[Federal Register Volume 80, Number 205 (Friday, October 23, 2015)]
[Proposed Rules]
[Pages 64966-65116]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2015-22848]
[[Page 64965]]
Vol. 80
Friday,
No. 205
October 23, 2015
Part IV
Environmental Protection Agency
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40 CFR Parts 60, 62, and 78
Federal Plan Requirements for Greenhouse Gas Emissions From Electric
Utility Generating Units Constructed on or Before January 8, 2014;
Model Trading Rules; Amendments to Framework Regulations; Proposed Rule
Federal Register / Vol. 80 , No. 205 / Friday, October 23, 2015 /
Proposed Rules
[[Page 64966]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 60, 62, and 78
[EPA-HQ-OAR-2015-0199; FRL 9930-67-OAR]
RIN 2060-AS47
Federal Plan Requirements for Greenhouse Gas Emissions From
Electric Utility Generating Units Constructed on or Before January 8,
2014; Model Trading Rules; Amendments to Framework Regulations
AGENCY: Environmental Protection Agency (EPA).
ACTION: Proposed rule.
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SUMMARY: In this action, the Environmental Protection Agency (EPA) is
proposing a federal plan to implement the greenhouse gas (GHG) emission
guidelines (EGs) for existing fossil fuel-fired electric generating
units (EGUs) under the Clean Air Act (CAA). The EGs were proposed in
June 2014 and finalized on August 3, 2015 as the Carbon Pollution
Emission Guidelines for Existing Stationary Sources: Electric Utility
Generating Units (also known as the Clean Power Plan or EGs). This
proposal presents two approaches to a federal plan for states and other
jurisdictions that do not submit an approvable plan to the EPA: a rate-
based emission trading program and a mass-based emission trading
program. These proposals also constitute proposed model trading rules
that states can adopt or tailor for implementation of the final EGs.
The federal plan is an important measure to ensure that congressionally
mandated emission standards under the authority of the CAA are
implemented. The proposed federal plan is related to but separate from
the final EGs. The final EGs establish the best system of emission
reduction (BSER) for applicable fossil fuel-fired EGUs in the form of a
carbon dioxide (CO2) emission performance rate for steam-
fired EGUs and a CO2 emission performance rate for natural
gas-fired combined cycle (NGCC) units, and provide guidance and
criteria for the development of approvable state plans. The purpose of
the proposed federal plan is to establish requirements directly
applicable to a state's affected EGUs that meet these emission
performance levels, or the equivalent statewide goal, in order to
achieve reductions in CO2 emissions in the case where a
state or other jurisdiction does not submit an approvable plan. The
stringency of the emission performance levels established in the final
EGs will be the same whether implemented through a state plan or a
federal plan. The EPA is also proposing enhancements to the CAA section
111(d) framework regulations related to the process and timing for
state plan submissions and EPA actions. The EPA intends to finalize
both the rate-based and mass-based model trading rules in summer 2016.
DATES: Comments. Comments must be received on or before January 21,
2016.
Public Hearing. The EPA will hold public hearings on the proposal.
Details will be announced in a separate Federal Register document.
ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-
OAR-2015-0199, to the Federal eRulemaking Portal: http://www.regulations.gov. Follow the online instructions for submitting
comments. Once submitted, comments cannot be edited or withdrawn. The
EPA may publish any comment received to its public docket. Do not
submit electronically any information you consider to be Confidential
Business Information (CBI) or other information whose disclosure is
restricted by statute. Multimedia submissions (audio, video, etc.) must
be accompanied by a written comment. The written comment is considered
the official comment and should include discussion of all points you
wish to make. The EPA will generally not consider comments or comment
contents located outside of the primary submission (i.e., on the web,
cloud, or other file sharing system). For additional submission
methods, the full EPA public comment policy, information about CBI or
multimedia submissions, and general guidance on making effective
comments, please visit http://www2.epa.gov/dockets/commenting-epa-dockets.
Instructions: Direct your comments on the federal plan requirements
proposed rule to Docket ID No. EPA-HQ-OAR-2015-0199. The EPA's policy
is that all comments received will be included in the public docket 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 email. The http://www.regulations.gov Web site is an ``anonymous access'' system, which
means the EPA will not know your identity or contact information unless
you provide it in the body of your comment. If you send an email
comment directly to the EPA without going through http://www.regulations.gov, your email 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, the 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 the EPA cannot read your comment due to technical
difficulties and cannot contact you for clarification, the EPA may not
be able to consider your comment. Electronic files should avoid the use
of special characters, any form of encryption and be free of any
defects or viruses.
Docket: The EPA has established a docket for this action under
Docket ID No. EPA-HQ-OAR-2015-0199. The EPA has previously established
a docket for the January 8, 2014, Clean Power Plan proposal under
Docket ID No. EPA-HQ-OAR-2009-0559. 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 form. Publicly available docket materials are available
either electronically at http://www.regulations.gov or in hard copy at
the EPA Docket Center EPA/DC, EPA WJC 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 holidays.
The telephone number for the Public Reading Room is (202) 566-1744, and
the telephone number for the EPA Docket Center is (202) 566-1742.
FOR FURTHER INFORMATION CONTACT: Ms. Toni Jones, Fuels and Incineration
Group, Sector Policies and Programs Division (E143-05), Environmental
Protection Agency, Research Triangle Park, North Carolina 27711;
telephone number: (919) 541-0316; fax number: (919) 541-3470; email
address: [email protected].
SUPPLEMENTARY INFORMATION:
Acronyms and Abbreviations. The following acronyms and
abbreviations are used in this document.
ANSI American National Standards Institute
ARP Acid Rain Program
[[Page 64967]]
ATCS Allowance Tracking and Compliance System
BSER Best system of emission reduction
CAA Clean Air Act
CAIR Clean Air Interstate Rule
CARB California Air Resources Board
CBI Confidential Business Information
CEIP Clean Energy Incentive Program
CEMS Continuous emissions monitoring system
CFCs Chlorofluorocarbons
CISWI Commercial Industrial Solid Waste Incinerators
CFR Code of Federal Regulations
CHP Combined heat and power
CO2 Carbon dioxide
CO2e Carbon dioxide equivalent
CSAPR Cross-state Air Pollution Rule
DOE U.S. Department of Energy
DOI U.S. Department of the Interior
DOL U.S. Department of Labor
DS-EE Demand-Side Energy Efficiency
EE Energy efficiency
EGs Emission Guidelines
EGU Electric generating unit
EIA Energy Information Administration
EJ Environmental justice
EM&V Evaluation, measurement, and verification
EPA Environmental Protection Agency
EO Executive Order
ERC Emission rate credit
FERC Federal Energy Regulatory Commission
FIP Federal implementation plan
FR Federal Register
GHG Greenhouse gas
GHGRP Greenhouse Gas Reporting Program
GJ/h Gigajoule per hour
HAP Hazardous air pollutants
ICR Information collection request
IGCC Integrated gasification combined cycle facility
IPM Integrated Planning Model
IPCC Intergovernmental Panel on Climate Change
ISO/RTO Independent System Operator/Regional Transmission
Organization
lbs Pounds
LML Lowest measured PM2.5 levels
MATS Mercury and Air Toxics Standards
M&V Measurement and verification
MMBtu/h Million British Thermal units per hour
MSW Municipal solid waste
MW Megawatts
MWh Megawatt-hours
NAAQS National Ambient Air Quality Standards
NAICS North American Industrial Classification System
NERC North American Electric Reliability Corporation
NGCC Natural gas combined cycle
NSPS New source performance standards
NSR New Source Review
NTTAA National Technology Transfer and Advancement Act
NODA Notice of data availability
NOX Nitrogen oxides
OAP Office of Atmospheric Programs
OAQPS Office of Air Quality Planning and Standards
PRA Paperwork Reduction Act
PSD Prevention of significant deterioration
PUC Public Utility Commission
RCT Randomized control trials
RE Renewable energy
REC Renewable Energy Certificate
RFA Regulatory Flexibility Act
RGGI Regional Greenhouse Gas Initiative
RIA Regulatory impact analysis
RPS Renewable Portfolio Standard
SCT Stationary combustion turbine
SGU Steam generating unit
SIP State implementation plan
SO2 Sulfur dioxide
TRM Technical Reference Manual
TSD Technical support document
The Court U.S. Court of Appeals for the District of Columbia Circuit
TTN Technology Transfer Network
UMRA Unfunded Mandates Reform Act
UNFCCC United Nations Framework Convention on Climate Change
U.S. United States
WWW World Wide Web
Organization of This Document. The following outline is provided to aid
in locating information in this preamble.
