under paragraph (b)(5)(i) of this section.
    (6) Notwithstanding the dates in paragraphs (b)(1), (2), and (3) of 
this section, for the owner or operator of a unit for which a TR opt-in 
application is submitted and not withdrawn and is not yet approved or 
disapproved, by the date specified in Sec.  97.541(c).
    (7) Notwithstanding the dates in paragraphs (b)(1), (2), and (3) of 
this section, for the owner or operator of a TR NOX Ozone 
Season opt-in unit, by the date on which the TR NOX Annual 
opt-in unit enters the TR NOX Ozone Season Trading Program 
as provided in Sec.  97.541(h).
    (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 emissions to the atmosphere without accounting for all 
such emissions in accordance with the applicable provisions of this 
subpart and part 75 of this chapter.
    (3) No owner or operator of a 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 emissions 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) 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.
    (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.

[[Page 45412]]

    (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 systems, 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. The 120-day 
review period specified in paragraph (d)(3) of this section shall not 
begin before receipt of a complete certification application.
    (C) Disapproval notice. If the certification application shows that 
any monitoring system does not meet the performance requirements of 
part 75 of this chapter or if the certification application is 
incomplete and the requirement for disapproval under paragraph 
(d)(3)(iv)(B) of this section is met, then the 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 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

[[Page 45413]]

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 
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 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;
    (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;
    (B) 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 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) Notwithstanding paragraphs (d)(1) and (2) of this section, for 
a unit for which a TR opt-in application is submitted and not withdrawn 
and is not yet approved or disapproved, the calendar quarter 
corresponding to the date specified in Sec.  97.541(c); and
    (4) Notwithstanding paragraphs (d)(1) and (2) of this section, for 
a TR NOX

[[Page 45414]]

Ozone Season opt-in unit, the calendar quarter corresponding to the 
date on which the TR NOX Annual opt-in unit enters the TR 
NOX Ozone Season Trading Program as provided in Sec.  
97.541(h).
    (5) 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.
    (6) 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 1 
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.
    (7) 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.
    (8) 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)(5) 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 or paragraph (5)(i) or 
(ii) of the definition of ``owner's share'' in Sec.  97.502.
    (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.


Sec.  97.540  General requirements for TR NOX Ozone Season opt-in 
units.

    (a) A TR NOX Ozone Season opt-in unit must be a unit 
that:
    (1) Is located in a State;
    (2) Is not a TR NOX Ozone Season unit under Sec.  
97.504;
    (3) Is not covered by a retired unit exemption under Sec.  72.8 of 
this chapter that is in effect; and
    (4) Vents all of its emissions to a stack and can meet the 
monitoring, recordkeeping, and reporting requirements of this subpart.
    (b) A TR NOX Ozone Season opt-in unit shall be deemed to 
be a TR NOX Ozone Season unit for purposes of applying this 
subpart, except for Sec. Sec.  97.505, 97.511, and 97.512.
    (c) Solely for purposes of applying the requirements of Sec. Sec.  
97.513 through 97.518 and Sec. Sec.  97.530 through 97.535, a unit for 
which a TR opt-in application is submitted and not withdrawn and is not 
yet approved or disapproved under Sec.  97.542 shall be deemed to be a 
TR NOX Ozone Season unit.
    (d) Any TR NOX Ozone Season opt-in unit, and any unit 
for which a TR opt-in application is submitted and not withdrawn and is 
not yet approved or disapproved under Sec.  97.542, located at the same 
source as one or more TR NOX Ozone Season units shall have 
the same designated representative and alternate designated 
representative as such TR NOX Ozone Season units.


Sec.  97.541  Opt-in process.

    A unit meeting the requirements for a TR NOX Ozone 
Season opt-in unit in Sec.  97.540(a) may become a TR NOX 
Ozone Season opt-in unit only if, in accordance with this section, the 
designated representative of the unit submits a complete TR opt-in 
application for the unit and the Administrator approves the 
application.
    (a) Applying to opt-in. The designated representative of the unit 
may submit a complete TR opt-in application for the unit at any time, 
except as provided under Sec.  97.542(e). A complete TR opt-in 
application shall include the following elements in a format prescribed 
by the Administrator:
    (1) Identification of the unit and the source where the unit is 
located,

[[Page 45415]]

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, and unit identification number and 
type;
    (2) A certification that the unit:
    (i) Is not a TR NOX Ozone Season unit under Sec.  
97.504;
    (ii) Is not covered by a retired unit exemption under Sec.  72.8 of 
this chapter that is in effect;
    (iii) Vents all of its emissions to a stack; and
    (iv) Has documented heat input (greater than 0 mmBtu) for more than 
876 hours during the 6 months immediately preceding submission of the 
TR opt-in application;
    (3) A monitoring plan in accordance with Sec. Sec.  97.530 through 
97.535;
    (4) A statement that the unit, if approved to become a TR 
NOX Ozone Season unit under paragraph (g) of this section, 
may withdraw from the TR NOX Ozone Season Trading Program 
only in accordance with Sec.  97.542;
    (5) A statement that the unit, if approved to become a TR 
NOX Ozone Season unit under paragraph (g) of this section, 
is subject to, and the owners and operators of the unit must comply 
with, the requirements of Sec.  97.543;
    (6) A complete certificate of representation under Sec.  97.516 
consistent with Sec.  97.540, if no designated representative has been 
previously designated for the source that includes the unit; and
    (7) The signature of the designated representative and the date 
signed.
    (b) Interim review of monitoring plan. The Administrator will 
determine, on an interim basis, the sufficiency of the monitoring plan 
submitted under paragraph (a)(3) of this section. The monitoring plan 
is sufficient, for purposes of interim review, if the plan appears to 
contain information demonstrating that the NOX emission rate 
and heat input of the unit and all other applicable parameters are 
monitored and reported in accordance with Sec. Sec.  97.530 through 
97.535. A determination of sufficiency shall not be construed as 
acceptance or approval of the monitoring plan.
    (c) Monitoring and reporting. (1)(i) If the Administrator 
determines that the monitoring plan is sufficient under paragraph (b) 
of this section, the owner or operator of the unit shall monitor and 
report the NOX emission rate and the heat input of the unit 
and all other applicable parameters, in accordance with Sec. Sec.  
97.530 through 97.535, starting on the date of certification of the 
necessary monitoring systems under Sec. Sec.  97.530 through 97.535 and 
continuing until the TR opt-in application submitted under paragraph 
(a) of this section is disapproved under this section or, if such TR 
opt-in application is approved, the date and time when the unit is 
withdrawn from the TR NOX Ozone Season Trading Program in 
accordance with Sec.  97.542.
    (ii) The monitoring and reporting under paragraph (c)(1)(i) of this 
section shall cover the entire control period immediately before the 
date on which the unit enters the TR NOX Ozone Season 
Trading Program under paragraph (h) of this section, during which 
period monitoring system availability must not be less than 98 percent 
under Sec. Sec.  97.530 through 97.535 and the unit must be in full 
compliance with any applicable State or Federal emissions or emissions-
related requirements.
    (2) To the extent the NOX emissions rate and the heat 
input of the unit are monitored and reported in accordance with 
Sec. Sec.  97.530 through 97.535 for one or more entire control 
periods, in addition to the control period under paragraph (c)(1)(ii) 
of this section, during which control periods monitoring system 
availability is not less than 98 percent under Sec. Sec.  97.530 
through 97.535 and the unit is in full compliance with any applicable 
State or Federal emissions or emissions-related requirements and which 
control periods begin not more than 3 years before the unit enters the 
TR NOX Ozone Season Trading Program under paragraph (h) of 
this section, such information shall be used as provided in paragraphs 
(e) and (f) of this section.
    (d) Statement on compliance. After submitting to the Administrator 
all quarterly reports required for the unit under paragraph (c) of this 
section, the designated representative shall submit, in a format 
prescribed by the Administrator, to the Administrator a statement that, 
for the years covered by such quarterly reports, the unit was in full 
compliance with any applicable State or Federal emissions or emissions-
related requirements.
    (e) Baseline heat input. The unit's baseline heat input shall 
equal:
    (1) If the unit's NOX emissions rate and heat input are 
monitored and reported for only one entire control period, in 
accordance with paragraph (c) of this section, the unit's total heat 
input (in mmBtu) for such control period; or
    (2) If the unit's NOX emission rate and heat input are 
monitored and reported for more than one entire control period, in 
accordance with paragraph (c) of this section, the average of the 
amounts of the unit's total heat input (in mmBtu) for such control 
periods.
    (f) Baseline NOX emission rate. The unit's baseline NOX 
emission rate shall equal:
    (1) If the unit's NOX emission rate and heat input are 
monitored and reported for only one entire control period, in 
accordance with paragraph (c) of this section, the unit's 
NOX emission rate (in lb/mmBtu) for such control period;
    (2) If the unit's NOX emission rate and heat input are 
monitored and reported for more than one entire control period, in 
accordance with paragraph (c) of this section, and the unit does not 
have add-on NOX emission controls during any such control 
periods, the average of the amounts of the unit's NOX 
emission rate (in lb/mmBtu) for such control periods; or
    (3) If the unit's NOX emission rate and heat input are 
monitored and reported for more than one entire control period, in 
accordance with paragraph (c) of this section, and the unit has add-on 
NOX emission controls during any such control periods, the 
average of the amounts of the unit's NOX emission rate (in 
lb/mmBtu) for such control periods during which the unit has add-on 
NOX emission controls.
    (g) Review of TR opt-in application.
    (1) After the designated representative submits the complete TR 
opt-in application, quarterly reports, and statement required in 
paragraphs (a), (c), and (d) of this section and if the Administrator 
determines that the designated representative shows that the unit meets 
the requirements for a TR NOX Ozone Season opt-in unit in 
Sec.  97.540, the element certified in paragraph (a)(2)(iv) of this 
section, and the monitoring and reporting requirements of paragraph (c) 
of this section, the Administrator will issue a written approval of the 
TR opt-in application for the unit. The written approve will state the 
unit's baseline heat input and baseline NOX emission rate. 
The Administrator will thereafter establish a compliance account for 
the source that includes the unit unless the source already has a 
compliance account.
    (2) Notwithstanding paragraphs (a) through (f) of this section, if, 
at any time before the TR opt-in application is approved under 
paragraph (g)(1) of this section, the Administrator determines that the 
unit cannot meet the requirements for a TR NOX Ozone Season 
opt-in unit in Sec.  97.540, the element certified in paragraph 
(a)(2)(iv) of this section, or the monitoring and reporting 
requirements in paragraph (c) of this section, the Administrator will 
issue a written disapproval of the TR opt-in application for the unit.

[[Page 45416]]

    (h) Date of entry into TR NOX Ozone Season Trading 
Program. A unit for which a TR opt-in application is approved under 
paragraph (g)(1) of this section shall become a TR NOX Ozone 
Season opt-in unit, and a TR NOX Ozone Season unit, 
effective as of the later of May 1, 2012 or May 1 of the first control 
period during which such approval is issued.


Sec.  97.542  Withdrawal of TR NOX Ozone Season opt-in unit from TR NOX 
Ozone Season Trading Program.

    A TR NOX Ozone Season opt-in unit may withdraw from the 
TR NOX Ozone Season Trading Program only if, in accordance 
with this section, the designated representative of the unit submits a 
request to withdraw the unit and the Administrator issues a written 
approval of the request.
    (a) Requesting withdrawal. In order to withdraw the TR 
NOX Ozone Season opt-in unit from the TR NOX 
Ozone Season Trading Program, the designated representative of the unit 
shall submit to the Administrator a request to withdraw the unit 
effective as of midnight of September 30 of a specified calendar year, 
which date must be at least 4 years after September 30 of the year of 
the unit's entry into the TR NOX Ozone Season Trading 
Program under Sec.  97.541(h). The request shall be in a format 
prescribed by the Administrator and shall be submitted no later than 90 
days before the requested effective date of withdrawal.
    (b) Conditions for withdrawal. Before a TR NOX Ozone 
Season opt-in unit covered by the request to withdraw may withdraw from 
the TR NOX Ozone Season Trading Program, the following 
conditions must be met:
    (1) For the control period ending on the date on which the 
withdrawal is to be effective, the source that includes the TR 
NOX Ozone Season opt-in unit must meet the requirement to 
hold TR NOX Ozone Season allowances under Sec. Sec.  97.524 
and 97.525 and cannot have any excess emissions.
    (2) After the requirement under paragraph (b)(1) of this section is 
met, the Administrator will deduct from the compliance account of the 
source that includes the TR NOX Ozone Season opt-in unit TR 
NOX Ozone Season allowances equal in amount to and allocated 
for the same or a prior control period as any TR NOX Ozone 
Season allowances allocated to the TR NOX Ozone Season opt-
in unit under Sec.  97.544 for any control period after the date on 
which the withdrawal is to be effective. If there are no other TR 
NOX Ozone Season units at the source, the Administrator will 
close the compliance account, and the owners and operators of the TR 
NOX Ozone Season opt-in unit may submit a TR NOX 
Ozone Season allowance transfer for any remaining TR NOX 
Ozone Season allowances to another Allowance Management System account 
in accordance Sec. Sec.  97.522 and 97.523.
    (c) Approving withdrawal. (1) After the requirements for withdrawal 
under paragraphs (a) and (b) of this section are met (including 
deduction of the full amount of TR NOX Ozone Season 
allowances required), the Administrator will issue a written approval 
of the request to withdraw, which will become effective as of midnight 
on September 30 of the calendar year for which the withdrawal was 
requested. The unit covered by the request shall continue to be a TR 
NOX Ozone Season opt-in unit until the effective date of the 
withdrawal and shall comply with all requirements under the TR 
NOX Ozone Season Trading Program concerning any control 
periods for which the unit is a TR NOX Ozone Season opt-in 
unit, even if such requirements arise or must be complied with after 
the withdrawal takes effect.
    (2) If the requirements for withdrawal under paragraphs (a) and (b) 
of this section are not met, the Administrator will issue a written 
disapproval of the request to withdraw. The unit covered by the request 
shall continue to be a TR NOX Ozone Season opt-in unit.
    (d) Reapplication upon failure to meet conditions of withdrawal. If 
the Administrator disapproves the request to withdraw, the designated 
representative of the unit may submit another request to withdraw in 
accordance with paragraphs (a) and (b) of this section.
    (e) Ability to reapply to the TR NOX Ozone Season Trading Program. 
Once a TR NOX Ozone Season opt-in unit withdraws from the TR 
NOX Ozone Season Trading Program, the designated 
representative may not submit another opt-in application under Sec.  
97.541 for such unit before the date that is 4 years after the date on 
which the withdrawal became effective.


Sec.  97.543  Change in regulatory status.

    (a) Notification. If a TR NOX Ozone Season opt-in unit 
becomes a TR NOX Ozone Season unit under Sec.  97.504, then 
the designated representative of the unit shall notify the 
Administrator in writing of such change in the TR NOX Ozone 
Season opt-in unit's regulatory status, within 30 days of such change.
    (b) Administrator's actions. (1) If a TR NOX Ozone 
Season opt-in unit becomes a TR NOX Ozone Season unit under 
Sec.  97.504, the Administrator will deduct, from the compliance 
account of the source that includes the TR NOX Ozone Season 
opt-in unit that becomes a TR NOX Ozone Season unit under 
Sec.  97.504, TR NOX Ozone Season allowances equal in amount 
to and allocated for the same or a prior control period as:
    (i) Any TR NOX Ozone Season allowances allocated to the 
TR NOX Ozone Season opt-in unit under Sec.  97.544 for any 
control period starting after the date on which the TR NOX 
Ozone Season opt-in unit becomes a TR NOX Ozone Season unit 
under Sec.  97.504; and
    (ii) If the date on which the TR NOX Ozone Season opt-in 
unit becomes a TR NOX Ozone Season unit under Sec.  97.504 
is not September 30, the TR NOX Ozone Season allowances 
allocated to the TR NOX Ozone Season opt-in unit under Sec.  
97.544 for the control period that includes the date on which the TR 
NOX Ozone Season opt-in unit becomes a TR NOX 
Ozone Season unit under Sec.  97.504--
    (A) Multiplied by the ratio of the number of days, in the control 
period, starting with the date on which the TR NOX Ozone 
Season opt-in unit becomes a TR NOX Ozone Season unit under 
Sec.  97.504, divided by the total number of days in the control 
period, and
    (B) Rounded to the nearest allowance.
    (2) The designated representative shall ensure that the compliance 
account of the source that includes the TR NOX Ozone Season 
opt-in unit that becomes a TR NOX Ozone Season unit under 
Sec.  97.504 contains the TR NOX Ozone Season allowances 
necessary for completion of the deduction under paragraph (b)(1) of 
this section.
    (3)(i) For control periods starting after the date on which the TR 
NOX Ozone Season opt-in unit becomes a TR NOX 
Ozone Season unit under Sec.  97.504, the TR NOX Ozone 
Season opt-in unit will be allocated TR NOX Ozone Season 
allowances in accordance with Sec.  97.512.
    (ii) If the date on which the TR NOX Ozone Season opt-in 
unit becomes a TR NOX Ozone Season unit under Sec.  97.504 
is not September 30, the following amount of TR NOX Ozone 
Season allowances will be allocated to the TR NOX Ozone 
Season opt-in unit (as a TR NOX Ozone Season unit) in 
accordance with Sec.  97.512 for the control period that includes the 
date on which the TR NOX Ozone Season opt-in unit becomes a 
TR NOX Ozone Season unit under Sec.  97.504:
    (A) The amount of TR NOX Ozone Season allowances 
otherwise allocated to the TR NOX Ozone Season opt-in unit 
(as a TR NOX Ozone Season unit) in accordance with Sec.  
97.512 for the control period;

[[Page 45417]]

    (B) Multiplied by the ratio of the number of days, in the control 
period, starting with the date on which the TR NOX Ozone 
Season opt-in unit becomes a TR NOX Ozone Season unit under 
Sec.  97.504, divided by the total number of days in the control 
period; and
    (C) Rounded to the nearest allowance.


Sec.  97.544  TR NOX Ozone Season allowance allocations to TR NOX Ozone 
Season opt-in units.