I. General Information
A. Executive Summary
B. Organization and Approach for This Proposed Rule
1. The Rate-Based Approach
2. The Mass-Based Approach
3. Other Proposed Actions
C. Who does the proposed action apply to?
1. What is an affected electric utility generating unit?
2. How To Determine if a Unit Is Covered by an Approved and
Effective State Plan
D. What should I consider as I prepare my comments?
II. Background Information
A. What is the regulatory development background for this
proposed rule?
B. What is the purpose of this Proposed Rule?
1. Federal Plan
2. Model Trading Rule
C. Legal Authority
D. Timing of EPA Actions on the Model Trading Rules, Federal
Plan, and Other Proposed Actions
E. Use of the Model Trading Rule as a Backstop
III. Federal Plan Structure To Achieve Reductions
A. Overview
1. Interactions With State Plans and Scope of Trading
2. Addressing Potential Leakage and Interstate Effects
3. Provisions To Encourage Early Action
B. Inventory of Emissions
C. Affected EGUs
D. Compliance Schedule
E. Addressing Reliability Concerns
F. Worker Certification
G. Remaining Useful Lives and Potential for ``Stranded Assets''
H. Implications for Other EPA Programs and Rules
1. Title V Permitting
2. Implications for New Source Review Program
3. Interactions With Other EPA Rules
I. Administrative Appeals Process
J. Consistency of Program Structure With Clean Air Act Authority
1. General Section 111(d)(2) Authority
2. Use of Market Techniques To Implement Standards of
Performance Under the Clean Air Act
IV. Rate-Based Implementation Approach
A. Overview
B. Rate Goals
C. Crediting Mechanism
1. ERCs Generated and Owed Against a Standard
2. Incremental NGCC ERCs
3. Eligible Emission Reduction Measures for ERC Generation
D. ERC Tracking and Compliance Operations
1. Designated Representatives and Alternate Designated
Representatives
2. ERC Tracking and Compliance System
3. Tracking System Requirements
4. Compliance and General Accounts
5. Compliance Demonstration
6. Recordation of ERC Generation and ERC Issuance
7. Independent Verifiers
8. Evaluation, Measurement, and Verification (EM&V) Plans,
Monitoring and Verification (M&V) Reports, and Verification Reports
9. ERC Transfers and Trading
10. Compliance With Emissions Standards
11. Other ERC Tracking and Compliance Operations Provisions
12. Banking of ERCs
13. Emissions Monitoring and Reporting
E. Federal Plan and State Plan Interactions
1. Interstate Trading
2. Treatment of States Entering or Exiting the Trading Program
V. Mass-Based Implementation Approach
A. Trading Program Overview
B. Statewide Mass-Based Emissions Goals
C. Compliance Timing and Allowance Banking
D. Initial Distribution of Allowances
1. Proposed Allocation Approach and Alternatives
2. Timing of Allowance Recordation
3. Allowance Set-Asides To Address Leakage to New Sources
4. Provisions To Encourage Early Action
5. Allocations to Units That Change Status
E. State-Determined Allowance Distribution
F. Treatment of States Entering or Exiting the Trading Program
G. Allowance Tracking, Compliance Operations, and Penalties
1. Designated Representatives and Alternate Designated
Representatives
2. Allowance Tracking and Compliance System
3. Compliance and General Accounts
4. Recordation of Allowance Allocations and Transfers
5. Compliance With Emissions Limitations
6. Other Allowance Tracking and Compliance Operations Provisions
H. Emissions Monitoring and Reporting Requirements
VI. Implementation of the Federal Plan and Delegation
A. Delegation of the Federal Plan and Retained Authorities
B. Mechanisms for Transferring Authority
1. Federal Plan Becomes Effective Prior To Approval of a State
or Tribal Plan
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2. State or Tribe Takes Delegation of the Federal Plan
C. Implementing Authority
D. Necessary or Appropriate Finding for Affected EGUs in Indian
Country
VII. Amendments To Process for Submittal and Approval of State Plans
and EPA Actions
A. Partial Approvals/Disapprovals
B. Conditional Approvals
C. Calls for Plan Revisions
D. Error Corrections
E. Completeness Criteria
F. Update to Deadlines for EPA Actions
G. Proposed Interpretation Regarding Existing Sources That
Modify or Reconstruct
H. Separate Finalization of These Changes
VIII. Impacts of This Action
A. Endangered Species Act
B. What are the Air Impacts?
C. What are the Energy Impacts?
D. What are the Compliance Costs?
E. What are the Economic and Employment Impacts?
F. What are the Benefits of the Proposed Action?
IX. Community and Environmental Justice Considerations
A. Proximity Analysis
B. Community Engagement in This Rulemaking Process
C. Providing Communities With Access to Additional Resources
D. Federal Programs and Resources Available to Communities
E. Co-Pollutants
F. Assessing Impacts of Federal Plan Implementation
G. The EPA's Continued Engagement
X. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
B. Paperwork Reduction Act (PRA)
C. Regulatory Flexibility Act (RFA)
D. Unfunded Mandates Reform Act (UMRA)
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 Risks and Safety Risks
H. Executive Order 13211: Actions That Significantly Affect
Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act (NTTAA) and
1 CFR Part 51
J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
I. General Information
A. Executive Summary
In the CAA, Congress created a partnership between the EPA and the
states. Under section 111(d) of the CAA, the EPA establishes emission
performance levels based on its determination of the BSER for existing
sources of air pollution and provides guidelines for state plans to
apply standards of performance to their sources that meet the BSER
level of performance. The EPA promulgated EGs under CAA section 111(d)
which set source-level CO2 emission performance rates for
the EGUs at certain large fossil fuel-fired power plants (``affected
EGUs''). States then apply these EGs to their sources in developing
state plans to achieve these emission performance levels for EPA
approval, or initial submittals, by September 6, 2016. The amount of
reductions in CO2 that the EPA determined to be achievable
for these sources is based on its determination of what constitutes the
BSER. This determination is finalized in the EGs, which are designed to
maximize the flexibility of both states and affected EGUs in meeting
CO2 emissions performance rates. While states may impose the
emission rates directly on their affected EGUs, states also have the
option of submitting more tailored plans that meet state-specific
emissions goals. The EGs also provide flexibility by allowing for
emissions trading and multi-state compliance options.
While it has been the EPA's longstanding view that the statute
identifies states as the preferred implementers of CAA programs, the
agency makes clear in the EGs that states cannot and will not be
penalized for failing to participate in this program. However, if a
state does not submit an approvable plan under section 111(d) of the
CAA, the EPA will develop, implement, and enforce a federal plan to
reduce CO2 from the fossil fuel-fired power plants in that
state. This is wholly consistent with the ``cooperative federalism''
structure of the CAA and many of our nation's other environmental laws.
In addition, we have heard from states and other stakeholders that it
would be helpful for the agency to present model designs for state
plans, and a federal plan would be an appropriate means of doing that.
Accordingly, the EPA proposes a federal plan under section 111(d)
of the CAA for the control of CO2, a GHG pollutant, from
certain emitting fossil fuel-fired power plants, in the event that some
states do not adopt their own plans. Specifically, the EPA is proposing
approaches in the form of mass- and rate-based trading options that
provide flexibility in implementing emission standards for a state's
affected EGUs. Both proposed approaches to the federal plan would
require affected EGUs to meet emission standards set using the
CO2 emission performance rates in the EGs. The federal plan
will achieve the same levels of emissions performance as required of
state plans under the EGs. The EPA will promulgate a final federal plan
for only the affected EGUs in states that the EPA determines did not
submit an approvable plan.
At the same time, these two proposed options offer states model
trading rules that the states can follow in developing their own plans
in order to capitalize on the flexibility built into the final EGs.
Thus, this document proposes four discrete actions: (1) A rate-based
federal plan for each state with affected EGUs; (2) a mass-based
federal plan for each state with affected EGUs; (3) a rate-based model
trading rule for potential use by any state; and (4) a mass-based model
trading rule for potential use by any state. The regulatory text of
each federal plan and corresponding model trading rule is identical,
except as indicated otherwise within the text of the model rule (for
instance, the EPA is providing model rule text for states to use
related to the crediting of a broader set of clean energy resources
than is being proposed in the federal plan).