    (a) Timing requirements. (1) When the TR opt-in application is 
approved for a unit under Sec.  97.541(g), the Administrator will issue 
TR NOX Ozone Season allowances and allocate them to the unit 
for the control period in which the unit enters the TR NOX 
Ozone Season Trading Program under Sec.  97.541(h), in accordance with 
paragraph (b) of this section.
    (2) By no later than July 30 of the control period after the 
control period in which a TR NOX Ozone Season opt-in unit 
enters the TR NOX Ozone Season Trading Program under Sec.  
97.541(h) and July 30 of each year thereafter, the Administrator will 
issue TR NOX Ozone Season allowances and allocate them to 
the TR NOX Ozone Season opt-in unit for the control period 
that includes such allocation deadline and in which the unit is a TR 
NOX Ozone Season opt-in unit, in accordance with paragraph 
(b) of this section.
    (b) Calculation of allocation. For each control period for which a 
TR NOX Ozone Season opt-in unit is to be allocated TR 
NOX Ozone Season allowances, the Administrator will issue 
and allocate TR NOX Ozone Season allowances in accordance 
with the following procedures:
    (1) The heat input (in mmBtu) used for calculating the TR 
NOX Ozone Season allowance allocation will be the lesser of:
    (i) The TR NOX Ozone Season opt-in unit's baseline heat 
input determined under Sec.  97.541(g); or
    (ii) The TR NOX Ozone Season opt-in unit's heat input, 
as determined in accordance with Sec. Sec.  97.530 through 97.535, for 
the immediately prior control period, except when the allocation is 
being calculated for the control period in which the TR NOX 
Ozone Season opt-in unit enters the TR NOX Ozone Season 
Trading Program under Sec.  97.541(h).
    (2) The NOX emission rate (in lb/mmBtu) used for 
calculating TR NOX Ozone Season allowance allocations will 
be the lesser of:
    (i) The TR NOX Ozone Season opt-in unit's baseline 
NOX emission rate (in lb/mmBtu) determined under Sec.  
97.541(g) and multiplied by 70 percent; or
    (ii) The most stringent State or Federal NOX emissions 
limitation applicable to the TR NOX Ozone Season opt-in unit 
at any time during the control period for which TR NOX Ozone 
Season allowances are to be allocated.
    (3) The Administrator will issue TR NOX Ozone Season 
allowances and allocate them to the TR NOX Ozone Season opt-
in unit in an amount equaling the heat input under paragraph (b)(1) of 
this section, multiplied by the NOX emission rate under 
paragraph (b)(2) of this section, divided by 2,000 lb/ton, and rounded 
to the nearest allowance.
    (c) Recordation. (1) The Administrator will record, in the 
compliance account of the source that includes the TR NOX 
Ozone Season opt-in unit, the TR NOX Ozone Season allowances 
allocated to the TR NOX Ozone Season opt-in unit under 
paragraph (a)(1) of this section.
    (2) By September 1 of the control period after the control period 
in which a TR NOX Ozone Season opt-in unit enters the TR 
NOX Ozone Season Trading Program under Sec.  97.541(h) and 
September 1 of each year thereafter, the Administrator will record, in 
the compliance account of the source that includes the TR 
NOX Ozone Season opt-in unit, the TR NOX Ozone 
Season allowances allocated to the TR NOX Ozone Season opt-
in unit under paragraph (a)(2) of this section.
    37. 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, and variability limits.
97.611 Timing requirements for TR SO2 Group 1 allowance 
allocations.
97.612 TR SO2 Group 1 allowance allocations for 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 Allowance Management System 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.
97.633 Notifications concerning monitoring.
97.634 Recordkeeping and reporting.
97.635 Petitions for alternatives to monitoring, recordkeeping, or 
reporting requirements.
97.640 General requirements for TR SO2 Group 1 opt-in 
units.
97.641 Opt-in process.
97.642 Withdrawal of TR SO2 Group 1 opt-in unit from TR 
SO2 Group 1 Trading Program.
97.643 Change in regulatory status.
97.644 TR SO2 Group 1 allowance allocations to TR 
SO2 Group 1 opt-in units.

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.  52.38(b) of this chapter, as a means of mitigating 
interstate transport of fine particulates and nitrogen oxides.


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) of the United

[[Page 45418]]

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 of the 
amount of such TR SO2 Group 1 allowances to be initially 
credited to a TR SO2 Group 1 source or a new unit set-aside.
    Allowable SO2 emission rate means, with regard to a unit, the 
SO2 emission rate limit 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, held, deducted, or 
transferred only as whole allowances. The Allowance Management System 
is a component of the CAMD Business System, which is the system used by 
the Administrator to handle TR SO2 Group 1 allowances and 
data related to SO2 emissions.
    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, 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 Annual emissions limitation for such control period in 
accordance with Sec.  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 Season 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 Sec.  72.2 of this chapter, Sec.  97.402, or Sec.  97.502 
respectively.
    Authorized account representative means, with regard to 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, with regard to 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.
    Certifying official means a natural person who is:
    (1) For a corporation, a president, secretary, treasurer, or vice-
president or 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 any solid fuel classified as anthracite, bituminous, 
subbituminous, or lignite.
    Coal-derived fuel means any fuel (whether in a solid, liquid, or 
gaseous state) produced by the mechanical, thermal, or chemical 
processing of coal.
    Coal-fired means combusting any amount of coal or coal-derived 
fuel, alone or in combination with any amount of any other fuel, during 
1990 or any year thereafter.
    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--
    (1) Operating as part of a cogeneration system; and
    (2) Producing during the later of 1990 or the 12-month period 
starting on the date that the unit first produces electricity and 
during each calendar year after the later of 1990 or the calendar year 
in which the unit first produces electricity--
    (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 then 42.5 percent of total energy input, 
if useful thermal energy produced is 15 percent or more of total energy 
output, or not less than 45 percent of total energy input, if useful 
thermal energy produced is less than 15 percent of total energy output.
    (ii) For a bottoming-cycle unit, useful power not less than 45 
percent of total energy input;
    (3) 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
    (4) Provided that, if a topping-cycle unit is operated as part of a 
cogeneration system during a calendar year and the cogeneration system 
meets on a system-wide basis the requirement in paragraph

[[Page 45419]]

(2)(i)(B) of this definition, the topping-cycle unit shall be deemed to 
meet such requirement during that 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 November 15, 1990 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 (other than replacement of the unit by a unit at the same 
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 November 15, 1990 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 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 November 15, 1990 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 (other than 
replacement of the unit by a unit at the same 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 
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.
    Commence operation means, with regard to a unit:
    (1) To have begun any mechanical, chemical, or electronic process, 
including start-up of the unit's combustion chamber.
    (2) For a unit that undergoes a physical change (other than 
replacement of the unit by a unit at the same source) after the date 
the unit commences operation as defined in paragraph (1) of this 
definition, such date shall remain the date of commencement of 
operation of the unit, which shall continue to be treated as the same 
unit.
    (3) For a unit that is replaced by a unit at the same source after 
the date the unit commences operation as defined in paragraph (1) of 
this definition, such date shall remain the replaced unit's date of 
commencement of operation, and the replacement unit shall be treated as 
a separate unit with a separate date for commencement of operation as 
defined in paragraph (1), (2), or (3) of this definition as 
appropriate.
    Common stack means a single flue through which emissions from 2 or 
more units are exhausted.
    Compliance account means 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 for 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 complying with the source's 
TR SO2 Group 1 emissions limitation in accordance with Sec.  
97.624 and the TR SO2 Group 1 assurance provisions in 
accordance with Sec.  97.625.
    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 
Sec.  72.2 of this chapter, Sec.  97.402, or Sec.  97.502 respectively.

[[Page 45420]]

    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 in accordance with this subpart.
    Excess emissions means any ton of SO2 emitted from the 
TR SO2 Group 1 units at a TR SO2 Group 1 source 
during a control period that exceeds the TR SO2 Group 1 
emissions limitation for the source.
    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 Sec. Sec.  97.604(b)(2)(i)(B), 
97.604(b)(2)(ii)(B), and 97.604(b)(2)(iii), 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 1990 or any calendar year thereafter.
    Fuel oil means any petroleum-based fuel (including diesel fuel or 
petroleum derivatives such as oil tar) and any recycled or blended 
petroleum products or petroleum by-products used as a fuel whether in a 
liquid, solid, or gaseous state.
    General account means an Allowance Management System account, 
established under this subpart, that is not a compliance account.
    Generator means a device that produces electricity.
    Gross electrical output means, with regard to 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, with regard to a unit for a specified period of 
time, the product (in mmBtu/time) of the gross calorific value of the 
fuel (in mmBtu/lb) multiplied by the fuel feed rate into a combustion 
device (in lb of fuel/time), as measured, recorded, and reported to the 
Administrator by the 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 the amount of heat input (in mmBtu) divided 
by unit operating time (in hr) or, with regard to a specific fuel, the 
amount of heat input attributed to the fuel (in mmBtu) divided by the 
unit operating time (in hr) during which the unit combusts the fuel.
    Life-of-the-unit, firm power contractual arrangement means a unit 
participation power sales agreement under which a utility or industrial 
customer reserves, or is entitled to receive, a specified amount or 
percentage of nameplate capacity and associated energy generated by any 
specified unit and pays its proportional amount of such unit's total 
costs, pursuant to a contract:
    (1) For the life of the unit;
    (2) For a cumulative term of no less than 30 years, including 
contracts that permit an election for early termination; or
    (3) For a period no less than 25 years or 70 percent of the 
economic useful life of the unit determined as of the time the unit is 
built, with option rights to purchase or release some portion of the 
nameplate capacity and associated energy generated by the unit at the 
end of the period.
    Maximum design heat input means the maximum amount of fuel per hour 
(in Btu/hr) that a 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) 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 (in MWe) that the generator is 
capable of producing on a steady state basis and during continuous 
operation (when not restricted by seasonal or other deratings), such 
increased maximum amount as of such completion as specified by the 
person conducting the physical change.
    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 any person who operates, controls, or supervises a 
TR SO2 Group 1 unit or a TR SO2 Group 1 source 
and shall include, but not be limited to, any holding company, utility 
system, or plant manager of such a unit or source.
    Owner means, with regard to 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;
    (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;
    (4) Provided that, for purposes of applying the TR SO2 
Group 1 assurance provisions in Sec. Sec.  97.606(c)(2) and 97.625, if 
one or more owners (as defined in paragraphs (1) through (3) of this 
definition) of one or more TR SO2 Group 1 units in a State 
are wholly owned by another, common owner, all such owners shall be 
treated collectively as a single owner in the State.
    Owner's assurance level means:
    (1) With regard to a State and control period for which the State 
assurance level is exceeded as described in Sec.  97.606(c)(2)(iii)(A) 
and not as described in Sec.  97.606(c)(2)(iii)(B), the owner's share 
of the State SO2 Group 1 trading budget with the one-year 
variability limit for the State for such control period; or
    (2) With regard to a State and control period for which the State 
assurance level is exceeded as described in Sec.  97.606(c)(2)(iii)(B), 
the owner's share of the State SO2 Group 1 trading budget 
with the three-year variability limit for the State for such control 
period.
    Owner's share means:
    (1) With regard to a total amount of SO2 emissions from 
all TR SO2 Group 1 units in a State during a control period, 
the total tonnage of SO2 emissions during such control 
period from all of the owner's TR SO2 Group 1 units in the 
State;
    (2) With regard to a State SO2 Group 1 trading budget 
with a one-year variability limit for a control period, the

[[Page 45421]]

amount (rounded to the nearest allowance) equal to the total amount of 
TR SO2 Group 1 allowances allocated for such control period 
to all of the owner's TR SO2 Group 1 units in the State, 
multiplied by the sum of the State SO2 Group 1 trading 
budget under Sec.  97.610(a) and the State's one-year variability limit 
under Sec.  97.610(b) and divided by such State SO2 Group 1 
trading budget;
    (3) With regard to a State SO2 Group 1 trading budget 
with a three-year variability limit for a control period, the amount 
(rounded to the nearest allowance) equal to the total amount of TR 
SO2 Group 1 allowances allocated for such control period to 
all of the owner's TR SO2 Group 1 units in the State, 
multiplied by the sum of the State SO2 Group 1 trading 
budget under Sec.  97.610(a) and the State's three-year variability 
limit under Sec.  97.610(b) and divided by such State SO2 
Group 1 trading budget;
    (4) Provided that, in the case of a unit with more than one owner, 
the amount of tonnage of SO2 emissions and of TR 
SO2 Group 1 allowances allocated for a control period, with 
regard to such unit, used in determining each owner's share shall be 
the amount (rounded to the nearest ton and the nearest allowance) equal 
to the unit's SO2 emissions and allocation of such 
allowances, respectively, for such control period multiplied by the 
percentage of ownership in the unit that the owner's legal, equitable, 
leasehold, or contractual reservation or entitlement in the unit 
comprises as of December 31 of such control period;
    (5) Provided that, where two or more units emit through a common 
stack that is the monitoring location from which SO2 mass 
emissions are reported for a control period for a year, the amount of 
tonnage of each unit's SO2 emissions used in determining 
each owner's share for such control period shall be:
    (i) The amount (rounded to the nearest ton) of SO2 
emissions reported at the common stack multiplied by the quotient of 
such unit's heat input for such control period divided by the total 
heat input reported from the common stack for such control period;
    (ii) An amount determined in accordance with a methodology that the 
Administrator determines is consistent with the purposes of this 
definition and whose adverse effect (if any) the Administrator 
determines will be de minimis; or
    (iii) An amount approved by the Administrator in response to a 
petition for an alternative requirement submitted in accordance with 
Sec.  97.635; and
    (6) Provided that, in the case of a unit that operates during, but 
is allocated no TR SO2 Group 1 allowances for, a 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 lesser of--
    (i) The unit's allowable SO2 emission rate (in lb per 
MWe) applicable to such control period, multiplied by a capacity factor 
of 0.84 (if the unit is a coal-fired boiler), 0.15 (if the unit is a 
simple combustion turbine), or 0.66 (if the unit is a combined cycle 
turbine), 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; or
    (ii) For a unit listed in appendix A to this subpart, the sum of 
the unit's SO2 emissions in the control period in the last 
three years during which the unit operated during the control period, 
divided by three.
    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 33 percent of a unit's 
maximum design heat input, divided by 3,413 Btu/kWh, divided by 1,000 
kWh/MWh, and multiplied by 8,760 hr/yr.
    Receive or receipt of means, when referring to the 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, 
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) For a topping-cycle unit, the use of reject heat from 
electricity production in a useful thermal energy application or 
process; or
    (2) For a bottoming-cycle unit, 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 or the District of Columbia that is 
subject to the TR SO2 Group 1 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 total energy of all forms supplied to a 
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,

[[Page 45422]]

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 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 by the 
Administrator in accordance with subpart AAAAA and 52.37(a) 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 by the Administrator in accordance with subpart BBBBB of 
this part and 52.37(b) 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 by the Administrator under this subpart to emit one ton of 
SO2 during a control period of the specified calendar year 
for which the authorization is allocated 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 assurance provisions.
    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 by the 
Administrator in accordance with this subpart and 52.38(b) 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.
    Unit operating day means a calendar day in which a unit combusts 
any fuel.
    Unit operating hour or hour of unit operation means an hour in 
which a unit combusts any fuel.
    Useful power means electricity or mechanical energy that a 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 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 stationary, 
fossil-fuel-fired combustion turbine serving at any time, since the 
later of November 15, 1990 or the start-up of the unit's combustion 
chamber, 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 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), (b)(2)(i), or (b)(2)(ii) 
of this section shall not be a TR SO2 Group 1 unit:
    (1)(i) Any unit:
    (A) Qualifying as a cogeneration unit during the later of 1990 or 
the 12-month period starting on the date the unit first produces 
electricity and continuing to qualify as a cogeneration unit; and
    (B) Not serving at any time, since the later of November 15, 1990 
or the start-up of the unit's combustion chamber, a generator with 
nameplate capacity of more than 25 MWe supplying in any calendar year 
more than one-third of the unit's potential electric output capacity or 
219,000 MWh, whichever is greater, to any utility power distribution 
system for sale.
    (ii) If a unit qualifies as a cogeneration unit during the later of 
1990 or the 12-month period starting on the date the unit first 
produces electricity and meets the requirements of paragraphs (b)(1)(i) 
of this section for at least one calendar year, but subsequently no 
longer meets such qualification and requirements, 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.

[[Page 45423]]

    (2)(i) Any unit commencing operation before January 1, 1985:
    (A) Qualifying as a solid waste incineration unit during the later 
of 1990 or the 12-month period starting on the date the unit first 
produces electricity and continuing to qualify as a solid waste 
incineration unit; and
    (B) With an average annual fuel consumption of fossil fuel for 
1985-1987 less than 20 percent (on a Btu basis) and an average annual 
fuel consumption of fossil fuel for any 3 consecutive calendar years 
after 1990 less than 20 percent (on a Btu basis).
    (ii) Any unit commencing operation on or after January 1, 1985:
    (A) Qualifying as a solid waste incineration unit during the later 
of 1990 or the 12-month period starting on the date the unit first 
produces electricity and continuing to qualify as a solid waste 
incineration unit; and
    (B) With an average annual fuel consumption of fossil fuel for the 
first 3 calendar years of operation less than 20 percent (on a Btu 
basis) and an average annual fuel consumption of fossil fuel for any 3 
consecutive calendar years after 1990 less than 20 percent (on a Btu 
basis).
    (iii) If a unit qualifies as a solid waste incineration unit during 
the later of 1990 or the 12-month period starting on the date the unit 
first produces electricity and meets the requirements of paragraph 
(b)(2)(i) or (ii) of this section for at least 3 consecutive calendar 
years, but subsequently no longer meets such qualification and 
requirements, 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 1990 for which the unit has an average annual fuel 
consumption of fossil fuel of 20 percent or more.
    (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, 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 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 and is not a TR SO2 Group 1 opt-in unit 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.


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

[[Page 45424]]

a control period, 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 a TR SO2 Group 1 source emits SO2 
during any control period 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 pay any fine, penalty, or assessment or comply with any 
other remedy imposed, for the same violations, under the Clean Air Act; 
and
    (B) 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 the total amount of 
SO2 emissions from all TR SO2 Group 1 units in a 
State during a control period in 2014 or any year thereafter exceeds 
the State assurance level as described in paragraph (c)(2)(iii) of this 
section, then each owner whose share of such SO2 emissions 
during such control period exceeds the owner's assurance level for the 
State and such control period shall hold, in a compliance account 
designated by the owner in accordance with Sec.  97.625(b)(4)(ii), TR 
SO2 Group 1 allowances available for deduction for such 
control period under Sec.  97.625(a) in an amount equal to the product, 
as determined by the Administrator in accordance with Sec.  97.625(b), 
of multiplying--
    (A) The quotient (rounded to the nearest whole number) of the 
amount by which the owner's share of such SO2 emissions 
exceeds the owner's assurance level divided by the sum of the amounts, 
determined for all such owners, by which each owner's share of such 
SO2 emissions exceeds that owner's assurance level; and
    (B) The amount by which total SO2 emissions for all TR 
SO2 Group 1 units in the State for such control period 
exceed the State assurance level as determined in accordance with 
paragraph (c)(2)(iii) of this section.
    (ii) The owner 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) The total amount of SO2 emissions from all TR 
SO2 Group 1 units in a State during a control period in 2014 
or any year thereafter exceeds the State assurance level:
    (A) If such total amount of SO2 emissions exceeds the 
sum, for such control period, of the State SO2 Group 1 
trading budget and the State's one-year variability limit under Sec.  
97.610(b); or
    (B) If, with regard to a control period in 2016 or any year 
thereafter, the sum, divided by three, of such total amount of 
SO2 emissions and the total amounts of SO2 
emissions from all TR SO2 Group 1 units in the State during 
the control periods in the immediately preceding two years exceeds the 
sum, for such control period, of the State SO2 Group 1 
trading budget and the State's three-year variability limit under Sec.  
97.610(b);
    (C) Provided that the amount by which such total amount of 
SO2 emissions exceeds the State assurance level shall be the 
greater of the amounts of the exceedance calculated under paragraph 
(c)(2)(iii)(A) of this section and under paragraph (c)(2)(iii)(B) of 
this section.
    (iv) It shall not be a violation of this subpart or of the Clean 
Air Act if the total amount of SO2 emissions from all TR 
SO2 Group 1 units in a State during a control period exceeds 
the State assurance level or if an owner's share of total 
SO2 emissions from the TR SO2 Group 1 units in a 
State during a control period exceeds the owner's assurance level.
    (v) To the extent an owner fails to hold TR SO2 Group 1 
allowances for a control period in accordance with paragraphs (c)(2)(i) 
and (ii) of this section,
    (A) The owner 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 owner fails 
to hold for a control period in accordance with paragraphs (c)(2)(i) 
and (ii) 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:
    (i) Under paragraph (c)(1) 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; and
    (ii) Under paragraph (c)(2) of this section for the control period 
starting on the later of January 1, 2014 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 deducted allowances. A TR SO2 Group 1 
allowance shall not be deducted, for compliance with the requirements 
under paragraphs (c)(1) and (2) of this section, for a control period 
in a calendar year before the year for which the TR SO2 
Group 1 allowance was allocated.
    (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 System 
accounts in accordance with this subpart.
    (6) Limited authorization. (i) A TR SO2 Group 1 
allowance is a limited authorization to emit one ton of SO2 
in accordance with the TR SO2 Group 1 Trading Program.
    (ii) Notwithstanding any other provision of this subpart, the 
Administrator has the authority to terminate or limit 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 Sec. Sec.  75.10, 75.11, and 75.16 of this chapter), an 
excepted monitoring system (under appendix D 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

[[Page 45425]]

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 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, including any monitoring plans and monitoring system 
certification and recertification applications.
    (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, including any submissions required for compliance with the TR 
SO2 Group 1 assurance provisions. 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 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, falls on a weekend 
or a State or Federal holiday, 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, 
and variability limits.

    (a) The State SO2 Group 1 trading budgets and 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 trading budget         New-unit set-aside (tons)
                                                          (tons) *             ---------------------------------
                    State                    ----------------------------------
                                                                 For 2014 and    For 2012-2013     For 2014 and
                                               For 2012-2013      thereafter                        thereafter
----------------------------------------------------------------------------------------------------------------
Georgia.....................................          233,260           85,717            6,998            2,572
Illinois....................................          208,957          151,530            6,269            4,546
Indiana.....................................          400,378          201,412           12,011            6,042
Iowa........................................           94,052           86,088            2,822            2,583
Kentucky....................................          219,549          113,844            6,586            3,415
Michigan....................................          251,337          155,675            7,540            4,670
Missouri....................................          203,689          158,764            6,111            4,763
New York....................................           66,542           42,041            1,996            1,261
North Carolina..............................          111,485           81,859            3,345            2,456
Ohio........................................          464,964          178,307           13,949            5,349
Pennsylvania................................          388,612          141,693           11,658            4,251
Tennessee...................................          100,007          100,007            3,000            3,000
Virginia....................................           72,595           40,785            2,178            1,224
West Virginia...............................          205,422          119,016            6,163            3,570
Wisconsin...................................           96,439           66,683            2,893            2,000
                                             -------------------------------------------------------------------
    Total...................................        3,117,288        1,723,421           93,519           51,703
----------------------------------------------------------------------------------------------------------------
* Without variability limits.

    (b) The States' one-year and three-year variability limits for the 
State SO2 Group 1 trading budgets for the control periods in 
2014 and thereafter are as follows:

[[Page 45426]]



------------------------------------------------------------------------
                                      One-year            Three-year
                                 variability limits   variability limits
             State             -----------------------------------------
                                      2014 and             2016 and
                                 thereafter  (tons)   thereafter  (tons)
------------------------------------------------------------------------
Georgia.......................                8,572                4,949
Illinois......................               15,153                8,749
Indiana.......................               20,141               11,629
Iowa..........................                8,609                4,970
Kentucky......................               11,384                6,573
Michigan......................               15,568                8,988
Missouri......................               15,876                9,166
New York......................                4,204                2,427
North Carolina................                8,186                4,726
Ohio..........................               17,831               10,295
Pennsylvania..................               14,169                8,181
Tennessee.....................               10,001                5,774
Virginia......................                4,079                2,355
West Virginia.................               11,902                6,871
Wisconsin.....................                6,668                3,850
------------------------------------------------------------------------

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 
set forth in appendix A to this subpart. Listing a unit in such 
appendix does not constitute a determination that the unit is a TR 
SO2 Group 1 unit, and not listing a unit in such appendix 
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 
listed in appendix A to this subpart as being allocated TR 
SO2 Group 1 allowances does not operate, starting after 
2011, during the control period in three consecutive years, such unit 
will not be allocated the TR SO2 Group 1 allowances set 
forth in appendix A to this subpart for the unit for the control 
periods in the seventh year after the first such year and in each year 
after that seventh year. All TR SO2 Group 1 allowances that 
would otherwise have been allocated to such unit will be allocated to 
the new unit set-aside 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) By July 1, 2012 and July 1 of each year 
thereafter, the Administrator will calculate the TR SO2 
Group 1 allowance allocation for each TR SO2 Group 1 unit, 
in accordance with Sec.  97.612, for the control period in the year of 
the applicable calculation deadline under this paragraph and will 
promulgate a notice of availability of the results of the calculations.
    (2) For each notice of data availability required in paragraph 
(b)(1) of this section, the Administrator will provide an opportunity 
for submission of objections to the calculations referenced in such 
notice.
    (i) Objections shall be submitted by the deadline specified in such 
notice and shall be limited to addressing whether the calculations are 
in accordance with Sec.  97.612 and Sec. Sec.  97.606(b)(2) and 97.630 
through 97.635.
    (ii) 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)(i) of this section. By September 1 
immediately after the promulgation of such notice, the Administrator 
will promulgate a notice of 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)(i) of this section.
    (c) Units that are not TR SO2 Group 1 units. 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 for the control period to a recipient that is not actually 
a TR SO2 Group 1 unit under Sec.  97.604 as of January 1, 
2012 or whose deadline for meeting monitor certification requirements 
under Sec.  97.630(b)(1) and (2) is after January 1, 2012 or if the 
Administrator determines that TR SO2 Group 1 allowances were 
allocated under paragraph (b) of this section and Sec.  97.612 for the 
control period to a recipient that is not actually a TR SO2 
Group 1 unit under Sec.  97.604 as of January 1 of the control period, 
then the Administrator will notify the designated representative and 
will act in accordance with the following procedures:
    (1) Except as provided in paragraph (c)(2) or (3) of this section, 
the Administrator will not record such TR SO2 Group 1 
allowances under Sec.  97.621.
    (2) If the Administrator already recorded such TR SO2 
Group 1 allowances under Sec.  97.621 and if the Administrator makes 
such determination 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.
    (3) If the Administrator already recorded such TR SO2 
Group 1 allowances under Sec.  97.621 and if the Administrator makes 
such determination 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.
    (4) The Administrator will transfer the TR SO2 Group 1 
allowances that are not recorded, or that are deducted, in accordance 
with paragraphs (c)(1) and (2) of this section to the new unit set-
aside, for the State in which such recipient is located, for the 
control period in the year of such transfer if the notice required in 
paragraph (b)(1) of this section for the control period in that year 
has not been promulgated or, if such notice has been promulgated, in 
the next year.

[[Page 45427]]

Sec.  97.612  TR SO2 Group 1 allowance allocations for new units.

    (a) For each control period in 2012 and thereafter, the 
Administrator will allocate, in accordance with the following 
procedures, TR SO2 Group 1 allowances to TR SO2 
Group 1 units in a State that are not listed in appendix A to this 
subpart, to TR SO2 Group 1 units that are so listed and 
whose allocation of SO2 Group 1 allowances for such control 
period is covered by Sec.  97.611(c)(1) or (2), and to TR 
SO2 Group 1 units that are so listed and, pursuant to Sec.  
97.611(a)(2), are not allocated TR SO2 Group 1 allowances 
for such control period but that operate during the immediately 
preceding control period:
    (1) The Administrator will establish a separate new unit set-aside 
for each State for each control period in a given year. Each 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). Each new unit set-aside will 
be allocated additional TR SO2 Group 1 allowances in 
accordance with Sec.  97.611(a)(2) and (c)(4).
    (2) The designated representative of such TR SO2 Group 1 
unit may submit to the Administrator a request, in a format prescribed 
by the Administrator, to be allocated TR SO2 Group 1 
allowances for a control period, starting with the later of the control 
period in 2012, the first control period after the control period in 
which the TR SO2 Group 1 unit commences commercial operation 
(for a unit not listed in appendix A to this subpart), or the first 
control period after the control period in which the unit resumes 
operation (for a unit listed in appendix A of this subpart) and for 
each subsequent control period.
    (i) The request must be submitted on or before May 1 of the first 
control period for which TR SO2 Group 1 allowances are 
sought and after the date on which the TR SO2 Group 1 unit 
commences commercial operation (for a unit not listed in appendix A of 
this subpart) or on which the unit resumes operation (for a unit listed 
in appendix A of this subpart).
    (ii) For each control period for which an allocation is sought, the 
request must be for TR SO2 Group 1 allowances in an amount 
equal to the unit's total tons of SO2 emissions during the 
immediately preceding control period.
    (3) The Administrator will review each TR SO2 Group 1 
allowance allocation request under paragraph (a)(2) of this section and 
will accept the request only if it meets the requirements of paragraph 
(a)(2) of this section. The Administrator will allocate TR 
SO2 Group 1 allowances for each control period pursuant to 
an accepted request as follows:
    (i) After May 1 of such control period, the Administrator will 
determine the sum of the TR SO2 Group 1 allowances requested 
in all accepted allowance allocation requests for such control period.
    (ii) If the amount of TR SO2 Group 1 allowances in the 
new unit set-aside for such control period is greater than or equal to 
the sum under paragraph (a)(3)(i) of this section, then the 
Administrator will allocate the amount of TR SO2 Group 1 
allowances requested to each TR SO2 Group 1 unit covered by 
an accepted allowance allocation request.
    (iii) If the amount of TR SO2 Group 1 allowances in the 
new unit set-aside for such control period is less than the sum under 
paragraph (a)(3)(i) of this section, then the Administrator will 
allocate to each TR SO2 Group 1 unit covered by an accepted 
allowance allocation request the amount of the TR SO2 Group 
1 allowances requested, multiplied by the amount of TR SO2 
Group 1 allowances in the new unit set-aside for such control period, 
divided by the sum determined under paragraph (a)(3)(i) of this 
section, and rounded to the nearest allowance.
    (iv) The Administrator will notify, through the promulgation of the 
notices of data availability described in Sec.  97.611(b), each 
designated representative that submitted an allowance allocation 
request of the amount of TR SO2 Group 1 allowances (if any) 
allocated for such control period to the TR SO2 Group 1 unit 
covered by the request.
    (b) If, after completion of the procedures under paragraph (a)(4) 
of this section for a control period, any unallocated TR SO2 
Group 1 allowances remain in the new unit set-aside under paragraph (a) 
of this section for a State for such control period, the Administrator 
will allocate to each TR SO2 Group 1 unit that is in the 
State, is listed in appendix A to this subpart, 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 amount of tons in such new unit set-aside, and rounded 
to the nearest allowance.


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,

[[Page 45428]]

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'' 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 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.

    (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 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, 
including the addition of a new 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 include the change.


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, and actual or projected date of 
commencement of commercial operation.
    (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 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 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

[[Page 45429]]

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 Sec.  97.615(a) or (b), 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 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 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 Allowance Management System 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) 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 
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 45430]]

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 order or decision 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 order or decision issued to the authorized account 
representative or alternate authorized account representative by the 
Administrator regarding the general account. (ii) Except as provided in 
paragraph (b)(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 (b)(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 (b)(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 of a new 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 authorized account representative. (i) Once a complete 
application for a general account under paragraph (b)(1) of this 
section has been submitted and received, the Administrator will rely on 
the application unless and until a superseding complete application for 
a general account under paragraph (b)(1) of this section is received by 
the Administrator.
    (ii) Except as provided in paragraph (b)(3)(i) or (ii) of this 
section, no objection or other communication submitted to the 
Administrator concerning the authorization, or any

[[Page 45431]]

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 make an electronic 
submission to the Administrator in accordance with paragraph (b)(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 as an ``agent'');
    (C) For each such natural person, a list of the type or types of 
electronic submissions under paragraph (b)(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(b)(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(b)(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(b)(5) is terminated.''.
    (iv) A notice of delegation submitted under paragraph (b)(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 (b)(5)(iii)(D) of this section and made in accordance with a 
notice of delegation effective under paragraph (b)(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)(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 20 business days 
after the notice is sent. The account will be closed after the 20-day 
period unless, before the end of the 20-day period, the Administrator 
receives a correctly submitted 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.
    (c) Account identification. The Administrator will assign a unique 
identifying number to each account established under paragraph (a) or 
(b) of this section.
    (d) Responsibilities of authorized account representative and 
alternate authorized account representative. After the establishment of 
an Allowance Management System 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 (b)(2)(ii) and (b)(5) of 
this section.


Sec.  97.621  Recordation of TR SO2 Group 1 allowance allocations.

    (a) By September 1, 2011, the Administrator will record in each TR 
SO2 Group 1 source's compliance account the TR 
SO2 Group 1 allowances allocated for the TR SO2 
Group 1 units at the source in accordance with Sec. Sec.  97.611(a) for 
the control periods in 2012, 2013, and 2014.
    (b) By June 1, 2012 and June 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 
for the TR SO2 Group 1 units at the source in accordance 
with Sec.  97.611(a) for the control period in the third year after the 
year of the applicable recordation deadline under this paragraph.
    (c) By September 1, 2012 and September 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 for the TR SO2 Group 1 units at the source in 
accordance with Sec.  97.612 for the control period in the year of the 
applicable recordation deadline under this paragraph.
    (d) When recording the allocation of TR SO2 Group 1 
allowances for a TR

[[Page 45432]]

SO2 Group 1 unit in a compliance 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.


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, 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 by 
the request, provided that the transfer is correctly submitted under 
Sec.  97.622.
    (b)(1) A TR SO2 Group 1 allowance transfer 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 any control period before such allowance 
transfer deadline will not be recorded until after the Administrator 
completes the deductions under Sec.  97.624 for the control period 
immediately before such allowance transfer deadline.
    (2) A TR SO2 Group 1 allowance transfer that is 
submitted for recordation after the deadline for holding TR 
SO2 Group 1 allowances described in Sec.  97.625(b)(5) and 
that includes any TR SO2 Group 1 allowances allocated for a 
control period before the year of such deadline will not be recorded 
until after the Administrator completes the deductions under Sec.  
97.625 for the control period immediately before the year of such 
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 the control period in the year or 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, the 
Administrator will deduct from the 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 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 (FIFO) 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 the control period 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 an owner of one or more TR SO2 Group 1 units 
in a State only if the TR SO2 Group 1 allowances:
    (1) Were allocated for the control period in the year or a prior 
year; and
    (2) Are held in a compliance account, designated by the owner in 
accordance