The EPA intends to finalize both the rate-based and mass-based
model trading rules in summer 2016. The EPA will finalize a federal
plan for only a given state in the event that the state does not submit
an approvable plan by the deadlines specified in the final EGs and the
EPA takes action finding that the state has failed to submit a plan, or
disapproving a submitted plan because it does not meet the requirements
of the EGs.\1\ Indeed, states may simply choose to accept a federal
plan for their sources rather than undertake the development of a plan
of their own by not submitting a state plan. Under this proposed rule,
a federal plan promulgated for a particular state would take the form
of either the mass-based model trading rule or the rate-based model
trading rule. The EPA currently intends to finalize a single approach
(i.e., either the mass-based or rate-based approach) for every state in
which it promulgates a federal plan, given the benefits of a broad
trading program, as discussed in
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section I.B of this preamble. We invite comment on which approach,
i.e., either mass-based or rate-based trading, should be selected if we
opt to finalize a single approach.
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\1\ For simplicity, at times this document may refer to the co-
proposed federal plans as ``the federal plan.'' (It may refer to the
model trading rules in the singular as well.) Even though the
singular is used, this term is meant to encompass both the rate-
based approach and the mass-based approach. The use of the singular
when referring to this proposed federal plan also is intended to
encompass all state-specific federal plans. In other words, the EPA
intends to finalize ``the federal plan'' as a series of state-
specific ``federal plans.'' This is consistent with the agency's
prior practice in other multi-state trading programs such as the
NOX Budget Trading Program, the Clean Air Interstate Rule
(CAIR), and the Cross-State Air Pollution Rule (CSAPR), where a
single rule promulgated multiple FIPs.
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It is the EPA's intention to give the states as much opportunity as
possible to set their own course for carrying out the EGs. Even where a
federal plan is put in place for a particular state, that state will
still be able to submit a plan, which, upon approval, will allow the
state and its sources to exit the federal plan. In addition, as
discussed in section VI.A of this preamble, states may take delegation
of administrative aspects of the federal plan in order to become the
primary implementers. And as discussed in sections V.E and VII.A of
this preamble, states may submit partial state plans in order to take
over the implementation of a portion of a federal plan. For instance,
in a mass-based trading program, the agency proposes to allow states to
submit partial state plans to replace the federal plan allowance-
distribution provisions with their own allowance-distribution
provisions, similar to the approach we have taken in prior trading
programs. Finally, even in states in which the affected EGUs are
operating under a federal plan, the agency recognizes that states may
adopt complementary measures outside of CAA programming to facilitate
compliance and lower costs that could benefit power generators and
consumers, directly or indirectly.
A state program that adheres to the model trading rule provisions
specified in this rulemaking would be presumptively approvable. States
may submit means of meeting the EGs' requirements that differ from the
model trading rule provisions, so long as the state demonstrates to the
EPA's satisfaction in the state plan submittal that such alternative
means of addressing requirements are at least as stringent as the
presumptively approvable approach described here.\2\ Additionally,
there are stand-alone portions of the model trading rules, such as the
evaluation, measurement, and verification (EM&V) procedures, that would
be approvable even if a state adopted an approach that differs from the
federal plan. The model trading rules serve as a mechanism to
facilitate larger trading markets since consistency with the federal
plan allows trading across both the state and federal programs. The EPA
expects a larger trading region is likely to result in lower overall
costs. These and other aspects of the model trading rules and federal
plan provide additional support for this rule as proposed. Thus, the
proposed rule would ensure that congressionally mandated emission
standards under authority of section 111 of the CAA are implemented,
either by the states in the first instance, or by the EPA where needed.
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\2\ For example, in the context of a mass- or rate-based trading
program, a state may submit a plan with alternative components other
than those described, so long as the program includes each of the
requirements and the state satisfactorily demonstrates in the state
plan submittal that such alternative means of addressing the
requirements are as stringent as the presumptively approvable
approach as described, and therefore provide for the implementation
of the state plan's emission standards.
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The agency is proposing a finding that it is necessary or
appropriate to implement a CAA section 111(d) federal plan for the
affected EGUs located in Indian country. CO2 emission
performance rates for these facilities were finalized in the EGs.
Tribes generally may seek ``treatment as a state'' (TAS) and submit a
tribal plan to implement CAA programs, including programs under CAA
section 111(d), and this proposed finding does not preclude tribes from
doing that. However, tribes are not subject to the deadlines applicable
to state action under the EGs and in the absence of a federal plan,
CO2 emissions from these EGUs could go unregulated.
Therefore, as discussed in section VI.D of this preamble, we are
proposing a necessary or appropriate finding.
This document also proposes certain enhancements to the process and
timing for state submittals and EPA action in the CAA section 111(d)
framework regulations of 40 CFR part 60, subpart B (these proposals are
not a part of the federal plan or model trading rules). These changes,
if finalized, would be applicable under the Clean Power Plan and other
CAA section 111(d) rules. These changes clarify the availability of
certain procedural mechanisms similar to those available under CAA
section 110 (such as calls for plan revisions and the availability of
``conditional approvals,'' etc.). They also extend the deadlines for
EPA action, in part to conform with the timelines in the EGs. These
changes do not alter the timelines for state action under the EGs and
do not alter the submission requirements established in the EGs.
Finally, the agency proposes to clarify and request comment on an
interpretive issue raised in the Clean Power Plan proposal regarding
whether a reconstruction or modification that is subject to a CAA
section 111(b) standard moves an existing source out of a CAA section
111(d) program. These proposed changes are discussed in section VII of
this preamble. The agency intends to finalize these changes earlier
than the finalization of the model trading rules.
In proposing a federal plan, the EPA considered a variety of
potential impacts that its action might have on the environment, on
businesses, particularly in the energy sector, and on the reliability
of the electrical grid. The agency gave extensive consideration to
impacts on vulnerable communities, particularly low-income communities,
communities of color, and indigenous communities. These considerations
are discussed in sections III, VIII, IX, and X of this preamble.
The agency convened a Small Business Advocacy Review Panel under
the Regulatory Flexibility Act and has completed an Initial Regulatory
Flexibility Analysis (IRFA). Various recommendations from the Panel are
found reflected throughout this proposal. In section X of this
preamble, the agency explains how it has conducted or intends to
conduct all other statutory or executive order (EO) reviews that apply
to this proposed action. The EPA also explains in this document how it
proposes to take into consideration the ``remaining useful lives'' of
affected EGUs in the design of the proposed federal plan, as discussed
below in section III.G of this preamble.
The agency considered the impacts this action could have on the
electricity grid and developed options for compliance that are cost-
effective and that provide substantial flexibility for the affected
EGUs that will accommodate the parties charged with maintaining the
reliability of electrical power. A key feature of the proposed federal
plan and model trading rule is that the flexibility inherent in both of
the two approaches (i.e., rate-based or mass-based trading) enables the
EPA and the states to create a level of flexibility for affected EGUs
that allows owners and operators to determine the best way to achieve
emission reductions, at the EGU-, state-, multi-state-, regional-, or
national level. As a result, compliance strategies can mirror, or be
integrated with, the ongoing operations of the current electricity grid
as it continues to serve its primary critical function of ensuring an
uninterrupted supply of affordable and reliable electricity. This
flexibility is especially valuable whenever the need to address
specific reliability concerns arises. It allows owners and operators of
reliability-critical EGUs to continue to meet their compliance
obligations while operating to maintain electric reliability.
The EPA outlined and initiated the Clean Energy Incentive Program
(CEIP) in the final EGs (see section VIII of the final EGs). The
program is designed to
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incentivize investment in certain types of renewable energy (RE)
projects, as well as demand-side energy efficiency (EE) projects
implemented in low-income communities, that generate MWh or reduce end-
use energy demand during 2020 and/or 2021. The EPA proposes to apply
the CEIP in all states subject to either a rate-based or mass-based
federal plan.
We also reviewed impacts that this action could have on the
environment and the need to ensure environmental integrity of the
program as well as avoid unintended environmental impacts. We took
measures to ensure that the reductions in carbon emissions this plan
will achieve are real, and not just apparent. As in the EGs, in both
the rate- and mass-based approaches, the EPA has incorporated
components to address the concern that the dynamics of either a rate-
or mass-based trading program could incentivize shifting generation
from existing units in ways that would result in more CO2
emissions than would otherwise be expected, or that undermine the
purpose of the CAA section 111(d) program.