[[Page 45433]]

with paragraph (b)(4)(ii) of this section, of one of the owner's TR 
SO2 Group 1 sources in the State as of the deadline 
established in paragraph (b)(5) 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, 2015 and June 1 of each year thereafter, the 
Administrator will:
    (i) Calculate, separately for each State, the total amount of 
SO2 emissions from all TR SO2 Group 1 units in 
the State during the control period in the year before the year of this 
calculation deadline and the amount, if any, by which such total amount 
of NOX emissions exceeds the State assurance level as 
described in Sec.  97.606(c)(2)(iii); and
    (ii) Promulgate a notice of availability of the results of the 
calculations required in paragraph (b)(1)(i) of this section, including 
separate calculations of the SO2 emissions for each TR 
SO2 Group 1 unit and of the amounts described in Sec. Sec.  
97.606(c)(2)(iii)(A) and (B) for each State.
    (2) The Administrator will provide an opportunity for submission of 
objections to the calculations referenced by each notice described in 
paragraph (b)(1) of this section.
    (i) Objections shall be submitted by the deadline specified in such 
notice and shall be limited to addressing whether the calculations for 
each TR SO2 Group 1 unit and each State for the control 
period in the year involved are in accordance with Sec.  
97.606(c)(2)(iii) and Sec. Sec.  97.606(b) and 97.630 through 97.635.
    (ii) 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)(i) of this section. By August 1 
immediately after the promulgation of such notice, the Administrator 
will promulgate a notice of 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)(i) of this section.
    (3) For each notice of data availability required in paragraph 
(b)(2)(ii) of this section and for any State identified in such notice 
as having TR SO2 Group 1 sources with total SO2 
emissions exceeding the State assurance level for a control period, as 
described in Sec.  97.606(c)(2)(iii):
    (i) By August 15 immediately after the promulgation of such notice, 
the designated representative of each TR SO2 Group 1 source 
in each such State shall submit a statement, in a format prescribed by 
the Administrator:
    (A) Listing all the owners of each TR SO2 Group 1 unit 
at the source, explaining how the selection of each owner for inclusion 
on the list is consistent with the definition of ``owner'' in Sec.  
97.602, and listing, separately for each unit, the percentage of the 
legal, equitable, leasehold, or contractual reservation or entitlement 
for each such owner as of midnight of December 31 of the control period 
in the year involved; and
    (B) For each TR SO2 Group 1 unit at the source that 
operates during, but is allocated no TR SO2 Group 1 
allowances for, the control period in the year involved, identifying 
whether the unit is a coal-fired boiler, simple combustion turbine, or 
combined cycle turbine cycle and providing the unit's allowable 
SO2 emission rate for such control period.
    (ii) By September 15 immediately after the promulgation of such 
notice, the Administrator will calculate, for each such State and each 
owner of one or more TR SO2 Group 1 units in the State and 
for the control period in the year involved, each owner's share of the 
total SO2 emissions from all TR SO2 Group 1 units 
in the State, each owner's assurance level, and the amount (if any) of 
TR SO2 Group 1 allowances that each owner must hold in 
accordance with the calculation formula in Sec.  97.606(c)(2)(i) and 
will promulgate a notice of 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)(3)(ii) of this section.
    (A) Objections shall be submitted by the deadline specified in such 
notice and shall be limited to addressing whether the calculations for 
each owner for the control period in the year involved are consistent 
with the SO2 emissions for the relevant TR SO2 
Group 1 units as set forth in the notice required in paragraph 
(b)(2)(ii) of this section, the definitions of ``owner'', ``owner's 
assurance level'', and ``owner's share'' in Sec.  97.602, and the 
calculation formula in Sec.  97.606(c)(2)(i) and shall not raise any 
issues about any data used in the notice of data availability required 
in paragraph (b)(2)(ii) of this section.
    (B) The Administrator will adjust the calculations to the extent 
necessary to ensure that they are consistent with the data and 
provisions referenced in paragraph (b)(3)(iii)(A) of this section. By 
November 15 immediately after the promulgation of such notice, the 
Administrator will promulgate a notice of 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)(3)(iii)(A) of this section.
    (4) By December 1 immediately after the promulgation of each notice 
of data availability required in paragraph (b)(3)(iii)(B) of this 
section:
    (i) Each owner identified, in such notice, as owning one or more TR 
SO2 Group 1 units in a State and as being required to hold 
TR SO2 Group 1 allowances shall designate the compliance 
account of one of the sources at which such unit or units are located 
to hold such required TR SO2 Group 1 allowances;
    (ii) The authorized account representative for the compliance 
account designated under paragraph (b)(4)(i) of this section shall 
submit to the Administrator a statement, in a format prescribed by the 
Administrator, making this designation.
    (5)(i) As of midnight of December 15 immediately after the 
promulgation of each notice of data availability required in paragraph 
(b)(3)(iii)(B) of this section, each owner described in paragraph 
(b)(4)(i) of this section shall hold in the compliance account 
designated by the owner in accordance with paragraph (b)(4)(ii) of this 
section the total amount of TR SO2 Group 1 allowances, 
available for deduction under paragraph (a) of this section, equal to 
the amount the owner is required to hold as calculated by the 
Administrator and referenced in such notice.
    (ii) Notwithstanding the allowance-holding deadline specified in 
paragraph (b)(5)(i) of this section, if December 15 is not a business 
day, then such allowance-holding deadline shall be midnight of the 
first business day thereafter.
    (6) After December 15 (or the date described in paragraph 
(b)(5)(ii) of this section) immediately after the promulgation of each 
notice of data availability required in paragraph (b)(3)(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 deduct from each 
compliance account designated in accordance with paragraph (b)(4)(ii) 
of this section, TR SO2 Group 1 allowances available under 
paragraph (a) of this section, as follows:
    (i) Until the amount of TR SO2 Group 1 allowances 
deducted equals the

[[Page 45434]]

amount that the owner designating the compliance account is required to 
hold as calculated by the Administrator and referenced in the notice 
required in paragraph (b)(3)(iii)(B) of this section; or
    (ii) If there are insufficient TR SO2 Group 1 allowances 
to complete the deductions in paragraph (b)(6)(i) of this section, 
until no more TR SO2 Group 1 allowances available under 
paragraph (a) of this section remain in the compliance account.
    (7) Notwithstanding any other provision of this subpart and any 
revision, made by or submitted to the Administrator after the 
promulgation of the notices of data availability required in paragraphs 
(b)(2)(ii) and (b)(3)(iii)(B) of this section respectively for a 
control period, of any data used in making the calculations referenced 
in such notice, the amount of TR SO2 Group 1 allowances that 
each owner is required to hold in accordance with Sec.  97.606(c)(2)(i) 
for the control period in the year involved shall continue to be such 
amount as calculated by the Administrator and referenced in such notice 
required in paragraph (b)(3)(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 are required to hold in 
accordance with the calculation formula in Sec.  97.606(c)(2)(i) for 
the control period in the year involved with regard to the State 
involved, provided that--
    (A) With regard to such litigation involving such notice required 
in paragraph (b)(2)(ii) of this section, 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)(ii) of this 
section; and
    (B) With regard to such litigation involving such notice required 
in paragraph (b)(3)(iii) of this section, 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)(3)(iii) of this 
section.
    (ii) If any such data are revised by the owners and operators of a 
source whose designated representative submitted such data under 
paragraph (b)(3)(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 are 
required to hold in accordance with the calculation formula in Sec.  
97.606(c)(2)(i) for the control period in the year involved with regard 
to the State involved, provided that such litigation was initiated no 
later than 30 days after promulgation of such notice required in 
paragraph (b)(3)(iii)(B) of this section.
    (iii) If the revised data are used to recalculate, in accordance 
with paragraphs (b)(7)(i) and (b)(7)(ii) of this section, the amount of 
TR SO2 Group 1 allowances that an owner is required to hold 
for the control period in the year involved with regard to the State 
involved--
    (A) Where the amount of TR SO2 Group 1 allowances that 
an owner is 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 owner shall hold the additional amount of TR 
SO2 Group 1 allowances in the compliance account designated 
by the owner in accordance with paragraph (b)(4)(ii) of this section. 
The owner's failure to hold such additional amount, as required, before 
the new deadline shall not be a violation of the Clean Air Act. The 
owner's 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 owner fails to hold as 
required as of the new deadline, and each day in the control period in 
the year involved, shall be a separate violation of the Clean Air Act. 
After such deadline, the Administrator will make the appropriate 
deductions from the compliance account.
    (B) For an owner 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 the compliance 
account that the owner designated in accordance with paragraph 
(b)(4)(ii) of this section, an amount of TR SO2 Group 1 
allowances equal to the amount of the decrease to the extent such 
amount was previously deducted from the compliance account under 
paragraph (b)(6) of this section (and has not already been restored to 
the compliance account) for the control period in the year involved.
    (C) Each TR SO2 Group 1 allowance held and deducted 
under paragraph (b)(7)(iii)(A) of this section, or recorded under 
paragraph (b)(7)(iii)(B) of this section, as a result of recalculation 
of requirements under the TR SO2 Group 1 assurance 
provisions for a control period in a given year must be a TR 
SO2 Group 1 allowance allocated for a control period in the 
same or a prior year.
    (c)(1) Identification of TR SO2 Group 1 allowances by serial 
number. The authorized account representative for each source's 
compliance account designated in accordance with paragraph (b)(4)(ii) 
of this section may request that specific TR SO2 Group 1 
allowances, identified by serial number, in the compliance account be 
deducted in accordance with paragraph (b)(6) or (7) of this section. In 
order to be complete, such request shall be submitted to the 
Administrator by the allowance-holding deadline described in paragraph 
(b)(5) of this section and include, in a format prescribed by the 
Administrator, the identification of the compliance account and the 
appropriate serial numbers.
    (2) First-in, first-out. The Administrator will deduct TR 
SO2 Group 1 allowances under paragraphs (b)(6) and (7) of 
this section from each source's compliance account designated under 
paragraph (b)(4)(ii) of this section 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 (FIFO) 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) Recordation of deductions. The Administrator will record in the 
appropriate compliance account all deductions from such an account 
under paragraph (b) of this section.


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

[[Page 45435]]

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, 97.627, 97.628, 97.642, or 97.643.


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 
source's compliance 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. The owner or operator 
shall record, report, and quality-assure the data from the monitoring 
systems under paragraph (a)(1) of this section on and after the 
following dates.
    (1) For the owner or operator of a TR SO2 Group 1 unit 
that commences commercial operation before July 1, 2011, by 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 dates:
    (i) January 1, 2012; or
    (ii) 180 calendar days, whichever occurs first, after the date on 
which the unit commences commercial operation.
    (3) For 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, by 90 unit 
operating days or 180 calendar days, whichever occurs first, after the 
date on which emissions first exit to the atmosphere through the new 
stack or flue or add-on SO2 emissions controls.
    (4) Notwithstanding the dates in paragraphs (b)(1) and (2) of this 
section, for the owner or operator of a unit for which a TR opt-in 
application is submitted and not withdrawn and is not yet approved or 
disapproved, by the date specified in Sec.  97.641(c).
    (5) Notwithstanding the dates in paragraphs (b)(1) and (2) of this 
section, for the owner or operator of a TR SO2 Group 1 opt-
in unit, by the date on which the TR SO2 Group 1 opt-in unit 
enters the TR SO2 Group 1 Trading Program as provided in 
Sec.  97.641(h).
    (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 emissions to the atmosphere without accounting for all 
such emissions in accordance with the applicable provisions of this 
subpart and part 75 of this chapter.
    (3) No owner or operator of a 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 emissions 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

[[Page 45436]]

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) 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 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.  97.633.
    (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. The 120-day

[[Page 45437]]

review period specified in paragraph (d)(3) of this section shall not 
begin before receipt of a complete certification application.
    (C) Disapproval notice. If the certification application shows that 
any monitoring system does not meet the performance requirements of 
part 75 of this chapter or if the certification application is 
incomplete and the requirement for disapproval under paragraph 
(d)(3)(iv)(B) of this section is met, then the 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 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 
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 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;
    (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

[[Page 45438]]

commence in the quarter covering January 1, 2012 through March 31, 
2012;
    (iii) Notwithstanding paragraphs (d)(1)(i) and (ii) of this 
section, for a unit for which a TR opt-in application is submitted and 
not withdrawn and is not yet approved or disapproved, the calendar 
quarter corresponding to the date specified in Sec.  97.641(c); and
    (iv) Notwithstanding paragraphs (d)(1)(i) and (ii) of this section, 
for a TR SO2 Group 1 opt-in unit, the calendar quarter 
corresponding to the date on which the TR SO2 Group 1 opt-in 
unit enters the TR SO2 Group 1 Trading Program as provided 
in Sec.  97.641(h).
    (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 or paragraph (5)(i) or 
(ii) of the definition of ``owner's share'' in Sec.  97.602.
    (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.


Sec.  97.640  General requirements for TR SO2 Group 1 opt-in units.

    (a) A TR SO2 Group 1 opt-in unit must be a unit that:
    (1) Is located in a State;
    (2) Is not a TR SO2 Group 1 unit under Sec.  97.604;
    (3) Is not covered by a retired unit exemption under Sec.  72.8 of 
this chapter that is in effect; and
    (4) Vents all of its emissions to a stack and can meet the 
monitoring, recordkeeping, and reporting requirements of this subpart.
    (b) A TR SO2 Group 1 opt-in unit shall be deemed to be a 
TR SO2 Group 1 unit for purposes of applying this subpart, 
except for Sec. Sec.  97.605, 97.611, and 97.612.
    (c) Solely for purposes of applying the requirements of Sec. Sec.  
97.613 through 97.618 and Sec. Sec.  97.630 through 97.635, a unit for 
which a TR opt-in application is submitted and not withdrawn and is not 
yet approved or disapproved under Sec.  97.642 shall be deemed to be a 
TR SO2 Group 1 unit.
    (d) Any TR SO2 Group 1 opt-in unit, and any unit for 
which a TR opt-in application is submitted and not withdrawn and is not 
yet approved or disapproved under Sec.  97.642, located at the same 
source as one or more TR SO2 Group 1 units shall have the 
same designated representative and alternate designated representative 
as such TR SO2 Group 1 units.


Sec.  97.641  Opt-in process.

    A unit meeting the requirements for a TR SO2 Group 1 
opt-in unit in Sec.  97.640(a) may become a TR SO2 Group 1 
opt-in unit only if, in accordance with this section, the designated 
representative of the unit submits a complete TR opt-in application for 
the unit and the Administrator approves the application.
    (a) Applying to opt-in. The designated representative of the unit 
may submit a complete TR opt-in application for the unit at any time, 
except as provided under Sec.  97.642(e). A complete TR opt-in 
application shall include the following elements in a format prescribed 
by the Administrator:
    (1) Identification of the unit and the source where the unit is 
located,

[[Page 45439]]

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, and unit identification number and 
type;
    (2) A certification that the unit:
    (i) Is not a TR SO2 Group 1 unit under Sec.  97.604;
    (ii) Is not covered by a retired unit exemption under Sec.  72.8 of 
this chapter that is in effect;
    (iii) Vents all of its emissions to a stack; and
    (iv) Has documented heat input (greater than 0 mmBtu) for more than 
876 hours during the 6 months immediately preceding submission of the 
TR opt-in application;
    (3) A monitoring plan in accordance with Sec. Sec.  97.630 through 
97.635;
    (4) A statement that the unit, if approved to become a TR 
SO2 Group 1 unit under paragraph (g) of this section, may 
withdraw from the TR SO2 Group 1 Trading Program only in 
accordance with Sec.  97.642;
    (5) A statement that the unit, if approved to become a TR 
SO2 Group 1 unit under paragraph (g) of this section, is 
subject to, and the owners and operators of the unit must comply with, 
the requirements of Sec.  97.643;
    (6) A complete certificate of representation under Sec.  97.616 
consistent with Sec.  97.640, if no designated representative has been 
previously designated for the source that includes the unit; and
    (7) The signature of the designated representative and the date 
signed.
    (b) Interim review of monitoring plan. The Administrator will 
determine, on an interim basis, the sufficiency of the monitoring plan 
submitted under paragraph (a)(3) of this section. The monitoring plan 
is sufficient, for purposes of interim review, if the plan appears to 
contain information demonstrating that the SO2 emission rate 
and heat input of the unit and all other applicable parameters are 
monitored and reported in accordance with Sec. Sec.  97.630 through 
97.635. A determination of sufficiency shall not be construed as 
acceptance or approval of the monitoring plan.
    (c) Monitoring and reporting. (1)(i) If the Administrator 
determines that the monitoring plan is sufficient under paragraph (b) 
of this section, the owner or operator of the unit shall monitor and 
report the SO2 emission rate and the heat input of the unit 
and all other applicable parameters, in accordance with Sec. Sec.  
97.630 through 97.635, starting on the date of certification of the 
necessary monitoring systems under Sec. Sec.  97.630 through 97.635 and 
continuing until the TR opt-in application submitted under paragraph 
(a) of this section is disapproved under this section or, if such TR 
opt-in application is approved, the date and time when the unit is 
withdrawn from the TR SO2 Group 1 Trading Program in 
accordance with Sec.  97.642.
    (ii) The monitoring and reporting under paragraph (c)(1)(i) of this 
section shall cover the entire control period immediately before the 
date on which the unit enters the TR SO2 Group 1 Trading 
Program under paragraph (h) of this section, during which period 
monitoring system availability must not be less than 98 percent under 
Sec. Sec.  97.630 through 97.635 and the unit must be in full 
compliance with any applicable State or Federal emissions or emissions-
related requirements.
    (2) To the extent the SO2 emission rate and the heat 
input of the unit are monitored and reported in accordance with 
Sec. Sec.  97.630 through 97.635 for one or more entire control 
periods, in addition to the control period under paragraph (c)(1)(ii) 
of this section, during which control periods monitoring system 
availability is not less than 98 percent under Sec. Sec.  97.630 
through 97.635 and the unit is in full compliance with any applicable 
State or Federal emissions or emissions-related requirements and which 
control periods begin not more than 3 years before the unit enters the 
TR SO2 Group 1 Trading Program under paragraph (h) of this 
section, such information shall be used as provided in paragraphs (e) 
and (f) of this section.
    (d) Statement on compliance. After submitting to the Administrator 
all quarterly reports required for the unit under paragraph (c) of this 
section, the designated representative shall submit, in a format 
prescribed by the Administrator, to the Administrator a statement that, 
for the years covered by such quarterly reports, the unit was in full 
compliance with any applicable State or Federal emissions or emissions-
related requirements.
    (e) Baseline heat input. The unit's baseline heat input shall 
equal:
    (1) If the unit's SO2 emission rate and heat input are 
monitored and reported for only one entire control period, in 
accordance with paragraph (c) of this section, the unit's total heat 
input (in mmBtu) for such control period; or
    (2) If the unit's SO2 emission rate and heat input are 
monitored and reported for more than one entire control period, in 
accordance with paragraph (c) of this section, the average of the 
amounts of the unit's total heat input (in mmBtu) for such control 
periods.
    (f) Baseline SO2 emission rate. The unit's baseline SO2 
emission rate shall equal:
    (1) If the unit's SO2 emission rate and heat input are 
monitored and reported for only one entire control period, in 
accordance with paragraph (c) of this section, the unit's 
SO2 emission rate (in lb/mmBtu) for such control period;
    (2) If the unit's SO2 emission rate and heat input are 
monitored and reported for more than one entire control period, in 
accordance with paragraph (c) of this section, and the unit does not 
have add-on SO2 emission controls during any such control 
periods, the average of the amounts of the unit's SO2 
emission rate (in lb/mmBtu) for such control periods; or
    (3) If the unit's SO2 emission rate and heat input are 
monitored and reported for more than one entire control period, in 
accordance with paragraph (c) of this section, and the unit has add-on 
SO2 emission controls during any such control periods, the 
average of the amounts of the unit's SO2 emission rate (in 
lb/mmBtu) for such control periods during which the unit has add-on 
SO2 emission controls.
    (g) Review of TR opt-in application.
    (1) After the designated representative submits the complete TR 
opt-in application, quarterly reports, and statement required in 
paragraphs (a), (c), and (d) of this section and if the Administrator 
determines that the designated representative shows that the unit meets 
the requirements for a TR SO2 Group 1 opt-in unit in Sec.  
97.640, the element certified in paragraph (a)(2)(iv) of this section, 
and the monitoring and reporting requirements of paragraph (c) of this 
section, the Administrator will issue a written approval of the TR opt-
in application for the unit. The written approve will state the unit's 
baseline heat input and baseline SO2 emission rate. The 
Administrator will thereafter establish a compliance account for the 
source that includes the unit unless the source already has a 
compliance account.
    (2) Notwithstanding paragraphs (a) through (f) of this section, if, 
at any time before the TR opt-in application is approved under 
paragraph (g)(1) of this section, the Administrator determines that the 
unit cannot meet the requirements for a TR SO2 Group 1 opt-
in unit in Sec.  97.640, the element certified in paragraph (a)(2)(iv) 
of this section, or the monitoring and reporting requirements in 
paragraph (c) of this section, the Administrator will issue a written 
disapproval of the TR opt-in application for the unit.
    (h) Date of entry into TR SO2 Group 1 Trading Program. A unit for 
which a

[[Page 45440]]

TR opt-in application is approved under paragraph (g)(1) of this 
section shall become a TR SO2 Group 1 opt-in unit, and a TR 
SO2 Group 1 unit, effective as of the later of January 1, 
2012, or January 1 of the first control period during which such 
approval is issued.