We considered whether compliance choices under a federal plan could
lead to an unintended concentration of other air pollutants in certain
overburdened communities, particularly low-income communities and
communities of color. As discussed below, our analysis shows why we do
not expect this to occur at any significant level. In general, as in
the EGs, we anticipate that the federal plan will result in overall
reductions of co-pollutants, in addition to reductions in
CO2, with corresponding co-benefits to public health. We
also reviewed whether this action could trigger an obligation to
consult with other agencies responsible for implementing the Endangered
Species Act, and propose to conclude that it will not.
In the final EGs, the EPA emphasized the importance of state
actions to ensure that in developing their respective compliance plans
the states addressed the concerns and priorities of vulnerable
communities. In the process of developing a final federal plan, the EPA
will take actions to address those concerns as well. In addition to the
public hearings that the EPA will be holding for all members of the
American public on this proposed rulemaking, we will also be conducting
a national webinar and outreach meeting(s) in all ten regions on this
proposed rulemaking for communities. The goal of these outreach
activities is to provide communities with the information they need to
understand how the proposed rulemaking will potentially impact their
respective communities. At the same time, this information will be
useful in helping communities engage the EPA during our comment period,
as well as with their states during the state plan development process.
We will also be providing other outreach and support activities for
vulnerable communities, which are outlined in the community and
environmental justice (EJ) considerations in section IX.B of this
preamble.
B. Organization and Approach for This Proposed Rule
In this action, the EPA is proposing a federal plan to implement
the Clean Power Plan EGs for affected fossil fuel-fired EGUs operating
in states that do not have approved state plans. Specifically, the EPA
is co-proposing two different approaches to a federal plan to implement
the Clean Power Plan EGs--a rate-based trading approach and a mass-
based trading approach. While establishing emission standards for
affected EGUs that would be directly enforceable against the owners and
operators of the source, both approaches would grant EGUs substantial
flexibility in meeting their compliance obligations. For this reason,
among others, these proposed approaches also serve as two proposed
model trading rules that states may adopt or tailor in designing their
own plans.
The EGs provide that states have until September 6, 2016 (or upon
making an initial submittal, until September 6, 2018) to submit state
plans, and the EPA does not intend to finalize and implement the
federal plan for any states prior to the agency's action of determining
a failure to submit a state plan or disapproving a state plan. At the
same time, in order to support states' consideration of adoption of one
of the model trading rules as an approvable state plan, the agency
intends to finalize either or both model rule options presented in this
proposed rule by summer 2016, prior to the deadline for state
submittals.
The EPA currently intends to finalize a single approach--i.e.,
either a rate-based or a mass-based approach--in all promulgated
federal plans for particular states in order to enhance the consistency
of the federal trading program, achieve economies of scale through a
single, broad trading program, ensure efficient administration of the
program, and simplify compliance planning for affected EGUs. The EPA
recognizes that the mass-based trading approach would be more
straightforward to implement compared to the rate-based trading
approach, both for industry and for the implementing agency. The EPA,
industry, and many state agencies have extensive knowledge of and
experience with mass-based trading programs. The EPA has more than two
decades of experience implementing federally-administered mass-based
emissions budget trading programs including the Acid Rain Program (ARP)
sulfur dioxide (SO2) trading program, the Nitrogen Oxides
(NOX) Budget Trading Program, CAIR, and CSAPR. The tracking
system infrastructure exists and is proven effective for implementing
such programs. The EPA requests comment on which approach--mass-based
or rate-based trading--is preferred for the federal plan. Some
stakeholders have suggested there could be utility in the availability
of both approaches based on the unique circumstances of particular
states. The EPA recognizes that it remains potentially possible to
finalize a different approach to a federal plan in some circumstances,
but believes that in general, and consistent with prior federal trading
programs such as CSAPR, creating a single, broad program has the most
advantages.
The stringency of the proposed federal plan is the same as the
CO2 emission performance rates established for affected EGUs
in the EGs. As explained in the final EGs, the EPA determined the
CO2 emission performance rates through the application of
the BSER. In the EGs, the EPA has taken final action on the BSER for
CO2 emissions from existing fossil fuel-fired EGUs. Any
comments on this proposed rule relating to the BSER, its stringency,
rationale, or legal basis, will not be considered as, by definition,
they will be beyond the scope of this action.\3\
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\3\ The agency recognizes that the ``remaining useful lives'' of
facilities subject to a CAA section 111(d) federal plan is a factor
that it must consider at the time it implements the federal plan.
This factor, and how the agency proposes to consider it, is
discussed in section III.G of this preamble below.
---------------------------------------------------------------------------
1. The Rate-Based Approach
In the first approach, the EPA would implement a rate-based
emissions trading program. In a rate-based program, affected EGUs must
meet an emission standard, derived from the EGs, expressed as a rate of
pounds of CO2 per megawatt hour (lbs/MWh). If sources emit
above their assigned rate, they must acquire a sufficient number of
emission rate credits (ERC), each representing a zero-emitting megawatt
hour (MWh), to bring their rate of emissions into compliance. Emission
rate credits (ERCs) may be generated by affected EGUs or by other
entities that supply zero- or low-emitting electricity resources to the
grid through an approval and recognition process that
[[Page 64971]]
the EPA will administer. ERCs may be bought and sold, or banked for use
in later years. The rate-based approach is explained in greater detail
in section IV of this preamble.
2. The Mass-Based Approach
The second approach to a federal plan that the EPA is proposing in
this action is a mass-based trading program. In a mass-based program,
the EPA would create a state emissions budget equal to the total tons
of CO2 allowed to be emitted by the affected EGUs in each
state, consistent with the mass goals established in the EGs. The EPA
would initially distribute the allowances within each state budget--
less three proposed allowance set-asides--to the affected EGUs based on
their historical generation. Allowances may then be transferred,
bought, and sold on the open market, or banked for future use. The
compliance obligation on each of the affected EGUs is to surrender the
number of allowances sufficient to cover the EGU's respective emissions
at the end of a given compliance period. The EPA is also proposing as a
part of the mass-based approach three set-asides of allowances: (1) For
a Clean Energy Incentive Program; (2) to support renewable energy (RE)
projects; and (3) to allocate allowances based on an updating
measurement of affected-EGU generation. The EPA is also proposing that
a jurisdiction may choose to replace the federal plan allocation
provisions with its own allowance allocation provisions. The mass-based
approach is explained in greater detail in section V of this preamble.
3. Other Proposed Actions
The EPA is proposing in this action a finding that it is necessary
or appropriate to regulate affected EGUs in certain parts of Indian
country via a federal plan. This is discussed in section VI.D of this
preamble.
In this action, the EPA is also proposing a number of changes to
the framework CAA section 111(d) regulations of 40 CFR part 60, subpart
B. These changes generally are intended to provide enhancements to the
process for state plan submissions and the timing of EPA actions
related to state plans and the federal plan. Specifically, the EPA
proposes six changes, to include: (1) Partial approval/disapproval
mechanisms similar to CAA section 110(k)(3); (2) a conditional approval
mechanism similar to CAA section 110(k)(4); (3) a mechanism for the EPA
to make calls for plan revisions similar to the ``SIP-call'' provisions
of CAA section 110(k)(5); (4) an error correction mechanism similar to
CAA section 110(k)(6); (5) completeness criteria and a process for
determining completeness of state plans and submittals similar to CAA
section 110(k)(1) and (2); and (6) updates to the deadlines for EPA
action. These proposed changes are explained in greater detail in
section VII of this preamble. They are not a component of the proposed
federal plan, or changes in the EGs. If these changes are finalized,
they will be applicable to other CAA section 111(d) rules. The EPA
intends to finalize these changes earlier than the finalization of the
model trading rules.
C. Who does the Proposed Action apply to?
Regulated Entities. Existing fossil fuel-fired EGUs (or affected
EGUs) covered by the final Clean Power Plan that are located in a state
that does not have an EPA-approved state plan are potentially subject
to this proposed action. Affected EGUs are those that were in
operation, or had commenced construction, on or before January 8,
2014.\4\ The following North American Industrial Classification System
(NAICS) codes apply as shown in Table 1 of this preamble:
---------------------------------------------------------------------------
\4\ An affected EGU is any fossil fuel-fired EGU that was in
operation or had commenced construction as of January 8, 2014, and
is therefore an ``existing source'' for purposes of CAA section 111,
but in all other respects would meet the applicability criteria for
coverage under the GHG standards for new fossil fuel-fired EGUs.
Table 1--Examples of Potentially Regulated Entities \a\
------------------------------------------------------------------------
Examples of potentially
Category NAICS code regulated entities
------------------------------------------------------------------------
Industry....................... 221112 Fossil fuel electric
power generating
units.
State/Local Government......... \b\ 221112 Fossil fuel electric
power generating units
owned by
municipalities.
------------------------------------------------------------------------
\a\ Includes NAICS categories for source categories that own and operate
electric power generating units (includes boilers and stationary
combined cycle combustion turbines).
\b\ State or local government-owned and operated establishments are
classified according to the activity in which they are engaged.
This table is not intended to be exhaustive, but rather provides a
general guide for identifying entities likely to be affected by the
proposed action. Whether an affected EGU is affected by this action is
described in the applicability criteria in 40 CFR 60.5845 and 60.5850
of subpart UUUU. Questions regarding the applicability of this action
to a particular entity should be directed to the person listed in the
preceding FOR FURTHER INFORMATION CONTACT section of this preamble.
1. What is an affected electric utility generating unit?
For the federal plan, the definition of an affected EGU is
identical to the definition in the final Clean Power Plan.
Additionally, the applicability of the federal plan is consistent with
the EGs, where an affected EGU subject to the federal plan is any steam
generating unit (SGU), integrated gasification combined cycle (IGCC),
or stationary combustion turbine (SCT) that was in operation or had
commenced construction as of January 8, 2014,\5\ and that meets certain
criteria, which differ depending on the type of unit. The criteria to
be an affected EGU are as follows: A unit, if it is a SGU or IGCC, must
serve a generator capable of selling greater than 25 MW (Megawatts) to
a utility power distribution system, have a base load rating greater
than 260 GJ/h (250 MMBtu/h) heat input of fossil fuel (either alone or
in combination with any other fuel), and historically have supplied
more than \1/3\ of its potential electric output and 219,000 MWh as
net-electric sales on any 3 calendar year basis. If a unit is a SCC,
the unit must meet the definition of a combined cycle or combined heat
and power (CHP) combustion turbine, serve a generator capable of
selling greater than 25 MW to a utility power distribution system, have
a base load rating of greater than 260 GJ/h (250 MMBtu/h), and
historically have combusted more than 90 percent natural gas on a heat
input basis on an annual basis.
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\5\ January 8, 2014 is the date the proposed GHG standards of
performance for new fossil fuel-fired EGUs were published in the
Federal Register (79 FR 1430).
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[[Page 64972]]
2. How To Determine if a Unit Is Covered By an Approved and Effective
State Plan
Section 111(d) of the CAA, as amended, 42 U.S.C. 7411(d),
authorizes the EPA to develop and implement a federal plan for affected
EGUs upon the EPA's action finding a failure to submit or disapproving
a state plan.\6\ The affected EGUs covered in EPA-approved state plans
are not subject to the federal plan. If the federal plan has been put
in place in a state, but is later replaced by an EPA-approved state
plan, the affected EGUs would become subject to the state plan as of
the effective date specified in a Federal Register notice regarding the
EPA's approval of the state plan. The EPA is not expecting state plans
to be submitted by the states that submit negative declarations.
However, in the event that there are later determined to be affected
EGUs located in these states, the final federal plan would be applied
to such EGUs through a future action. Part 62 of title 40 of the CFR
identifies the status of approval and promulgation of CAA section
111(d) state plans for designated facilities in each state. Recognizing
the urgent need for actions to reduce GHG emissions, and in accordance
with the Presidential Memorandum,\7\ as well as the benefit of
providing states with model trading rule options to consider as they
prepare their state plans, the EPA is proposing this rulemaking
concurrently with the Administrator's signing and promulgation of the
final Clean Power Plan EGs. 40 CFR part 62 is updated only once per
year. Thus, if 40 CFR part 62 does not indicate that your state has an
approved and effective plan after the compliance date has passed
requiring state plan submittal, you should contact your state
environmental agency's Air Director or your EPA Regional Office (see
Table 2 in section II.B of this preamble) to determine if approval
occurred since publication of the most recent version of 40 CFR part
62.
---------------------------------------------------------------------------
\6\ In this Preamble, the term ``state'' generally encompasses
the 50 states and the District of Columbia, U.S. territories, and
any Indian Tribe that has been approved by the EPA pursuant to 40
CFR 49.9 as eligible to develop and implement a CAA section 111(d)
plan. However, the federal plan is not proposed for affected EGUs in
certain states or territories where the EGs did not finalize
emission performance rates.
\7\ Presidential Memorandum--Power Sector Carbon Pollution
Standards, June 25, 2013. http://www.whitehouse.gov/the-press-office/2013/06/25/presidential-memorandum-power-sector-carbon-pollution-standards.
---------------------------------------------------------------------------
D. What should I consider as I prepare my comments?
Do not submit information that you consider to be CBI
electronically through http://www.regulations.gov or email. Send or
deliver information identified as CBI to only the following address:
OAQPS Document Control Officer (Room C404-02), U.S. EPA, Research
Triangle Park, NC 27711, Attention Docket ID No. EPA-HQ-OAR-2015-0199.
Clearly mark the part or all of the information that you claim to be
CBI. For CBI on a disk or CD-ROM that you mail to the 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 marked as CBI will not be disclosed except
in accordance with procedures set forth in 40 CFR part 2.
If you have any questions about CBI or the procedures for claiming
CBI, please consult the person identified in the FOR FURTHER
INFORMATION CONTACT section of this preamble.
Docket. The docket number for the proposed action (40 CFR part 62,
subpart MMM) is Docket ID No. EPA-HQ-OAR-2015-0199.
World Wide Web (WWW). In addition to being available in the docket,
an electronic copy of the proposed action is available on the Internet
through the EPA's Technology Transfer Network (TTN) Web site, a forum
for information and technology exchange in various areas of air
pollution control. Following signature by the EPA Administrator, the
EPA will post a copy of the proposed action at http://www2.epa.gov/cleanpowerplan/regulatory-actions#regulations. Following publication in
the Federal Register (FR) the EPA will post the FR version of the
proposed rule and key technical documents on the same Web site.
II. Background Information
A. What is the regulatory development background for this proposed
rule?
On August 3, 2015, the EPA finalized the Clean Power Plan EGs for
existing fossil fuel-fired EGUs (40 CFR part 60, subpart UUUU) under
authority of section 111 of the CAA (79 FR 34950). The Guidelines apply
to existing fossil fuel-fired EGUs, i.e., those that were in operation
or had commenced construction before January 8, 2014. States with
existing EGUs subject to the EGs are required to submit to the EPA by
September 6, 2016, a state plan that implements the EGs. States may
also make initial plan submittals in lieu of a complete state plan, in
which case extensions will be granted until September 6, 2018 (40 CFR
part 60, subpart UUUU).\8\ As discussed in section VI.D of this
preamble, Indian Tribes may, but are not required to, submit tribal
plans. Once the EPA finds that a state has failed to submit a plan, or
disapproves a state plan,\9\ section 111 of the CAA and 40 CFR 60.27
require the EPA to develop, implement, and enforce a federal plan for
existing EGUs located in that state. In addition, CAA section 301(d)(2)
authorizes the Administrator to treat an Indian Tribe in the same
manner as a state for this EGU requirement. See 40 CFR 49.3; see also
``Indian Tribes: Air Quality Planning and Management,'' hereafter
``Tribal Authority Rule,'' (63 FR 7254, February 12, 1998). As
discussed in section VI.D of this preamble, the agency in this action
is proposing a necessary or appropriate finding for the affected EGUs
in several areas of Indian country and is proposing the federal plan
for these affected EGUs.
---------------------------------------------------------------------------
\8\ See section VII of this preamble for additional information
on proposed changes to 40 CFR 60.27 to provide enhancements and
flexibilities to the agency's process for review and action on state
plans and promulgation of federal plans.
\9\ If a state has submitted a complete plan, then the EPA will
go through a public notice and comment process to fully or partially
approve or disapprove the state plan.
---------------------------------------------------------------------------
The agency believes it is appropriate to propose the federal plan
at this time for any states that may ultimately be found to have failed
to submit a plan, or had their plan disapproved by the EPA. For some
states in this situation, the federal plan may be no more than an
interim measure to ensure that congressionally mandated emission
standards under authority of section 111 of the CAA are implemented
until they can get an approved plan in place. Other states may choose
to rely on the federal plan and would not need to develop their own
plan. This proposal also serves as two proposed model trading rules
which states can adopt or tailor for adoption as their state plan. The
role of the model rules is discussed in section II.B of this preamble.
In this proposal, the EPA is soliciting public comment only on the
proposed approaches for a federal plan and model trading rule for the
implementation of the Clean Power Plan EGs. Comments on the underlying
Clean Power Plan rule will be considered outside the scope for this
proposed rule.