Sec.  97.642  Withdrawal of TR SO2 Group 1 opt-in unit from TR SO2 
Group 1 Trading Program.

    A TR SO2 Group 1 opt-in unit may withdraw from the TR 
SO2 Group 1 Trading Program only if, in accordance with this 
section, the designated representative of the unit submits a request to 
withdraw the unit and the Administrator issues a written approval of 
the request.
    (a) Requesting withdrawal. In order to withdraw the TR 
SO2 Group 1 opt-in unit from the TR SO2 Group 1 
Trading Program, the designated representative of the unit shall submit 
to the Administrator a request to withdraw the unit effective as of 
midnight of December 31 of a specified calendar year, which date must 
be at least 4 years after December 31 of the year of the unit's entry 
into the TR SO2 Group 1 Trading Program under Sec.  
97.641(h). The request shall be in a format prescribed by the 
Administrator and shall be submitted no later than 90 days before the 
requested effective date of withdrawal.
    (b) Conditions for withdrawal. Before a TR SO2 Group 1 
opt-in unit covered by the request to withdraw may withdraw from the TR 
SO2 Group 1 Trading Program, the following conditions must 
be met:
    (1) For the control period ending on the date on which the 
withdrawal is to be effective, the source that includes the TR 
SO2 Group 1 opt-in unit must meet the requirement to hold TR 
SO2 Group 1 allowances under Sec. Sec.  97.624 and 97.625 
and cannot have any excess emissions.
    (2) After the requirement under paragraph (b)(1) of this section is 
met, the Administrator will deduct from the compliance account of the 
source that includes the TR SO2 Group 1 opt-in unit TR 
SO2 Group 1 allowances equal in amount to and allocated for 
the same or a prior control period as any TR SO2 Group 1 
allowances allocated to the TR SO2 Group 1 opt-in unit under 
Sec.  97.644 for any control period after the date on which the 
withdrawal is to be effective. If there are no other TR SO2 
Group 1 units at the source, the Administrator will close the 
compliance account, and the owners and operators of the TR 
SO2 Group 1 opt-in unit may submit a TR SO2 Group 
1 allowance transfer for any remaining TR SO2 Group 1 
allowances to another Allowance Management System account in accordance 
with Sec. Sec.  97.622 and 97.623.
    (c) Approving withdrawal. (1) After the requirements for withdrawal 
under paragraphs (a) and (b) of this section are met (including 
deduction of the full amount of TR SO2 Group 1 allowances 
required), the Administrator will issue a written approval of the 
request to withdraw, which will become effective as of midnight on 
December 31 of the calendar year for which the withdrawal was 
requested. The unit covered by the request shall continue to be a TR 
SO2 Group 1 opt-in unit until the effective date of the 
withdrawal and shall comply with all requirements under the TR 
SO2 Group 1 Trading Program concerning any control periods 
for which the unit is a TR SO2 Group 1 opt-in unit, even if 
such requirements arise or must be complied with after the withdrawal 
takes effect.
    (2) If the requirements for withdrawal under paragraphs (a) and (b) 
of this section are not met, the Administrator will issue a written 
disapproval of the request to withdraw. The unit covered by the request 
shall continue to be a TR SO2 Group 1 opt-in unit.
    (d) Reapplication upon failure to meet conditions of withdrawal. If 
the Administrator disapproves the request to withdraw, the designated 
representative of the unit may submit another request to withdraw in 
accordance with paragraphs (a) and (b) of this section.
    (e) Ability to reapply to the TR SO2 Group 1 Trading Program. Once 
a TR SO2 Group 1 opt-in unit withdraws from the TR 
SO2 Group 1 Trading Program, the designated representative 
may not submit another opt-in application under Sec.  97.641 for such 
unit before the date that is 4 years after the date on which the 
withdrawal became effective.


Sec.  97.643   Change in regulatory status.

    (a) Notification. If a TR SO2 Group 1 opt-in unit 
becomes a TR SO2 Group 1 unit under Sec.  97.604, then the 
designated representative of the unit shall notify the Administrator in 
writing of such change in the TR SO2 Group 1 opt-in unit's 
regulatory status, within 30 days of such change.
    (b) Administrator's actions. (1) If a TR SO2 Group 1 
opt-in unit becomes a TR SO2 Group 1 unit under Sec.  
97.604, the Administrator will deduct, from the compliance account of 
the source that includes the TR SO2 Group 1 opt-in unit that 
becomes a TR SO2 Group 1 unit under Sec.  97.604, TR 
SO2 Group 1 allowances equal in amount to and allocated for 
the same or a prior control period as:
    (i) Any TR SO2 Group 1 allowances allocated to the TR 
SO2 Group 1 opt-in unit under Sec.  97.644 for any control 
period starting after the date on which the TR SO2 Group 1 
opt-in unit becomes a TR SO2 Group 1 unit under Sec.  
97.604; and
    (ii) If the date on which the TR SO2 Group 1 opt-in unit 
becomes a TR SO2 Group 1 unit under Sec.  97.604 is not 
December 31, the TR SO2 Group 1 allowances allocated to the 
TR SO2 Group 1 opt-in unit under Sec.  97.644 for the 
control period that includes the date on which the TR SO2 
Group 1 opt-in unit becomes a TR SO2 Group 1 unit under 
Sec.  97.604--
    (A) Multiplied by the ratio of the number of days, in the control 
period, starting with the date on which the TR SO2 Group 1 
opt-in unit becomes a TR SO2 Group 1 unit under Sec.  
97.604, divided by the total number of days in the control period, and
    (B) Rounded to the nearest allowance.
    (2) The designated representative shall ensure that the compliance 
account of the source that includes the TR SO2 Group 1 opt-
in unit that becomes a TR SO2 Group 1 unit under Sec.  
97.604 contains the TR SO2 Group 1 allowances necessary for 
completion of the deduction under paragraph (b)(1) of this section.
    (3)(i) For control periods starting after the date on which the TR 
SO2 Group 1 opt-in unit becomes a TR SO2 Group 1 
unit under Sec.  97.604, the TR SO2 Group 1 opt-in unit will 
be allocated TR SO2 Group 1 allowances in accordance with 
Sec.  97.612.
    (ii) If the date on which the TR SO2 Group 1 opt-in unit 
becomes a TR SO2 Group 1 unit under Sec.  97.604 is not 
December 31, the following amount of TR SO2 Group 1 
allowances will be allocated to the TR SO2 Group 1 opt-in 
unit (as a TR SO2 Group 1 unit) in accordance with Sec.  
97.612 for the control period that includes the date on which the TR 
SO2 Group 1 opt-in unit becomes a TR SO2 Group 1 
unit under Sec.  97.604:
    (A) The amount of TR SO2 Group 1 allowances otherwise 
allocated to the TR SO2 Group 1 opt-in unit (as a TR 
SO2 Group 1 unit) in accordance with Sec.  97.612 for the 
control period;
    (B) Multiplied by the ratio of the number of days, in the control 
period, starting with the date on which the TR SO2 Group 1 
opt-in unit becomes a TR SO2 Group 1 unit under Sec.  
97.604, divided by the total number of days in the control period; and
    (C) Rounded to the nearest allowance.

[[Page 45441]]

Sec.  97.644   TR SO2 Group 1 allowance allocations to TR SO2 Group 1 
opt-in units.

    (a) Timing requirements. (1) When the TR opt-in application is 
approved for a unit under Sec.  97.641(g), the Administrator will issue 
TR SO2 Group 1 allowances and allocate them to the unit for 
the control period in which the unit enters the TR SO2 Group 
1 Trading Program under Sec.  97.641(h), in accordance with paragraph 
(b) of this section.
    (2) By no later than October 31 of the control period after the 
control period in which a TR SO2 Group 1 opt-in unit enters 
the TR SO2 Group 1 Trading Program under Sec.  97.641(h) and 
October 31 of each year thereafter, the Administrator will issue TR 
SO2 Group 1 allowances and allocate them to the TR 
SO2 Group 1 opt-in unit for the control period that includes 
such allocation deadline and in which the unit is a TR SO2 
Group 1 opt-in unit, in accordance with paragraph (b) of this section.
    (b) Calculation of allocation. For each control period for which a 
TR SO2 Group 1 opt-in unit is to be allocated TR 
SO2 Group 1 allowances, the Administrator will issue and 
allocate TR SO2 Group 1 allowances in accordance with the 
following procedures:
    (1) The heat input (in mmBtu) used for calculating the TR 
SO2 Group 1 allowance allocation will be the lesser of:
    (i) The TR SO2 Group 1 opt-in unit's baseline heat input 
determined under Sec.  97.641(g); or
    (ii) The TR SO2 Group 1 opt-in unit's heat input, as 
determined in accordance with Sec. Sec.  97.630 through 97.635, for the 
immediately prior control period, except when the allocation is being 
calculated for the control period in which the TR SO2 Group 
1 opt-in unit enters the TR SO2 Group 1 Trading Program 
under Sec.  97.641(h).
    (2) The SO2 emission rate (in lb/mmBtu) used for 
calculating TR SO2 Group 1 allowance allocations will be the 
lesser of:
    (i) The TR SO2 Group 1 opt-in unit's baseline 
SO2 emission rate (in lb/mmBtu) determined under Sec.  
97.641(g) and multiplied by 70 percent; or
    (ii) The most stringent State or Federal SO2 emissions 
limitation applicable to the TR SO2 Group 1 opt-in unit at 
any time during the control period for which TR SO2 Group 1 
allowances are to be allocated.
    (3) The Administrator will issue TR SO2 Group 1 
allowances and allocate them to the TR SO2 Group 1 opt-in 
unit in an amount equaling the heat input under paragraph (b)(1) of 
this section, multiplied by the SO2 emission rate under 
paragraph (b)(2) of this section, divided by 2,000 lb/ton, and rounded 
to the nearest allowance.
    (c) Recordation. (1) The Administrator will record, in the 
compliance account of the source that includes the TR SO2 
Group 1 opt-in unit, the TR SO2 Group 1 allowances allocated 
to the TR SO2 Group 1 opt-in unit under paragraph (a)(1) of 
this section.
    (2) By December 1 of the control period after the control period in 
which a TR SO2 Group 1 opt-in unit enters the TR 
SO2 Group 1 Trading Program under Sec.  97.641(h) and 
December 1 of each year thereafter, the Administrator will record, in 
the compliance account of the source that includes the TR 
SO2 Group 1 opt-in unit, the TR SO2 Group 1 
allowances allocated to the TR SO2 Group 1 opt-in unit under 
paragraph (a)(2) of this section.
    38. 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, and variability limits.
97.711 Timing requirements for TR SO2 Group 2 allowance 
allocations.
97.712 TR SO2 Group 2 allowance allocations for 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 Allowance Management System 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.
97.740 General requirements for TR SO2 Group 2 opt-in 
units.
97.741 Opt-in process.
97.742 Withdrawal of TR SO2 Group 2 opt-in unit from TR 
SO2 Group 2 Trading Program.
97.743 Change in regulatory status.
97.744 TR SO2 Group 2 allowance allocations to TR 
SO2 Group 2 opt-in units.

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.  52.38(b) of this chapter, as a means of mitigating 
interstate transport of fine particulates and nitrogen oxides.


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) 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 of the 
amount of such TR SO2 Group 2 allowances to be initially 
credited to a TR SO2 Group 2 source or a new unit set-aside.
    Allowable SO2 emission rate means, with regard to a unit, the 
SO2 emission rate limit that is applicable to the unit

[[Page 45442]]

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, held, deducted, or 
transferred only as whole allowances. The Allowance Management System 
is a component of the CAMD Business System, which is the system used by 
the Administrator to handle TR SO2 Group 2 allowances and 
data related to SO2 emissions.
    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, 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 Annual emissions limitation for such control period in 
accordance with Sec.  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 Season 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 Sec.  72.2 of this chapter, Sec.  97.402, or Sec.  97.502 
respectively.
    Authorized account representative means, with regard to 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, with regard to 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.
    Certifying official means a natural person who is:
    (1) For a corporation, a president, secretary, treasurer, or vice-
president or 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 any solid fuel classified as anthracite, bituminous, 
subbituminous, or lignite.
    Coal-derived fuel means any fuel (whether in a solid, liquid, or 
gaseous state) produced by the mechanical, thermal, or chemical 
processing of coal.
    Coal-fired means combusting any amount of coal or coal-derived 
fuel, alone or in combination with any amount of any other fuel, during 
1990 or any year thereafter.
    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--
    (1) Operating as part of a cogeneration system; and
    (2) Producing during the later of 1990 or the 12-month period 
starting on the date that the unit first produces electricity and 
during each calendar year after the later of 1990 or the calendar year 
in which the unit first produces electricity--
    (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 then 42.5 percent of total energy input, 
if useful thermal energy produced is 15 percent or more of total energy 
output, or not less than 45 percent of total energy input, if useful 
thermal energy produced is less than 15 percent of total energy output.
    (ii) For a bottoming-cycle unit, useful power not less than 45 
percent of total energy input;
    (3) 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
    (4) Provided that, if a topping-cycle unit is operated as part of a 
cogeneration system during a calendar year and the cogeneration system 
meets on a system-wide basis the requirement in paragraph (2)(i)(B) of 
this definition, the topping-cycle unit shall be deemed to meet such 
requirement during that 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

[[Page 45443]]

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 November 15, 1990 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 (other than replacement of the unit by a unit at the same 
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 November 15, 1990 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 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 November 15, 1990 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 
and that subsequently undergoes a physical change (other than 
replacement of the unit by a unit at the same source), such date shall 
remain the 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 
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.
    Commence operation means, with regard to a unit:
    (1) To have begun any mechanical, chemical, or electronic process, 
including start-up of the unit's combustion chamber.
    (2) For a unit that undergoes a physical change (other than 
replacement of the unit by a unit at the same source) after the date 
the unit commences operation as defined in paragraph (1) of this 
definition, such date shall remain the date of commencement of 
operation of the unit, which shall continue to be treated as the same 
unit.
    (3) For a unit that is replaced by a unit at the same source after 
the date the unit commences operation as defined in paragraph (1) of 
this definition, such date shall remain the replaced unit's date of 
commencement of operation, and the replacement unit shall be treated as 
a separate unit with a separate date for commencement of operation as 
defined in paragraph (1), (2), or (3) of this definition as 
appropriate.
    Common stack means a single flue through which emissions from 2 or 
more units are exhausted.
    Compliance account means 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 for 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 complying with the source's 
TR SO2 Group 2 emissions limitation in accordance with Sec.  
97.724 and the TR SO2 Group 2 assurance provisions in 
accordance with Sec.  97.725.
    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 natural person as the designated representative, as defined in 
Sec.  72.2 of this chapter, Sec.  97.402, or Sec.  97.502 respectively.
    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 in accordance with this subpart.
    Excess emissions means any ton of SO2 emitted from the 
TR SO2 Group 2 units at a TR SO2 Group 2 source 
during a control period that exceeds the TR SO2 Group 2 
emissions limitation for the source.
    Fossil fuel means--

[[Page 45444]]

    (1) Natural gas, petroleum, coal, or any form of solid, liquid, or 
gaseous fuel derived from such material; or
    (2) For purposes of applying Sec. Sec.  97.704(b)(2)(i)(B), 
97.704(b)(2)(ii)(B), and 97.704(b)(2)(iii), 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 1990 or any calendar year thereafter.
    Fuel oil means any petroleum-based fuel (including diesel fuel or 
petroleum derivatives such as oil tar) and any recycled or blended 
petroleum products or petroleum by-products used as a fuel whether in a 
liquid, solid, or gaseous state.
    General account means an Allowance Management System account, 
established under this subpart, that is not a compliance account.
    Generator means a device that produces electricity.
    Gross electrical output means, with regard to 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, with regard to a unit for a specified period of 
time, the product (in mmBtu/time) of the gross calorific value of the 
fuel (in mmBtu/lb) multiplied by the fuel feed rate into a combustion 
device (in lb of fuel/time), as measured, recorded, and reported to the 
Administrator by the 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 the amount of heat input (in mmBtu) divided 
by unit operating time (in hr) or, with regard to a specific fuel, the 
amount of heat input attributed to the fuel (in mmBtu) divided by the 
unit operating time (in hr) during which the unit combusts the fuel.
    Life-of-the-unit, firm power contractual arrangement means a unit 
participation power sales agreement under which a utility or industrial 
customer reserves, or is entitled to receive, a specified amount or 
percentage of nameplate capacity and associated energy generated by any 
specified unit and pays its proportional amount of such unit's total 
costs, pursuant to a contract:
    (1) For the life of the unit;
    (2) For a cumulative term of no less than 30 years, including 
contracts that permit an election for early termination; or
    (3) For a period no less than 25 years or 70 percent of the 
economic useful life of the unit determined as of the time the unit is 
built, with option rights to purchase or release some portion of the 
nameplate capacity and associated energy generated by the unit at the 
end of the period.
    Maximum design heat input means the maximum amount of fuel per hour 
(in Btu/hr) that a 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) 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 (in MWe) that the generator is 
capable of producing on a steady state basis and during continuous 
operation (when not restricted by seasonal or other deratings), such 
increased maximum amount as of such completion as specified by the 
person conducting the physical change.
    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 any person who operates, controls, or supervises a 
TR SO2 Group 2 unit or a TR SO2 Group 2 source 
and shall include, but not be limited to, any holding company, utility 
system, or plant manager of such a unit or source.
    Owner means, with regard to 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;
    (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;
    (4) Provided that, for purposes of applying the TR SO2 
Group 2 assurance provisions in Sec. Sec.  97.706(c)(2) and 97.725, if 
one or more owners (as defined in paragraphs (1) through (3) of this 
definition) of one or more TR SO2 Group 2 units in a State 
are wholly owned by another, common owner, all such owners shall be 
treated collectively as a single owner in the State.
    Owner's assurance level means:
    (1) With regard to a State and control period for which the State 
assurance level is exceeded as described in Sec.  97.706(c)(2)(iii)(A) 
and not as described in Sec.  97.706(c)(2)(iii)(B), the owner's share 
of the State SO2 Group 2 trading budget with the one-year 
variability limit for the State for such control period; or
    (2) With regard to a State and control period for which the State 
assurance level is exceeded as described in Sec.  97.706(c)(2)(iii)(B), 
the owner's share of the State SO2 Group 2 trading budget 
with the three-year variability limit for the State for such control 
period.
    Owner's share means:
    (1) With regard to a total amount of SO2 emissions from 
all TR SO2 Group 2 units in a State during a control period, 
the total tonnage of SO2 emissions during such control 
period from all of the owner's TR SO2 Group 2 units in the 
State;
    (2) With regard to a State SO2 Group 2 trading budget 
with a one-year variability limit for a control period, the amount 
(rounded to the nearest allowance) equal to the total amount of TR 
SO2 Group 2 allowances allocated for such control period to 
all of the owner's TR SO2 Group 2 units in the State, 
multiplied by the sum of the State SO2 Group 2 trading 
budget under Sec.  97.710(a) and the State's one-year variability limit 
under Sec.  97.710(b) and divided by such State SO2 Group 2 
trading budget;
    (3) With regard to a State SO2 Group 2 trading budget 
with a three-year

[[Page 45445]]

variability limit for a control period, the amount (rounded to the 
nearest allowance) equal to the total amount of TR SO2 Group 
2 allowances allocated for such control period to all of the owner's TR 
SO2 Group 2 units in the State, multiplied by the sum of the 
State SO2 Group 2 trading budget under Sec.  97.710(a) and 
the State's three-year variability limit under Sec.  97.710(b) and 
divided by such State SO2 Group 2 trading budget;
    (4) Provided that, in the case of a unit with more than one owner, 
the amount of tonnage of SO2 emissions and of TR 
SO2 Group 2 allowances allocated for a control period, with 
regard to such unit, used in determining each owner's share shall be 
the amount (rounded to the nearest ton and the nearest allowance) equal 
to the unit's SO2 emissions and allocation of such 
allowances, respectively, for such control period multiplied by the 
percentage of ownership in the unit that the owner's legal, equitable, 
leasehold, or contractual reservation or entitlement in the unit 
comprises as of December 31 of such control period;
    (5) Provided that, where two or more units emit through a common 
stack that is the monitoring location from which SO2 mass 
emissions are reported for a control period for a year, the amount of 
tonnage of each unit's SO2 emissions used in determining 
each owner's share for such control period shall be:
    (i) The amount (rounded to the nearest ton) of SO2 
emissions reported at the common stack multiplied by the quotient of 
such unit's heat input for such control period divided by the total 
heat input reported from the common stack for such control period;
    (ii) An amount determined in accordance with a methodology that the 
Administrator determines is consistent with the purposes of this 
definition and whose adverse effect (if any) the Administrator 
determines will be de minimis; or
    (iii) An amount approved by the Administrator in response to a 
petition for an alternative requirement submitted in accordance with 
Sec.  97.735; and
    (6) Provided that, in the case of a unit that operates during, but 
is allocated no TR SO2 Group 2 allowances for, a 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 lesser of--
    (i) The unit's allowable SO2 emission rate (in lb per 
MWe) applicable to such control period, multiplied by a capacity factor 
of 0.84 (if the unit is a coal-fired boiler), 0.15 (if the unit is a 
simple combustion turbine), or 0.66 (if the unit is a combined cycle 
turbine), 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; or
    (ii) For a unit listed in appendix A to this subpart, the sum of 
the unit's SO2 emissions in the control period in the last 
three years during which the unit operated during the control period, 
divided by three.
    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 33 percent of a unit's 
maximum design heat input, divided by 3,413 Btu/kWh, divided by 1,000 
kWh/MWh, and multiplied by 8,760 hr/yr.
    Receive or receipt of means, when referring to the 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 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, 
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) For a topping-cycle unit, the use of reject heat from 
electricity production in a useful thermal energy application or 
process; or
    (2) For a bottoming-cycle unit, 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 or the District of Columbia that is 
subject to the TR SO2 Group 2 Trading Program pursuant to 
Sec.  52.38(c) 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 total energy of all forms supplied to a 
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 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 by the 
Administrator in

[[Page 45446]]

accordance with subpart AAAAA and 52.37(a) 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 by the Administrator in accordance with subpart BBBBB of 
this part and 52.37(b) 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 by the Administrator under this subpart to emit one ton of 
SO2 during a control period of the specified calendar year 
for which the authorization is allocated 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 assurance provisions.
    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 by the 
Administrator in accordance with this subpart and 52.38(c) 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.
    Unit operating day means a calendar day in which a unit combusts 
any fuel.
    Unit operating hour or hour of unit operation means an hour in 
which a unit combusts any fuel.
    Useful power means electricity or mechanical energy that a 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 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, since the 
later of November 15, 1990 or the start-up of the unit's combustion 
chamber, 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 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), (b)(2)(i), or (b)(2)(ii) 
of this section shall not be a TR SO2 Group 2 unit:
    (1)(i) Any unit:
    (A) Qualifying as a cogeneration unit during the later of 1990 or 
the 12-month period starting on the date the unit first produces 
electricity and continuing to qualify as a cogeneration unit; and
    (B) Not serving at any time, since the later of November 15, 1990 
or the start-up of the unit's combustion chamber, a generator with 
nameplate capacity of more than 25 MWe supplying in any calendar year 
more than one-third of the unit's potential electric output capacity or 
219,000 MWh, whichever is greater, to any utility power distribution 
system for sale.
    (ii) If a unit qualifies as a cogeneration unit during the later of 
1990 or the 12-month period starting on the date the unit first 
produces electricity and meets the requirements of paragraphs (b)(1)(i) 
of this section for at least one calendar year, but subsequently no 
longer meets such qualification and requirements, 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.
    (2)(i) Any unit commencing operation before January 1, 1985:
    (A) Qualifying as a solid waste incineration unit during the later 
of 1990 or the 12-month period starting on the date the unit first 
produces electricity and continuing to qualify as a solid waste 
incineration unit; and
    (B) With an average annual fuel consumption of fossil fuel for 
1985-1987 less than 20 percent (on a Btu

[[Page 45447]]

basis) and an average annual fuel consumption of fossil fuel for any 3 
consecutive calendar years after 1990 less than 20 percent (on a Btu 
basis).
    (ii) Any unit commencing operation on or after January 1, 1985:
    (A) Qualifying as a solid waste incineration unit during the later 
of 1990 or the 12-month period starting on the date the unit first 
produces electricity and continuing to qualify as a solid waste 
incineration unit; and
    (B) With an average annual fuel consumption of fossil fuel for the 
first 3 calendar years of operation less than 20 percent (on a Btu 
basis) and an average annual fuel consumption of fossil fuel for any 3 
consecutive calendar years after 1990 less than 20 percent (on a Btu 
basis).
    (iii) If a unit qualifies as a solid waste incineration unit during 
the later of 1990 or the 12-month period starting on the date the unit 
first produces electricity and meets the requirements of paragraph 
(b)(2)(i) or (ii) of this section for at least 3 consecutive calendar 
years, but subsequently no longer meets such qualification and 
requirements, 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 1990 for which the unit has an average annual fuel 
consumption of fossil fuel of 20 percent or more.
    (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, 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 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 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 and is not a TR SO2 Group 2 opt-in unit 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, 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.

[[Page 45448]]

    (ii) If a TR SO2 Group 2 source emits SO2 
during any control period 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 pay any fine, penalty, or assessment or comply with any 
other remedy imposed, for the same violations, under the Clean Air Act; 
and
    (B) 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 the total amount of 
SO2 emissions from all TR SO2 Group 2 units in a 
State during a control period in 2014 or any year thereafter exceeds 
the State assurance level as described in paragraph (c)(2)(iii) of this 
section, then each owner whose share of such SO2 emissions 
during such control period exceeds the owner's assurance level for the 
State and such control period shall hold, in a compliance account 
designated by the owner in accordance with Sec.  97.725(b)(4)(ii), TR 
SO2 Group 2 allowances available for deduction for such 
control period under Sec.  97.725(a) in an amount equal to the product, 
as determined by the Administrator in accordance with Sec.  97.725(b), 
of multiplying--
    (A) The quotient (rounded to the nearest whole number) of the 
amount by which the owner's share of such SO2 emissions 
exceeds the owner's assurance level divided by the sum of the amounts, 
determined for all such owners, by which each owner's share of such 
SO2 emissions exceeds that owner's assurance level; and
    (B) The amount by which total SO2 emissions for all TR 
SO2 Group 2 units in the State for such control period 
exceed the State assurance level as determined in accordance with 
paragraph (c)(2)(iii) of this section.
    (ii) The owner 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) The total amount of SO2 emissions from all TR 
SO2 Group 2 units in a State during a control period in 2014 
or any year thereafter exceeds the State assurance level:
    (A) If such total amount of SO2 emissions exceeds the 
sum, for such control period, of the State SO2 Group 2 
trading budget and the State's one-year variability limit under Sec.  
97.710(b); or
    (B) If, with regard to a control period in 2016 or any year 
thereafter, the sum, divided by three, of such total amount of 
SO2 emissions and the total amounts of SO2 
emissions from all TR SO2 Group 2 units in the State during 
the control periods in the immediately preceding two years exceeds the 
sum, for such control period, of the State SO2 Group 2 
trading budget and the State's three-year variability limit under Sec.  
97.710(b);
    (C) Provided that the amount by which such total amount of 
SO2 emissions exceeds the State assurance level shall be the 
greater of the amounts of the exceedance calculated under paragraph 
(c)(2)(iii)(A) of this section and under paragraph (c)(2)(iii)(B) of 
this section.
    (iv) It shall not be a violation of this subpart or of the Clean 
Air Act if the total amount of SO2 emissions from all TR 
SO2 Group 2 units in a State during a control period exceeds 
the State assurance level or if an owner's share of total 
SO2 emissions from the TR SO2 Group 2 units in a 
State during a control period exceeds the owner's assurance level.
    (v) To the extent an owner fails to hold TR SO2 Group 2 
allowances for a control period in accordance with paragraphs (c)(2)(i) 
and (ii) of this section,
    (A) The owner 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 owner fails 
to hold for a control period in accordance with paragraphs (c)(2)(i) 
and (ii) 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:
    (i) Under paragraph (c)(1) 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; and
    (ii) Under paragraph (c)(2) of this section for the control period 
starting on the later of January 1, 2014 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 deducted allowances. A TR SO2 Group 2 
allowance shall not be deducted, for compliance with the requirements 
under paragraphs (c)(1) and (2) of this section, for a control period 
in a calendar year before the year for which the TR SO2 
Group 2 allowance was allocated.
    (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. (i) A TR SO2 Group 2 
allowance is a limited authorization to emit one ton of SO2 
in accordance with the TR SO2 Group 2 Trading Program.
    (ii) Notwithstanding any other provision of this subpart, the 
Administrator has the authority to terminate or limit 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 Sec. Sec.  75.10, 75.11, and 75.16 of this chapter), an 
excepted monitoring system (under appendix D 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

[[Page 45449]]

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 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, including any monitoring plans and monitoring system 
certification and recertification applications.
    (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, including any submissions required for compliance with the TR 
SO2 Group 2 assurance provisions. 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 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.


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, falls on a weekend 
or a State or Federal holiday, 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, 
and variability limits.

    (a) The State SO2 Group 2 trading budgets and 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      New-unit set-
                                       trading budget     aside  (tons)
                                          (tons) *     -----------------
                State                ------------------
                                        For 2012 and      For 2012 and
                                         thereafter        thereafter
------------------------------------------------------------------------
Alabama.............................           161,871             4,856
Connecticut.........................             3,059                92
Delaware............................             7,784               234
District of Columbia................               337                10
Florida.............................           161,739             4,852
Kansas..............................            57,275             1,718
Louisiana...........................            90,477             2,714
Maryland............................            39,665             1,190
Massachusetts.......................             7,902               237
Minnesota...........................            47,101             1,413
Nebraska............................            71,598             2,148
New Jersey..........................            11,291               339
South Carolina......................           116,483             3,494
                                     -----------------------------------
    Total...........................           776,582            23,297
------------------------------------------------------------------------
* Without variability limits.

    (b) The States' one-year and three-year variability limits for the 
State SO2 Group 2 trading budgets for the control periods in 
2014 and thereafter are as follows:

[[Page 45450]]



------------------------------------------------------------------------
                                          One-year         Three-year
                                         variability       variability
                                           limits            limits
                State                -----------------------------------
                                          2014 and          2016 and
                                         thereafter        thereafter
                                           (tons)            (tons)
------------------------------------------------------------------------
Alabama.............................            16,187             9,346
Connecticut.........................             1,700               981
Delaware............................             1,700               981
District of Columbia................             1,700               981
Florida.............................            16,174             9,338
Kansas..............................             5,728             3,307
Louisiana...........................             9,048             5,224
Maryland............................             3,967             2,290
Massachusetts.......................             1,700               981
Minnesota...........................             4,710             2,719
Nebraska............................             7,160             4,134
New Jersey..........................             1,700               981
South Carolina......................            11,648             6,725
------------------------------------------------------------------------

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 
set forth in appendix A to this subpart. Listing a unit in such 
appendix does not constitute a determination that the unit is a TR 
SO2 Group 2 unit, and not listing a unit in such appendix 
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 
listed in appendix A to this subpart as being allocated TR 
SO2 Group 2 allowances does not operate, starting after 
2011, during the control period in three consecutive years, such unit 
will not be allocated the TR SO2 Group 2 allowances set 
forth in appendix A to this subpart for the unit for the control 
periods in the seventh year after the first such year and in each year 
after that seventh 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 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.
    (b) New units. (1) By July 1, 2012, and July 1 of each year 
thereafter, the Administrator will calculate the TR SO2 
Group 2 allowance allocation for each TR SO2 Group 2 unit, 
in accordance with Sec.  97.712, for the control period in the year of 
the applicable calculation deadline under this paragraph and will 
promulgate a notice of availability of the results of the calculations.
    (2) For each notice of data availability required in paragraph 
(b)(1) of this section, the Administrator will provide an opportunity 
for submission of objections to the calculations referenced in such 
notice.
    (i) Objections shall be submitted by the deadline specified in such 
notice and shall be limited to addressing whether the calculations are 
in accordance with Sec.  97.712 and Sec. Sec.  97.706(b)(2) and 97.730 
through 97.735.
    (ii) 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)(i) of this section. By September 1 
immediately after the promulgation of such notice, the Administrator 
will promulgate a notice of 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)(i) of this section.
    (c) Units that are not TR SO2 Group 2 units. 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 for the control period to a recipient that is not actually 
a TR SO2 Group 2 unit under Sec.  97.704 as of January 1, 
2012, or whose deadline for meeting monitor certification requirements 
under Sec.  97.730(b)(1) and (2) is after January 1, 2012, or if the 
Administrator determines that TR SO2 Group 2 allowances were 
allocated under paragraph (b) of this section and Sec.  97.712 for the 
control period to a recipient that is not actually a TR SO2 
Group 2 unit under Sec.  97.704 as of January 1 of the control period, 
then the Administrator will notify the designated representative and 
will act in accordance with the following procedures:
    (1) Except as provided in paragraph (c)(2) or (3) of this section, 
the Administrator will not record such TR SO2 Group 2 
allowances under Sec.  97.721.
    (2) If the Administrator already recorded such TR SO2 
Group 2 allowances under Sec.  97.721 and if the Administrator makes 
such determination 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.
    (3) If the Administrator already recorded such TR SO2 
Group 2 allowances under Sec.  97.721 and if the Administrator makes 
such determination 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.
    (4) The Administrator will transfer the TR SO2 Group 2 
allowances that are not recorded, or that are deducted, in accordance 
with paragraphs (c)(1) and (2) of this section to the new unit set-
aside, for the State in which such recipient is located, for the 
control period in the year of such transfer if the notice required in 
paragraph (b)(1) of this section for the control period in that year 
has not been promulgated or, such notice has been promulgated, in the 
next year.

[[Page 45451]]

Sec.  97.712  TR SO2 Group 2 allowance allocations for new units.

    (a) For each control period in 2012 and thereafter, the 
Administrator will allocate, in accordance with the following 
procedures, TR SO2 Group 2 allowances to TR SO2 
Group 2 units in a State that are not listed in appendix A to this 
subpart, to TR SO2 Group 2 units that are so listed and 
whose allocation of SO2 Group 2 allowances for such control 
period is covered by Sec.  97.711(c)(1) or (2), and to TR 
SO2 Group 2 units that are so listed and, pursuant to Sec.  
97.711(a)(2), are not allocated TR SO2 Group 2 allowances 
for such control period but that operate during the immediately 
preceding control period:
    (1) The Administrator will establish a separate new unit set-aside 
for each State for each control period in a given year. Each 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). Each new unit set-aside will 
be allocated additional TR SO2 Group 2 allowances in 
accordance with Sec.  97.711(a)(2) and (c)(4).
    (2) The designated representative of such TR SO2 Group 2 
unit may submit to the Administrator a request, in a format prescribed 
by the Administrator, to be allocated TR SO2 Group 2 
allowances for a control period, starting with the later of the control 
period in 2012, the first control period after the control period in 
which the TR SO2 Group 2 unit commences commercial operation 
(for a unit not listed in appendix A to this subpart), or the first 
control period after the control period in which the unit resumes 
operation (for a unit listed in appendix A of this subpart) and for 
each subsequent control period.
    (i) The request must be submitted on or before May 1 of the first 
control period for which TR SO2 Group 2 allowances are 
sought and after the date on which the TR SO2 Group 2 unit 
commences commercial operation (for a unit not listed in appendix A of 
this subpart) or on which the unit resumes operation (for a unit listed 
in appendix A of this subpart).
    (ii) For each control period for which an allocation is sought, the 
request must be for TR SO2 Group 2 allowances in an amount 
equal to the unit's total tons of SO2 emissions during the 
immediately preceding control period.
    (3) The Administrator will review each TR SO2 Group 2 
allowance allocation request under paragraph (a)(2) of this section and 
will accept the request only if it meets the requirements of paragraph 
(a)(2) of this section. The Administrator will allocate TR 
SO2 Group 2 allowances for each control period pursuant to 
an accepted request as follows:
    (i) After May 1 of such control period, the Administrator will 
determine the sum of the TR SO2 Group 2 allowances requested 
in all accepted allowance allocation requests for such control period.
    (ii) If the amount of TR SO2 Group 2 allowances in the 
new unit set-aside for such control period is greater than or equal to 
the sum under paragraph (a)(3)(i) of this section, then the 
Administrator will allocate the amount of TR SO2 Group 2 
allowances requested to each TR SO2 Group 2 unit covered by 
an accepted allowance allocation request.
    (iii) If the amount of TR SO2 Group 2 allowances in the 
new unit set-aside for such control period is less than the sum under 
paragraph (a)(3)(i) of this section, then the Administrator will 
allocate to each TR SO2 Group 2 unit covered by an accepted 
allowance allocation request the amount of the TR SO2 Group 
2 allowances requested, multiplied by the amount of TR SO2 
Group 2 allowances in the new unit set-aside for such control period, 
divided by the sum determined under paragraph (a)(3)(i) of this 
section, and rounded to the nearest allowance.
    (iv) The Administrator will notify, through the promulgation of the 
notices of data availability described in Sec.  97.711(b), each 
designated representative that submitted an allowance allocation 
request of the amount of TR SO2 Group 2 allowances (if any) 
allocated for such control period to the TR SO2 Group 2 unit 
covered by the request.
    (b) If, after completion of the procedures under paragraph (a)(4) 
of this section for a control period, any unallocated TR SO2 
Group 2 allowances remain in the new unit set-aside under paragraph (a) 
of this section for a State for such control period, the Administrator 
will allocate to each TR SO2 Group 2 unit that is in the 
State, is listed in appendix A to this subpart, 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 amount of tons in such new unit set-aside, and rounded 
to the nearest allowance.