B. What is the purpose of this proposed rule?
The purpose of this action is two-fold: (1) To co-propose two
approaches to a
[[Page 64973]]
federal plan to implement the Clean Power Plan EGs for affected EGUs
operating in any state lacking an approved state plan by the relevant
deadlines; and (2) to propose these same approaches as model trading
rules for states to consider in developing their own plans.
1. Federal Plan
Section 111 of the CAA and 40 CFR 60.27 require the EPA to develop,
implement and enforce a federal plan to cover existing EGUs located in
states that do not have an approved plan. Section 111(d) of the CAA
relies upon states as the preferred implementers of EGs for existing
EGUs. States with affected EGUs are to submit state plans or make
initial submittals to the EPA by September 6, 2016 pursuant to the
EGs.\10\ States without any existing EGUs are directed to submit to the
Administrator a letter of negative declaration certifying that there
are no affected EGUs in the state. No plan is required for states that
do not have any affected EGUs. Affected EGUs located in states that
mistakenly submit a letter of negative declaration will become subject
to the federal plan until a state plan covering those EGUs becomes
approved. The EPA intends to finalize the federal plan only for those
states that the EPA finds failed to submit plans or whose plans the EPA
disapproves. For more information on the timing and mechanics of EPA
action on state plans and finalization of this federal plan, see
section II.D of this preamble below.
---------------------------------------------------------------------------
\10\ States may request extensions of up to two years as part of
a complete initial CAA section 111(d) submission.
---------------------------------------------------------------------------
2. Model Trading Rule
The EPA is also proposing the federal plan approaches as two forms
of a model trading rule (mass-based and rate-based), which states can
adopt or tailor for implementation as a state plan under the EGs. The
EPA intends to finalize the model trading rules earlier than it
promulgates a federal plan for a state. When the EPA finalizes one or
both of its proposed approaches as a final model trading rule, and a
state adopts a final model trading rule in its entirety as its state
plan, it would be presumptively approvable.
The EPA has designed these rules so that they meet the requirements
of the final EGs. If one of the model rules is adopted by a state
without any change, it would be presumptively approvable. We use the
term ``presumptively'' in recognition that a state plan submission must
be accompanied by other materials in addition to the regulatory
provisions. These requirements are set forth in the final Clean Power
Plan and framework regulations of 40 CFR part 60, subpart B. For
instance, they include a formal letter of submittal from the Governor
or his or her designee, evidence that the rule has been adopted into
state law and that the state has necessary legal authority to implement
and enforce the rule, and evidence that procedural requirements,
including public participation under 40 CFR 60.23, have been met.
In further support of state use of the model rules, we are drafting
the model trading rule so that it can be adopted or incorporated by
reference with a minimum of changes that would be necessary to make the
rule appropriate for use by states. This way, a state may incorporate
by reference the model rule as the state plan, or as the backstop to a
state measures plan with few if any adjustments. States may make
changes to the model trading rule, so long as they still meet the
requirements of the EGs. If the state chooses to tailor or modify the
model trading rule such as by expanding the scope of eligibility of
projects that may generate ERCs in a rate-based trading program, the
EPA may still approve the plan, but the EPA would conduct appropriate
review of such provisions for consistency with the EGs and the state
would have to demonstrate to the EPA's satisfaction that its
alternative provisions are as stringent as the presumptively approvable
approach described. We note here, and in the regulatory text of the
model trading rule, that the scope of eligibility of proposed ``ERC
resources'' for the federal plan is different than the scope of
eligibility provided for in the model rule. Thus, all of the language
and provisions in the regulatory text relevant to these other ERC
resources is relevant only to the proposed model trading rule and not
to the federal plan as such (i.e., those ERC resources discussed in
section IV.C.3 of this preamble are applicable to the model rule and
only metered RE and applicable nuclear are applicable to the federal
plan).
The EPA's approval of a state plan, including a plan that adopts
the model trading rule, will be the result of an independent notice-
and-comment rulemaking process. Without prejudging the outcome of that
process, the EPA recognizes that it may be able to approve or
``conditionally approve'' state plans that are substantially similar,
but not identical to, the final model trading rules. Ultimately, state
plans must meet the requirements of the EGs for approvability. Thus, a
conditional approval would be based on a condition that the state take
such actions as may be necessary by a date certain to meet the
requirements of the EGs. (The EPA is proposing to explicitly provide
for conditional approvals in the CAA section 111(d) framework
regulations. See section VII.B of this preamble.)
In accordance with the EGs, the process for review and approval (or
disapproval) of state plans, whether based on the model trading rules
or otherwise, would occur once the states have made their submissions
by September 6, 2016. As provided in the EGs, states have the option of
not submitting a full state plan, but rather making an initial
submittal, in order to obtain an extension of 2 years before submitting
a full state plan for EPA approval. It could be beneficial for
coordination purposes if a state that is interested in adopting one of
the model trading rules but intends to make an initial submittal next
year were to indicate which model trading rule they intend to adopt.
This is not an additional requirement beyond what the EGs require for
initial submittals, however.
The EPA strongly encourages states to consider adopting one of the
model trading rules, which are designed to be referenced by states in
their rulemakings. Use of the model trading rules by states would help
to ensure consistency between and among the state programs, which is
useful for the potential operation of a broad trading program that
spans multi-state regions or operates on a national scale. As discussed
at length in the EGs, EGUs operate less as individual, isolated
entities and more as multiple components of a large interconnected
system designed to integrate a range of functions that ensure an
uninterrupted supply of affordable and reliable electricity while also,
for the past several decades, maintaining compliance with air pollution
control programs. Since, as a practical matter under both the EGs and
any federal plan, emission reductions must occur at the affected EGUs,
a broad-scale emissions trading program would be particularly effective
in allowing EGUs to operate in a way that achieves pollution control
without disturbing the overall system of which they are a part and the
critical functions that this system performs. In addition, consistency
of requirements benefits the affected EGUs, as well as the states and
the EPA in their roles as administrators and implementers of a trading
program. States of course remain free to develop a plan of their own
choosing to submit to the EPA for approval following the
[[Page 64974]]
criteria set out in the final Clean Power Plan EGs.
The EPA believes there are compelling policy reasons that support
the provision of a proposed model trading rule at this time. The EPA
has heard from multiple stakeholders and in public comments submitted
on the proposed EGs that there is a strong interest in seeing a model
state plan or trading rule prior to the deadline for state submittals
under the EGs. According to these stakeholders, model rules can provide
predictability for planning purposes, both among states and affected
EGUs. In addition, some states have indicated that they may prefer to
rely on a federal plan, either temporarily or permanently, rather than
develop a plan of their own. This proposal of a model trading rule
addresses these policy interests.
The approach of proposing model trading rules that are identical in
all key respects to proposed federal plans that may be promulgated
later, is consistent with prior CAA section 111(d) and CAA section 110
rulemakings. For example, the NOX state implementation plan
(SIP) Call model rule at 40 CFR part 96 (63 FR 57356; October 27, 1998)
was identical in all meaningful respects with the Federal
NOX Budget Trading Program at 40 CFR part 97 (65 FR 2674;
January 18, 2000). And the CAIR model rule in 40 CFR part 96 (70 FR
25339; May 12, 2005) was identical in all meaningful respects with the
federal CAIR in 40 CFR part 97 (71 FR 25396; April 28, 2006).\11\ While
these identical programs for model rules and Federal Implementation
Plans (FIPs) were finalized in separate parts of the CFR, the EPA does
not see any reason that it could not just as easily propose the federal
plan as the model trading rule in the same section of the CFR.\12\ If a
federal plan were to be finalized for a given state at a later time,
this would be reflected in 40 CFR part 62 by cross-reference, along
with any modifications or adjustments that may be appropriate at the
time of actual promulgation of a federal plan.
---------------------------------------------------------------------------
\11\ We also note that historically under the CAA section
111(d)/129 rules, the content of EGs and their corresponding federal
plans have had significant overlap.
\12\ We propose to include a note in the regulatory text
explaining where aspects of the proposed subpart relevant to states
as part of the model trading rule are not applicable.
Table 2--Regional Office Contacts
----------------------------------------------------------------------------------------------------------------
Region Regional contact Phone States and protectorates
----------------------------------------------------------------------------------------------------------------
Region I............................. Shutsu Wong, 617-918-1078 Connecticut, Massachusetts,
[email protected]. Maine, New Hampshire, Rhode
Island, Vermont.