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,

[[Page 45452]]

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'' 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 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.

    (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 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, 
including the addition of a new 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 include the change.


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, and actual or projected date of 
commencement of commercial operation.
    (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 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 allowances by contract, TR 
SO2 Group 2 allowances and proceeds of transactions 
involving TR SO2 Group 2

[[Page 45453]]

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 Sec.  97.715(a) or (b), 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 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 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 Allowance Management System 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) 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 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 45454]]

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 order or decision 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 order or decision issued to the authorized account 
representative or alternate authorized account representative by the 
Administrator regarding the general account.
    (ii) Except as provided in paragraph (b)(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 (b)(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 (b)(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 of a new 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 (b)(1) of this 
section has been submitted and received, the Administrator will rely on 
the application unless and until a superseding complete application for 
a general account under paragraph (b)(1) of this section is received by 
the Administrator.
    (ii) Except as provided in paragraph (b)(3)(i) or (ii) of this 
section, no objection or other communication submitted to the 
Administrator concerning the authorization, or any

[[Page 45455]]

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 make an electronic 
submission to the Administrator in accordance with paragraph (b)(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 as an ``agent'');
    (C) For each such natural person, a list of the type or types of 
electronic submissions under paragraph (b)(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(b)(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(b)(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(b)(5) is terminated.''.
    (iv) A notice of delegation submitted under paragraph (b)(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 (b)(5)(iii)(D) of this section and made in accordance with a 
notice of delegation effective under paragraph (b)(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)(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 20 business days after the 
notice is sent. The account will be closed after the 20-day period 
unless, before the end of the 20-day period, the Administrator receives 
a correctly submitted 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.
    (c) Account identification. The Administrator will assign a unique 
identifying number to each account established under paragraph (a) or 
(b) of this section.
    (d) Responsibilities of authorized account representative and 
alternate authorized account representative. After the establishment of 
an Allowance Management System 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 (b)(2)(ii) and (b)(5) of 
this section.


Sec.  97.721  Recordation of TR SO2 Group 2 allowance allocations.

    (a) By September 1, 2011, the Administrator will record in each TR 
SO2 Group 2 source's compliance account the TR 
SO2 Group 2 allowances allocated for the TR SO2 
Group 2 units at the source in accordance with Sec. Sec.  97.711(a) for 
the control periods in 2012, 2013, and 2014.
    (b) By June 1, 2012 and June 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 
for the TR SO2 Group 2 units at the source in accordance 
with Sec.  97.711(a) for the control period in the third year after the 
year of the applicable recordation deadline under this paragraph.
    (c) By September 1, 2012 and September 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 for the TR SO2 Group 2 units at the source in 
accordance with Sec.  97.712 for the control period in the year of the 
applicable recordation deadline under this paragraph.
    (d) When recording the allocation of TR SO2 Group 2 
allowances for a TR SO2 Group 2 unit in a compliance

[[Page 45456]]

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.


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, 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 by 
the request, provided that the transfer is correctly submitted under 
Sec.  97.722.
    (b)(1) A TR SO2 Group 2 allowance transfer 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 under Sec.  97.724 for the control period 
immediately before such allowance transfer deadline.
    (2) A TR SO2 Group 2 allowance transfer that is 
submitted for recordation after the deadline for holding TR 
SO2 Group 2 allowances described in Sec.  97.725(b)(5) and 
that includes any TR SO2 Group 2 allowances allocated for a 
control period before the year of such deadline will not be recorded 
until after the Administrator completes the deductions under Sec.  
97.725 for the control period immediately before the year of such 
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 the control period in the year or 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, the 
Administrator will deduct from the 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 
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 (FIFO) 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 the control period 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 an owner of one or more TR SO2 Group 2 units 
in a State only if the TR SO2 Group 2 allowances:
    (1) Were allocated for the control period in the year or a prior 
year; and
    (2) Are held in a compliance account, designated by the owner in 
accordance with paragraph (b)(4)(ii) of this section,

[[Page 45457]]

of one of the owner's TR SO2 Group 2 sources in the State as 
of the deadline established in paragraph (b)(5) 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, 2015 and June 1 of each year thereafter, the 
Administrator will:
    (i) Calculate, separately for each State, the total amount of 
SO2 emissions from all TR SO2 Group 2 units in 
the State during the control period in the year before the year of this 
calculation deadline and the amount, if any, by which such total amount 
of NOX emissions exceeds the State assurance level as 
described in Sec.  97.706(c)(2)(iii); and
    (ii) Promulgate a notice of availability of the results of the 
calculations required in paragraph (b)(1)(i) of this section, including 
separate calculations of the SO2 emissions for each TR 
SO2 Group 2 unit and of the amounts described in Sec. Sec.  
97.706(c)(2)(iii)(A) and (B) for each State.
    (2) The Administrator will provide an opportunity for submission of 
objections to the calculations referenced by each notice described in 
paragraph (b)(1) of this section.
    (i) Objections shall be submitted by the deadline specified in such 
notice and shall be limited to addressing whether the calculations for 
each TR SO2 Group 2 unit and each State for the control 
period in the year involved are in accordance with Sec.  
97.706(c)(2)(iii) and Sec. Sec.  97.706(b) and 97.730 through 97.735.
    (ii) 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)(i) of this section. By August 1 
immediately after the promulgation of such notice, the Administrator 
will promulgate a notice of 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)(i) of this section.
    (3) For each notice of data availability required in paragraph 
(b)(2)(ii) of this section and for any State identified in such notice 
as having TR SO2 Group 2 sources with total SO2 
emissions exceeding the State assurance level for a control period, as 
described in Sec.  97.706(c)(2)(iii):
    (i) By August 15 immediately after the promulgation of such notice, 
the designated representative of each TR SO2 Group 2 source 
in each such State shall submit a statement, in a format prescribed by 
the Administrator:
    (A) Listing all the owners of each TR SO2 Group 2 unit 
at the source, explaining how the selection of each owner for inclusion 
on the list is consistent with the definition of ``owner'' in Sec.  
97.702, and listing, separately for each unit, the percentage of the 
legal, equitable, leasehold, or contractual reservation or entitlement 
for each such owner as of midnight of December 31 of the control period 
in the year involved; and
    (B) For each TR SO2 Group 2 unit at the source that 
operates during, but is allocated no TR SO2 Group 2 
allowances for, the control period in the year involved, identifying 
whether the unit is a coal-fired boiler, simple combustion turbine, or 
combined cycle turbine cycle and providing the unit's allowable 
SO2 emission rate for such control period.
    (ii) By September 15 immediately after the promulgation of such 
notice, the Administrator will calculate, for each such State and each 
owner of one or more TR SO2 Group 2 units in the State and 
for the control period in the year involved, each owner's share of the 
total SO2 emissions from all TR SO2 Group 2 units 
in the State, each owner's assurance level, and the amount (if any) of 
TR SO2 Group 2 allowances that each owner must hold in 
accordance with the calculation formula in Sec.  97.706(c)(2)(i) and 
will promulgate a notice of 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)(3)(ii) of this section.
    (A) Objections shall be submitted by the deadline specified in such 
notice and shall be limited to addressing whether the calculations for 
each owner for the control period in the year involved are consistent 
with the SO2 emissions for the relevant TR SO2 
Group 2 units as set forth in the notice required in paragraph 
(b)(2)(ii) of this section, the definitions of ``owner'', ``owner's 
assurance level'', and ``owner's share'' in Sec.  97.702, and the 
calculation formula in Sec.  97.706(c)(2)(i) and shall not raise any 
issues about any data used in the notice of data availability required 
in paragraph (b)(2)(ii) of this section.
    (B) The Administrator will adjust the calculations to the extent 
necessary to ensure that they are consistent with the data and 
provisions referenced in paragraph (b)(3)(iii)(A) of this section. By 
November 15 immediately after the promulgation of such notice, the 
Administrator will promulgate a notice of 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)(3)(iii)(A) of this section.
    (4) By December 1 immediately after the promulgation of each notice 
of data availability required in paragraph (b)(3)(iii)(B) of this 
section:
    (i) Each owner identified, in such notice, as owning one or more TR 
SO2 Group 2 units in a State and as being required to hold 
TR SO2 Group 2 allowances shall designate the compliance 
account of one of the sources at which such unit or units are located 
to hold such required TR SO2 Group 2 allowances;
    (ii) The authorized account representative for the compliance 
account designated under paragraph (b)(4)(i) of this section shall 
submit to the Administrator a statement, in a format prescribed by the 
Administrator, making this designation.
    (5)(i) As of midnight of December 15 immediately after the 
promulgation of each notice of data availability required in paragraph 
(b)(3)(iii)(B) of this section, each owner described in paragraph 
(b)(4)(i) of this section shall hold in the compliance account 
designated by the owner in accordance with paragraph (b)(4)(ii) of this 
section the total amount of TR SO2 Group 2 allowances, 
available for deduction under paragraph (a) of this section, equal to 
the amount the owner is required to hold as calculated by the 
Administrator and referenced in such notice.
    (ii) Notwithstanding the allowance-holding deadline specified in 
paragraph (b)(5)(i) of this section, if December 15 is not a business 
day, then such allowance-holding deadline shall be midnight of the 
first business day thereafter.
    (6) After December 15 (or the date described in paragraph 
(b)(5)(ii) of this section) immediately after the promulgation of each 
notice of data availability required in paragraph (b)(3)(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 deduct from each 
compliance account designated in accordance with paragraph (b)(4)(ii) 
of this section, TR SO2 Group 2 allowances available under 
paragraph (a) of this section, as follows:
    (i) Until the amount of TR SO2 Group 2 allowances 
deducted equals the

[[Page 45458]]

amount that the owner designating the compliance account is required to 
hold as calculated by the Administrator and referenced in the notice 
required in paragraph (b)(3)(iii)(B) of this section; or
    (ii) If there are insufficient TR SO2 Group 2 allowances 
to complete the deductions in paragraph (b)(6)(i) of this section, 
until no more TR SO2 Group 2 allowances available under 
paragraph (a) of this section remain in the compliance account.
    (7) Notwithstanding any other provision of this subpart and any 
revision, made by or submitted to the Administrator after the 
promulgation of the notices of data availability required in paragraphs 
(b)(2)(ii) and (b)(3)(iii)(B) of this section respectively for a 
control period, of any data used in making the calculations referenced 
in such notice, the amount of TR SO2 Group 2 allowances that 
each owner is required to hold in accordance with Sec.  97.706(c)(2)(i) 
for the control period in the year involved shall continue to be such 
amount as calculated by the Administrator and referenced in such notice 
required in paragraph (b)(3)(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 are required to hold in 
accordance with the calculation formula in Sec.  97.706(c)(2)(i) for 
the control period in the year involved with regard to the State 
involved, provided that--
    (A) With regard to such litigation involving such notice required 
in paragraph (b)(2)(ii) of this section, 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)(ii) of this 
section; and
    (B) With regard to such litigation involving such notice required 
in paragraph (b)(3)(iii) of this section, 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)(3)(iii) of this 
section.
    (ii) If any such data are revised by the owners and operators of a 
source whose designated representative submitted such data under 
paragraph (b)(3)(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 are 
required to hold in accordance with the calculation formula in Sec.  
97.706(c)(2)(i) for the control period in the year involved with regard 
to the State involved, provided that such litigation was initiated no 
later than 30 days after promulgation of such notice required in 
paragraph (b)(3)(iii)(B) of this section.
    (iii) If the revised data are used to recalculate, in accordance 
with paragraphs (b)(7)(i) and (b)(7)(ii) of this section, the amount of 
TR SO2 Group 2 allowances that an owner is required to hold 
for the control period in the year involved with regard to the State 
involved--
    (A) Where the amount of TR SO2 Group 2 allowances that 
an owner is 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 owner shall hold the additional amount of TR 
SO2 Group 2 allowances in the compliance account designated 
by the owner in accordance with paragraph (b)(4)(ii) of this section. 
The owner's failure to hold such additional amount, as required, before 
the new deadline shall not be a violation of the Clean Air Act. The 
owner's 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 owner fails to hold as 
required as of the new deadline, and each day in the control period in 
the year involved, shall be a separate violation of the Clean Air Act. 
After such deadline, the Administrator will make the appropriate 
deductions from the compliance account.
    (B) For an owner 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 the compliance 
account that the owner designated in accordance with paragraph 
(b)(4)(ii) of this section, an amount of TR SO2 Group 2 
allowances equal to the amount of the decrease to the extent such 
amount was previously deducted from the compliance account under 
paragraph (b)(6) of this section (and has not already been restored to 
the compliance account) for the control period in the year involved.
    (C) Each TR SO2 Group 2 allowance held and deducted 
under paragraph (b)(7)(iii)(A) of this section, or recorded under 
paragraph (b)(7)(iii)(B) of this section, as a result of recalculation 
of requirements under the TR SO2 Group 2 assurance 
provisions for a control period in a given year must be a TR 
SO2 Group 2 allowance allocated for a control period in the 
same or a prior year.
    (c)(1) Identification of TR SO2 Group 2 allowances by serial 
number. The authorized account representative for each source's 
compliance account designated in accordance with paragraph (b)(4)(ii) 
of this section may request that specific TR SO2 Group 2 
allowances, identified by serial number, in the compliance account be 
deducted in accordance with paragraph (b)(6) or (7) of this section. In 
order to be complete, such request shall be submitted to the 
Administrator by the allowance-holding deadline described in paragraph 
(b)(5) of this section and include, in a format prescribed by the 
Administrator, the identification of the compliance account and the 
appropriate serial numbers.
    (2) First-in, first-out. The Administrator will deduct TR 
SO2 Group 2 allowances under paragraphs (b)(6) and (7) of 
this section from each source's compliance account designated under 
paragraph (b)(4)(ii) of this section 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 (FIFO) 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) Recordation of deductions. The Administrator will record in the 
appropriate compliance account all deductions from such an account 
under paragraph (b) of this section.


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

[[Page 45459]]

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, 97.727, 97.728, 97.742, or 97.743.


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 
source's compliance 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. The owner or operator 
shall record, report, and quality-assure the data from the monitoring 
systems under paragraph (a)(1) of this section on and after the 
following dates.
    (1) For the owner or operator of a TR SO2 Group 2 unit 
that commences commercial operation before July 1, 2011, by 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 dates:
    (i) January 1, 2012; or
    (ii) 180 calendar days, whichever occurs first, after the date on 
which the unit commences commercial operation.
    (3) For 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 under paragraph (b)(1) or (2) of this section, by 90 unit 
operating days or 180 calendar days, whichever occurs first, after the 
date on which emissions first exit to the atmosphere through the new 
stack or flue or add-on SO2 emissions controls.
    (4) Notwithstanding the dates in paragraphs (b)(1) and (2) of this 
section, for the owner or operator of a unit for which a TR opt-in 
application is submitted and not withdrawn and is not yet approved or 
disapproved, by the date specified in Sec.  97.741(c).
    (5) Notwithstanding the dates in paragraphs (b)(1) and (2) of this 
section, for the owner or operator of a TR SO2 Group 2 opt-
in unit, by the date on which the TR SO2 Group 2 opt-in unit 
enters the TR SO2 Group 2 Trading Program as provided in 
Sec.  97.741(h).
    (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 emissions to the atmosphere without accounting for all 
such emissions in accordance with the applicable provisions of this 
subpart and part 75 of this chapter.
    (3) No owner or operator of a 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 emissions 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

[[Page 45460]]

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) 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 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.  97.733.
    (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. The 120-day 
review period specified in paragraph

[[Page 45461]]

(d)(3) of this section shall not begin before receipt of a complete 
certification application.
    (C) Disapproval notice. If the certification application shows that 
any monitoring system does not meet the performance requirements of 
part 75 of this chapter or if the certification application is 
incomplete and the requirement for disapproval under paragraph 
(d)(3)(iv)(B) of this section is met, then the 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 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 
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 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;
    (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

[[Page 45462]]

commence in the quarter covering January 1, 2012 through March 31, 
2012;
    (iii) Notwithstanding paragraphs (d)(1)(i) and (ii) of this 
section, for a unit for which a TR opt-in application is submitted and 
not withdrawn and is not yet approved or disapproved, the calendar 
quarter corresponding to the date specified in Sec.  97.741(c); and
    (iv) Notwithstanding paragraphs (d)(1)(i) and (ii) of this section, 
for a TR SO2 Group 2 opt-in unit, the calendar quarter 
corresponding to the date on which the TR SO2 Group 1 opt-in 
unit enters the TR SO2 Group 2 Trading Program as provided 
in Sec.  97.71(h).
    (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 or paragraph (5)(i) or 
(ii) of the definition of ``owner's share'' in Sec.  97.702.
    (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.


Sec.  97.740  General requirements for TR SO2 Group 2 opt-in units.

    (a) A TR SO2 Group 2 opt-in unit must be a unit that:
    (1) Is located in a State;
    (2) Is not a TR SO2 Group 2 unit under Sec.  97.704;
    (3) Is not covered by a retired unit exemption under Sec.  72.8 of 
this chapter that is in effect; and
    (4) Vents all of its emissions to a stack and can meet the 
monitoring, recordkeeping, and reporting requirements of this subpart.
    (b) A TR SO2 Group 2 opt-in unit shall be deemed to be a 
TR SO2 Group 2 unit for purposes of applying this subpart, 
except for Sec. Sec.  97.705, 97.711, and 97.712.
    (c) Solely for purposes of applying the requirements of Sec. Sec.  
97.713 through 97.718 and Sec. Sec.  97.730 through 97.735, a unit for 
which a TR opt-in application is submitted and not withdrawn and is not 
yet approved or disapproved under Sec.  97.742 shall be deemed to be a 
TR SO2 Group 2 unit.
    (d) Any TR SO2 Group 2 opt-in unit, and any unit for 
which a TR opt-in application is submitted and not withdrawn and is not 
yet approved or disapproved under Sec.  97.742, located at the same 
source as one or more TR SO2 Group 2 units shall have the 
same designated representative and alternate designated representative 
as such TR SO2 Group 2 units.