Region II............................ Gavin Lau, 212-637-3708 New York, New Jersey, Puerto
[email protected]. Rico, Virgin Islands.
Region III........................... Mike Gordon, 215-814-2039 Virginia, Delaware, District
[email protected]. of Columbia, Maryland,
Pennsylvania, West
Virginia.
Region IV............................ Ken Mitchell, 404-562-9065 Florida, Georgia, North
[email protected]. Carolina, Alabama,
Kentucky, Mississippi,
South Carolina, Tennessee.
Region V............................. Alexis Cain, 312-886-7018 Minnesota, Wisconsin,
[email protected]. Illinois, Indiana,
Michigan, Ohio.
Region VI............................ Rob Lawrence, 214-665-6580 Arkansas, Louisiana, New
[email protected]. Mexico, Oklahoma, Texas.
Region VII........................... Ward Burns, 913-551-7960 Iowa, Kansas, Missouri,
[email protected]. Nebraska.
Region VIII.......................... Laura Farris, 303-312-6388 Colorado, Montana, North
[email protected]. Dakota, South Dakota, Utah,
Wyoming.
Region IX............................ Ray Saracino, 415-972-3361 Arizona, California, Hawaii,
[email protected]. Nevada, American Samoa,
Guam, Northern Mariana
Islands.
Region X............................. Dan Brown, 503-326-6823 Alaska, Idaho, Oregon,
[email protected]. Washington.
----------------------------------------------------------------------------------------------------------------
C. Legal Authority
Section 111(d)(2) of the CAA, 42 U.S.C. 7411(d)(2) provides the EPA
the same authority to prescribe a plan for a state in cases where the
state fails to submit a satisfactory plan as the agency would have
under CAA section 110(c) in the case of failure to submit an
implementation plan. In addition, the EPA has authority under CAA
section 111(d)(1) to prescribe regulations that establish procedures
similar to CAA section 110 with respect to the submission of state
plans, and the EPA also has general rulemaking authority as necessary
to implement the CAA under CAA section 301. A federal plan under CAA
section 111(d) applies, implements and enforces standards of
performance for affected EGUs. Under the Clean Power Plan EGs, state
plans will be due on September 6, 2016, but states are also allowed to
seek a 2-year extension for a final plan submittal, upon a satisfactory
initial plan submittal by the same deadline. See 40 CFR 60.5755,
60.5760(b). If a state does not submit a final state plan or initial
plan submittal,\13\ or if either a final state plan or an initial plan
submittal does not meet the requirements of the EG, the agency will
take the appropriate steps to finalize and implement a federal plan for
that state's EGUs.
---------------------------------------------------------------------------
\13\ Indeed, states may simply choose to accept a federal plan
in lieu of undertaking to develop a state plan at all. While the
statute uses the phrase ``fails to submit a satisfactory plan,'' the
EPA does not believe this should carry any pejorative connotation.
While Congress identified states and local governments as having
``primary responsibility'' for air pollution prevention and control,
CAA section 101(a)(3), states are in no way penalized for not
submitting a plan under CAA section 111(d). Rather, the EPA steps
into the shoes of the state to carry out the CAA section 111(d)
program in its stead. To the extent states may be interested in
accepting a federal plan, the EPA would be interested in hearing
that through the comment process on this proposal.
---------------------------------------------------------------------------
Further, states will remain free, and indeed are strongly
encouraged, to submit an approvable state plan even after promulgation
of the federal plan for their jurisdictions. The EPA will withdraw the
federal plan for a state when that state submits, and the EPA approves,
a final plan. See 40 CFR 60.5720.
D. Timing of EPA Actions on the Model Trading Rules, Federal Plan, and
Other Proposed Actions
This action co-proposes two approaches to the federal plan, both of
which also constitute proposed model trading rules that states could
adopt as state plans for EPA approval. The EPA currently intends to
finalize one or both of the model trading rules by next summer so that
they may be available to states as soon as possible to help inform
their state plan development efforts prior to the initial submittal
deadline of September 6, 2016, and 2 years before the states' final
plan deadline of September 6, 2018.\14\ If the EPA
[[Page 64975]]
finalizes the model trading rules in that timeframe, the only direct
consequence will be to provide the states certainty as to one or two
particular approaches to the design of their state plan that the EPA
will approve if adopted in full. The finalization of a model trading
rule will not constitute a final action with respect to a federal plan
for the affected EGUs in any state. Rather, the proposed federal plan
will remain just that, a proposal. The EPA will promulgate a final
federal plan for any state only after it has made a finding on a
state's failure to submit a plan, or fully or partially disapproved a
submitted state plan. The EPA will go through a public notice and
comment process before disapproving a submitted and complete state
plan, in whole or part. The EPA invites comments on this staged
approach to finalizing one or more model trading rules on the one hand
(which we currently intend to do in summer 2016), and finalizing
federal plans on the other (which we currently intend to do state-by-
state upon our taking predicate action on states' plans).
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\14\ We anticipate that the model rules' text could be finalized
either in a new subpart or subparts of 40 CFR part 62 of title 40 of
the CFR as proposed, or in a final document that is not published in
the CFR.
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In this action, the EPA is also proposing enhancements to the
process for agency action on state submittals and promulgation of a
federal plan under CAA section 111(d). For more detailed discussion of
these changes, see section VII of this preamble. This aspect of this
proposal is separate from the federal plan and the model trading rules.
The EPA intends to finalize these changes on a timeline earlier than
both a model trading rule and the federal plan.
Under the framework regulations as proposed to be amended, see
section VII below, and the final EGs, at 40 CFR 60.27 and 60.5715 and
5760, respectively, the initial timelines for EPA action on state
submittals and, potentially, the promulgation of a federal plan will be
as follows: The EPA will have 12 months from the date of a state's
submission to approve or disapprove that state's plan. The EPA will
have 12 months from the date of its action on a state submission to
promulgate the federal plan for the EGUs in that state. Under the
completeness-criteria process proposed to be added to 40 CFR 60.27, see
section VII.E below, the EPA would have 6 months from the deadline for
a state's submission to notify a state that its submittal does not meet
completeness criteria and constitutes a failure to submit a plan. In
the case of initial submittals under 40 CFR 60.5765, the EPA will have
90 days from the date the EPA received the initial submittal to notify
a state that its initial submittal does not meet the requirements of 40
CFR 60.5765(a). As with state plans, the EPA will have 12 months to
promulgate a federal plan from the date of its finding that a state
failed to submit a complete and approvable initial submittal.
(Formally, such a finding would be that the state failed to submit a
state plan.)
The timeframes stated in the previous paragraph reflect the maximum
time allowed for EPA action. We note that under CAA section 111(d)(2)
and CAA section 110(c), the EPA may promulgate a final federal plan for
a state immediately upon making a finding of failure to submit a state
plan or initial submittal, or upon making a finding of final
disapproval of a state plan. Congress gave the EPA authority in CAA
section 111(d)(2), as it did in CAA section 110(c), to promulgate a
federal plan at any time after it disapproves or finds a failure to
submit a state plan. The Supreme Court has recognized that under this
authority, the EPA may promulgate a FIP ``at any time'' within the 2-
year limit of CAA section 110(c) ``that begins the moment EPA
determines a SIP to be inadequate.'' EME Homer City v. EPA, 134 S. Ct.
1584, 1601 (2014). ``EPA is not obliged to wait two years or postpone
its action even a single day . . . .'' Id. It is essential to implement
plans for the control of emissions of CO2 expeditiously and
avoid unnecessary delay. Among other reasons, this will provide
affected EGUs regulatory certainty and will assist the regulated
entities as well as those authorities with responsibility for ensuring
grid reliability to have as much time as possible to plan for the 2022
compliance start date set in the EGs. Thus, it is reasonable to propose
this federal plan now so that federal plans will be ready to be
promulgated quickly in cases where states have failed to submit a plan
or their plans are found unsatisfactory.
It is the agency's intention to promulgate federal plans promptly
for states who do not submit plans or initial submittals by September
6, 2016. However, the effect of putting the federal plan in place at
that time would ultimately be limited in impact upon states. Because
the EPA would implement the federal plan, its promulgation does not
obligate state officials to take any actions themselves. Further,
states remain free--and the EPA in fact encourages states--to submit
state plans that can replace the federal plan. States can do so in
advance of the beginning of the performance period in 2022, or may
transfer to a state plan after that date. However, in doing so, the
agency and states should be mindful of the goals of regulatory
certainty discussed in the prior paragraph.