Sec.  97.741  Opt-in process.

    A unit meeting the requirements for a TR SO2 Group 2 
opt-in unit in Sec.  97.740(a) may become a TR SO2 Group 2 
opt-in unit only if, in accordance with this section, the designated 
representative of the unit submits a complete TR opt-in application for 
the unit and the Administrator approves the application.
    (a) Applying to opt-in. The designated representative of the unit 
may submit a complete TR opt-in application for the unit at any time, 
except as provided under Sec.  97.742(e). A complete TR opt-in 
application shall include the following elements in a format prescribed 
by the Administrator:
    (1) Identification of the unit and the source where the unit is 
located,

[[Page 45463]]

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, and unit identification number and 
type;
    (2) A certification that the unit:
    (i) Is not a TR SO2 Group 2 unit under Sec.  97.704;
    (ii) Is not covered by a retired unit exemption under Sec.  72.8 of 
this chapter that is in effect;
    (iii) Vents all of its emissions to a stack; and
    (iv) Has documented heat input (greater than 0 mmBtu) for more than 
876 hours during the 6 months immediately preceding submission of the 
TR opt-in application;
    (3) A monitoring plan in accordance with Sec. Sec.  97.730 through 
97.735;
    (4) A statement that the unit, if approved to become a TR 
SO2 Group 2 unit under paragraph (g) of this section, may 
withdraw from the TR SO2 Group 2 Trading Program only in 
accordance with Sec.  97.742;
    (5) A statement that the unit, if approved to become a TR 
SO2 Group 2 unit under paragraph (g) of this section, is 
subject to, and the owners and operators of the unit must comply with, 
the requirements of Sec.  97.743;
    (6) A complete certificate of representation under Sec.  97.716 
consistent with Sec.  97.740, if no designated representative has been 
previously designated for the source that includes the unit; and
    (7) The signature of the designated representative and the date 
signed.
    (b) Interim review of monitoring plan. The Administrator will 
determine, on an interim basis, the sufficiency of the monitoring plan 
submitted under paragraph (a)(3) of this section. The monitoring plan 
is sufficient, for purposes of interim review, if the plan appears to 
contain information demonstrating that the SO2 emission rate 
and heat input of the unit and all other applicable parameters are 
monitored and reported in accordance with Sec. Sec.  97.730 through 
97.735. A determination of sufficiency shall not be construed as 
acceptance or approval of the monitoring plan.
    (c) Monitoring and reporting. (1)(i) If the Administrator 
determines that the monitoring plan is sufficient under paragraph (b) 
of this section, the owner or operator of the unit shall monitor and 
report the SO2 emission rate and the heat input of the unit 
and all other applicable parameters, in accordance with Sec. Sec.  
97.730 through 97.735, starting on the date of certification of the 
necessary monitoring systems under Sec. Sec.  97.730 through 97.735 and 
continuing until the TR opt-in application submitted under paragraph 
(a) of this section is disapproved under this section or, if such TR 
opt-in application is approved, the date and time when the unit is 
withdrawn from the TR SO2 Group 2 Trading Program in 
accordance with Sec.  97.742.
    (ii) The monitoring and reporting under paragraph (c)(1)(i) of this 
section shall cover the entire control period immediately before the 
date on which the unit enters the TR SO2 Group 2 Trading 
Program under paragraph (h) of this section, during which period 
monitoring system availability must not be less than 98 percent under 
Sec. Sec.  97.730 through 97.735 and the unit must be in full 
compliance with any applicable State or Federal emissions or emissions-
related requirements.
    (2) To the extent the SO2 emission rate and the heat 
input of the unit are monitored and reported in accordance with 
Sec. Sec.  97.730 through 97.735 for one or more entire control 
periods, in addition to the control period under paragraph (c)(1)(ii) 
of this section, during which control periods monitoring system 
availability is not less than 98 percent under Sec. Sec.  97.730 
through 97.735 and the unit is in full compliance with any applicable 
State or Federal emissions or emissions-related requirements and which 
control periods begin not more than 3 years before the unit enters the 
TR SO2 Group 2 Trading Program under paragraph (h) of this 
section, such information shall be used as provided in paragraphs (e) 
and (f) of this section.
    (d) Statement on compliance. After submitting to the Administrator 
all quarterly reports required for the unit under paragraph (c) of this 
section, the designated representative shall submit, in a format 
prescribed by the Administrator, to the Administrator a statement that, 
for the years covered by such quarterly reports, the unit was in full 
compliance with any applicable State or Federal emissions or emissions-
related requirements.
    (e) Baseline heat input. The unit's baseline heat input shall 
equal:
    (1) If the unit's SO2 emission rate and heat input are 
monitored and reported for only one entire control period, in 
accordance with paragraph (c) of this section, the unit's total heat 
input (in mmBtu) for such control period; or
    (2) If the unit's SO2 emission rate and heat input are 
monitored and reported for more than one entire control period, in 
accordance with paragraph (c) of this section, the average of the 
amounts of the unit's total heat input (in mmBtu) for such control 
periods.
    (f) Baseline SO2 emission rate. The unit's baseline SO2 
emission rate shall equal:
    (1) If the unit's SO2 emission rate and heat input are 
monitored and reported for only one entire control period, in 
accordance with paragraph (c) of this section, the unit's 
SO2 emission rate (in lb/mmBtu) for such control period;
    (2) If the unit's SO2 emission rate and heat input are 
monitored and reported for more than one entire control period, in 
accordance with paragraph (c) of this section, and the unit does not 
have add-on SO2 emission controls during any such control 
periods, the average of the amounts of the unit's SO2 
emission rate (in lb/mmBtu) for such control periods; or
    (3) If the unit's SO2 emission rate and heat input are 
monitored and reported for more than one entire control period, in 
accordance with paragraph (c) of this section, and the unit has add-on 
SO2 emission controls during any such control periods, the 
average of the amounts of the unit's SO2 emission rate (in 
lb/mmBtu) for such control periods during which the unit has add-on 
SO2 emission controls.
    (g) Review of TR opt-in application.
    (1) After the designated representative submits the complete TR 
opt-in application, quarterly reports, and statement required in 
paragraphs (a), (c), and (d) of this section and if the Administrator 
determines that the designated representative shows that the unit meets 
the requirements for a TR SO2 Group 2 opt-in unit in Sec.  
97.640, the element certified in paragraph (a)(2)(iv) of this section, 
and the monitoring and reporting requirements of paragraph (c) of this 
section, the Administrator will issue a written approval of the TR opt-
in application for the unit. The written approval will state the unit's 
baseline heat input and baseline SO2 emission rate. The 
Administrator will thereafter establish a compliance account for the 
source that includes the unit unless the source already has a 
compliance account.
    (2) Notwithstanding paragraphs (a) through (f) of this section, if, 
at any time before the TR opt-in application is approved under 
paragraph (g)(1) of this section, the Administrator determines that the 
unit cannot meet the requirements for a TR SO2 Group 2 opt-
in unit in Sec.  97.740, the element certified in paragraph (a)(2)(iv) 
of this section, or the monitoring and reporting requirements in 
paragraph (c) of this section, the Administrator will issue a written 
disapproval of the TR opt-in application for the unit.
    (h) Date of entry into TR SO2 Group 2 Trading Program. A unit for 
which a

[[Page 45464]]

TR opt-in application is approved under paragraph (g)(1) of this 
section shall become a TR SO2 Group 2 opt-in unit, and a TR 
SO2 Group 2 unit, effective as of the later of January 1, 
2012 or January 1 of the first control period during which such 
approval is issued.


Sec.  97.742  Withdrawal of TR SO2 Group 2 opt-in unit from TR SO2 
Group 2 Trading Program.

    A TR SO2 Group 2 opt-in unit may withdraw from the TR 
SO2 Group 2 Trading Program only if, in accordance with this 
section, the designated representative of the unit submits a request to 
withdraw the unit and the Administrator issues a written approval of 
the request.
    (a) Requesting withdrawal. In order to withdraw the TR 
SO2 Group 2 opt-in unit from the TR SO2 Group 2 
Trading Program, the designated representative of the unit shall submit 
to the Administrator a request to withdraw the unit effective as of 
midnight of December 31 of a specified calendar year, which date must 
be at least 4 years after December 31 of the year of the unit's entry 
into the TR SO2 Group 2 Trading Program under Sec.  
97.741(h). The request shall be in a format prescribed by the 
Administrator and shall be submitted no later than 90 days before the 
requested effective date of withdrawal.
    (b) Conditions for withdrawal. Before a TR SO2 Group 2 
opt-in unit covered by the request to withdraw may withdraw from the TR 
SO2 Group 2 Trading Program, the following conditions must 
be met:
    (1) For the control period ending on the date on which the 
withdrawal is to be effective, the source that includes the TR 
SO2 Group 2 opt-in unit must meet the requirement to hold TR 
SO2 Group 2 allowances under Sec. Sec.  97.724 and 97.725 
and cannot have any excess emissions.
    (2) After the requirement under paragraph (b)(1) of this section is 
met, the Administrator will deduct from the compliance account of the 
source that includes the TR SO2 Group 2 opt-in unit TR 
SO2 Group 2 allowances equal in amount to and allocated for 
the same or a prior control period as any TR SO2 Group 2 
allowances allocated to the TR SO2 Group 2 opt-in unit under 
Sec.  97.744 for any control period after the date on which the 
withdrawal is to be effective. If there are no other TR SO2 
Group 2 units at the source, the Administrator will close the 
compliance account, and the owners and operators of the TR 
SO2 Group 2 opt-in unit may submit a TR SO2 Group 
2 allowance transfer for any remaining TR SO2 Group 2 
allowances to another Allowance Management System account in accordance 
with Sec. Sec.  97.722 and 97.723.
    (c) Approving withdrawal. (1) After the requirements for withdrawal 
under paragraphs (a) and (b) of this section are met (including 
deduction of the full amount of TR SO2 Group 2 allowances 
required), the Administrator will issue a written approval of the 
request to withdraw, which will become effective as of midnight on 
December 31 of the calendar year for which the withdrawal was 
requested. The unit covered by the request shall continue to be a TR 
SO2 Group 2 opt-in unit until the effective date of the 
withdrawal and shall comply with all requirements under the TR 
SO2 Group 2 Trading Program concerning any control periods 
for which the unit is a TR SO2 Group 2 opt-in unit, even if 
such requirements arise or must be complied with after the withdrawal 
takes effect.
    (2) If the requirements for withdrawal under paragraphs (a) and (b) 
of this section are not met, the Administrator will issue a written 
disapproval of the request to withdraw. The unit covered by the request 
shall continue to be a TR SO2 Group 2 opt-in unit.
    (d) Reapplication upon failure to meet conditions of withdrawal. If 
the Administrator disapproves the request to withdraw, the designated 
representative of the unit may submit another request to withdraw in 
accordance with paragraphs (a) and (b) of this section.
    (e) Ability to reapply to the TR SO2 Group 2 Trading Program. Once 
a TR SO2 Group 2 opt-in unit withdraws from the TR 
SO2 Group 2 Trading Program, the designated representative 
may not submit another opt-in application under Sec.  97.741 for such 
unit before the date that is 4 years after the date on which the 
withdrawal became effective.


Sec.  97.743  Change in regulatory status.

    (a) Notification. If a TR SO2 Group 2 opt-in unit 
becomes a TR SO2 Group 2 unit under Sec.  97.704, then the 
designated representative of the unit shall notify the Administrator in 
writing of such change in the TR SO2 Group 2 opt-in unit's 
regulatory status, within 30 days of such change.
    (b) Administrator's actions. (1) If a TR SO2 Group 2 
opt-in unit becomes a TR SO2 Group 2 unit under Sec.  
97.604, the Administrator will deduct, from the compliance account of 
the source that includes the TR SO2 Group 2 opt-in unit that 
becomes a TR SO2 Group 2 unit under Sec.  97.704, TR 
SO2 Group 2 allowances equal in amount to and allocated for 
the same or a prior control period as:
    (i) Any TR SO2 Group 2 allowances allocated to the TR 
SO2 Group 2 opt-in unit under Sec.  97.744 for any control 
period starting after the date on which the TR SO2 Group 2 
opt-in unit becomes a TR SO2 Group 2 unit under Sec.  
97.704; and
    (ii) If the date on which the TR SO2 Group 2 opt-in unit 
becomes a TR SO2 Group 2 unit under Sec.  97.704 is not 
December 31, the TR SO2 Group 2 allowances allocated to the 
TR SO2 Group 2 opt-in unit under Sec.  97.744 for the 
control period that includes the date on which the TR SO2 
Group 2 opt-in unit becomes a TR SO2 Group 2 unit under 
Sec.  97.704--
    (A) Multiplied by the ratio of the number of days, in the control 
period, starting with the date on which the TR SO2 Group 2 
opt-in unit becomes a TR SO2 Group 2 unit under Sec.  
97.704, divided by the total number of days in the control period, and
    (B) Rounded to the nearest allowance.
    (2) The designated representative shall ensure that the compliance 
account of the source that includes the TR SO2 Group 2 opt-
in unit that becomes a TR SO2 Group 2 unit under Sec.  
97.704 contains the TR SO2 Group 2 allowances necessary for 
completion of the deduction under paragraph (b)(1) of this section.
    (3)(i) For control periods starting after the date on which the TR 
SO2 Group 2 opt-in unit becomes a TR SO2 Group 2 
unit under Sec.  97.704, the TR SO2 Group 2 opt-in unit will 
be allocated TR SO2 Group 2 allowances in accordance with 
Sec.  97.712.
    (ii) If the date on which the TR SO2 Group 2 opt-in unit 
becomes a TR SO2 Group 2 unit under Sec.  97.704 is not 
December 31, the following amount of TR SO2 Group 2 
allowances will be allocated to the TR SO2 Group 2 opt-in 
unit (as a TR SO2 Group 2 unit) in accordance with Sec.  
97.712 for the control period that includes the date on which the TR 
SO2 Group 2 opt-in unit becomes a TR SO2 Group 2 
unit under Sec.  97.704:
    (A) The amount of TR SO2 Group 2 allowances otherwise 
allocated to the TR SO2 Group 2 opt-in unit (as a TR 
SO2 Group 2 unit) in accordance with Sec.  97.712 for the 
control period;
    (B) Multiplied by the ratio of the number of days, in the control 
period, starting with the date on which the TR SO2 Group 2 
opt-in unit becomes a TR SO2 Group 2 unit under Sec.  
97.704, divided by the total number of days in the control period; and
    (C) Rounded to the nearest allowance.

[[Page 45465]]

Sec.  97.744  TR SO2 Group 2 allowance allocations to TR SO2 Group 2 
opt-in units.

    (a) Timing requirements. (1) When the TR opt-in application is 
approved for a unit under Sec.  97.741(g), the Administrator will issue 
TR SO2 Group 2 allowances and allocate them to the unit for 
the control period in which the unit enters the TR SO2 Group 
2 Trading Program under Sec.  97.741(h), in accordance with paragraph 
(b) of this section.
    (2) By no later than October 31 of the control period after the 
control period in which a TR SO2 Group 2 opt-in unit enters 
the TR SO2 Group 2 Trading Program under Sec.  97.741(h) and 
October 31 of each year thereafter, the Administrator will issue TR 
SO2 Group 2 allowances and allocate them to the TR 
SO2 Group 2 opt-in unit for the control period that includes 
such allocation deadline and in which the unit is a TR SO2 
Group 2 opt-in unit, in accordance with paragraph (b) of this section.
    (b) Calculation of allocation. For each control period for which a 
TR SO2 Group 2 opt-in unit is to be allocated TR 
SO2 Group 2 allowances, the Administrator will issue and 
allocate TR SO2 Group 2 allowances in accordance with the 
following procedures:
    (1) The heat input (in mmBtu) used for calculating the TR 
SO2 Group 2 allowance allocation will be the lesser of:
    (i) The TR SO2 Group 2 opt-in unit's baseline heat input 
determined under Sec.  97.741(g); or
    (ii) The TR SO2 Group 2 opt-in unit's heat input, as 
determined in accordance with Sec. Sec.  97.730 through 97.735, for the 
immediately prior control period, except when the allocation is being 
calculated for the control period in which the TR SO2 Group 
2 opt-in unit enters the TR SO2 Group 2 Trading Program 
under Sec.  97.741(h).
    (2) The SO2 emission rate (in lb/mmBtu) used for 
calculating TR SO2 Group 2 allowance allocations will be the 
lesser of:
    (i) The TR SO2 Group 2 opt-in unit's baseline 
SO2 emission rate (in lb/mmBtu) determined under Sec.  
97.741(g) and multiplied by 70 percent; or
    (ii) The most stringent State or Federal SO2 emissions 
limitation applicable to the TR SO2 Group 2 opt-in unit at 
any time during the control period for which TR SO2 Group 2 
allowances are to be allocated.
    (3) The Administrator will issue TR SO2 Group 2 
allowances and allocate them to the TR SO2 Group 2 opt-in 
unit in an amount equaling the heat input under paragraph (b)(1) of 
this section, multiplied by the SO2 emission rate under 
paragraph (b)(2) of this section, divided by 2,000 lb/ton, and rounded 
to the nearest allowance.
    (c) Recordation. (1) The Administrator will record, in the 
compliance account of the source that includes the TR SO2 
Group 2 opt-in unit, the TR SO2 Group 2 allowances allocated 
to the TR SO2 Group 2 opt-in unit under paragraph (a)(1) of 
this section.
    (2) By December 1 of the control period after the control period in 
which a TR SO2 Group 2 opt-in unit enters the TR 
SO2 Group 2 Trading Program under Sec.  97.741(h) and 
December 1 of each year thereafter, the Administrator will record, in 
the compliance account of the source that includes the TR 
SO2 Group 2 opt-in unit, the TR SO2 Group 2 
allowances allocated to the TR SO2 Group 2 opt-in unit under 
paragraph (a)(2) of this section.

[FR Doc. 2010-17007 Filed 7-30-10; 8:45 am]
BILLING CODE 6560-50-P