Because we are proposing a federal plan that would apply emission
standards to affected EGUs in all states that the agency determines not
to have an approvable plan, the EPA invites comment from all persons
with concerns about or comments on the proposed federal plan as it may
apply in any state, whether or not that state has submitted, or intends
to submit, its own plan on which the EPA has yet to take action.
In this document, the EPA is proposing regulatory text setting out
the substantive provisions for both of the proposed federal plans/model
trading rules. The EPA is not providing specific regulatory text that
would, if finalized, actually promulgate a federal plan for each state
for which this proposed federal plan might be applied.\15\ We currently
envision that this language would be in the form of a new section to
the state-specific subparts of part 62 and would be ministerial in
nature. It would likely provide that the affected EGUs in each such
state are subject to a federal plan and would then cross-reference or
incorporate by reference the substantive provisions of one of the two
subparts proposed in this action (if finalized), along with any
applicable modifications or adjustments as may be necessary, either
based on new information or in response to comments regarding the
application of the federal plan to that particular state. This text may
appear similar to the FIP language found in the final CSAPR rule (76 FR
48208, 48361-78; August 8, 2011).
---------------------------------------------------------------------------
\15\ The minimum contents of a notice of proposed rulemaking
under the CAA are set forth at CAA section 307(d)(3) and 5 U.S.C.
553(b).
---------------------------------------------------------------------------
E. Use of the Model Trading Rule as a Backstop
As discussed in the final EGs, the EPA believes that either a mass-
based or rate-based model trading rule could function well as the
federally enforceable ``backstop'' that the EGs require to be included
in ``state measures'' type state plans.\16\ (The proposed federal plan
does not itself require a ``backstop'' because it relies on an
``emission standards'' approach, rather than a ``state measures''
approach, as delineated in the final EGs.) The conditions and
requirements for the federally enforceable backstop in a state measures
approach are discussed in
[[Page 64976]]
detail in the final EGs. See sections VIII.C.3.b and VIII.C.6.c of the
final EGs. To summarize those provisions, without reopening them for
comment, the federally enforceable backstop must fully achieve the
CO2 emission performance rates or the state's interim and
final CO2 emission goals if the state plan fails to achieve
the intended level of CO2 emission performance. The state
plan submittal must identify the federally enforceable emission
standards for affected EGUs that would be used in the backstop,
demonstrate that those emission standards meet the requirements that
apply in the context of an emission standards approach, identify a
schedule and trigger for implementation of the backstop that is
consistent with the requirements in the EGs, and identify all necessary
state administrative and technical procedures for implementing the
backstop (e.g., how and when the state would notify affected EGUs that
the backstop has been triggered). In addition, the backstop emission
standards must make up for any shortfall in CO2 emission
performance during a prior plan performance period that led to
triggering of the backstop.
---------------------------------------------------------------------------
\16\ We are aware of at least one case in which a court has
upheld the use of a trading program as a backstop to ensure CAA
requirements are met. See WildEarth Guardians v. U.S. EPA, No. 12-
9596 (10th Cir. filed October 21, 2014) (upholding use of backstop
cap-and-trade program under 40 CFR 41.309 of the Regional Haze
Rule).
---------------------------------------------------------------------------
The EGs explicitly recognized that the backstop emission standards
could be based on one of the model trading rules that the EPA is
proposing in this action. As discussed in section II.B of this preamble
above, we are drafting the model trading rule so that it can be adopted
or incorporated by reference with a minimum of changes necessary to
make the rule appropriate for use by states, and this includes its use
as a backstop. Instances of this approach are throughout the proposed
rule text and reflect our desire to ease the use of the model rule for
states, as a full state plan, or as a backstop to a ``state measures''
plan.
One way in which a backstop may need to differ from the model
trading rules proposed in this action is the requirement to make up for
a shortfall in emissions performance in a state's prior plan
performance period. The model trading rules do not provide provisions
that would automatically adjust the emission standards to account for
any prior emission performance shortfall (which is an option states
have if designing their own backstop). Thus, a state relying on the
model trading rule as its backstop would likely need to submit an
appropriate revision to the backstop emission standards adjusting for
the shortfall through the state plan revision process. This would
likely be done in conjunction with the process for putting the backstop
into effect.
If a state chooses to use the model rule as its federally
enforceable backstop in a state measures plan, this does not mean that
the backstop is itself the federal plan. Rather, the model rule becomes
adopted as a part of the state plan. Both approaches to the model
trading rule are ``emission standard'' approaches under the EGs where
an emission standard is imposed and federally enforceable on the
affected EGUs: In the rate-based approach the emissions standard is an
allowable rate of emissions; in the mass-based approach the emission
standard is the requirement to hold allowances equal to reported
emissions. The EPA may also handle the administration of the trading
program for states utilizing the model trading rule. However, even
though the backstop may take the form of an EPA-administered,
federally-enforceable trading rule, this does not mean that a federal
plan has been put into effect. The state retains all of its rights and
responsibilities with respect to the implementation and enforcement of
the backstop as a component of its state plan.
Applicability and Enforceability. If promulgated for the affected
EGUs in a particular state, this federal plan will require affected
EGUs to meet specific emission standards for CO2 and related
requirements. These enforceable compliance obligations will apply to
the owners and operators of those affected EGUs. See 40 CFR 62.13. No
obligation falls on states or state officials (except to the extent
they may be owners and operators of affected EGUs).\17\ In the event of
noncompliance, the provisions in the federal plan are federally
enforceable against an affected EGU, in the same manner as the
provisions of an approved state plan under CAA section 111(d), and
similar to a FIP or an approved SIP under CAA section 110. See CAA
section 111(d)(2)(B), 42 U.S.C. 7411(d)(2)(B) (power to enforce state
and federal plans), section 113(a)-(h), 42 U.S.C. 7413(a)-(h), and
section 304, 42 U.S.C. 7604. This means that the Administrator has the
ability to enforce against violations and secure appropriate corrective
actions pursuant to CAA sections 113(a)-(h), and states and other third
parties maintain the ability to enforce against violations and secure
appropriate corrective actions pursuant to CAA section 304.
---------------------------------------------------------------------------
\17\ See Reno v. Condon, 528 U.S. 141, 151 (2000). State
officials responsible for developing state plans, however, should be
aware of the procedural enhancements being proposed to the framework
regulations of 40 CFR part 60, subpart B, in this rulemaking
document. These changes are discussed in section VII of this
preamble below. These changes are not a component of the proposed
federal plan or the EGs. Although these changes do not alter the
deadlines or submission obligations provided in the Clean Power Plan
Emission Guidelines, state officials and other interested parties
are encouraged to review and comment on these changes.
---------------------------------------------------------------------------
III. Federal Plan Structure To Achieve Reductions
A. Overview
1. Interactions With State Plans and Scope of Trading
The EPA intends to set up and administer a program to track trading
programs--both rate-based and mass-based--that will be available for
all states that choose it. The EPA proposes that affected EGUs in any
state covered by a federal plan could trade compliance instruments with
affected EGUs in any other state covered by a federal plan or a state
plan meeting the conditions for linkage to the federal plan. In the
proposed mass-based federal plan trading program, this would mean that
affected EGUs in a state covered by the federal plan or a state meeting
the conditions for linkage to the federal plan could use, as a
compliance instrument, an allowance distributed in any other state
covered by the federal plan or a state meeting the conditions for
linkage to the federal plan. Similarly, in the proposed rate-based
federal plan trading program approach, this would mean that affected
EGUs in a state covered by the federal plan or a state meeting the
conditions for linkage to the federal plan could use, as a compliance
instrument, an ERC issued in any other state covered by the federal
plan or a state meeting the conditions for linkage to the federal plan.
We propose that an affected EGU in a state covered by the mass-based
trading federal plan must use allowances for compliance (not ERCs).
Similarly, an affected EGU in a state covered by the rate-based trading
federal plan must use ERCs for compliance (not allowances).
The agency promulgated provisions for ``ready-for-interstate-
trading'' plans in the EGs. The EPA is proposing the federal plans as
ready-for-interstate-trading plans. State plans that adopt the model
rule are also considered ready-for-interstate-trading. The EPA proposes
to allow interstate trading between affected EGUs in states covered by
the proposed federal plans and affected EGUs in states covered by state
plans (referred to below as ``linking'' states, or ``linkages'') under
the following conditions, which are discussed further below the list:
The state plan must be approved.
The state plan must implement the same type of trading
program as the federal plan trading program in order to
[[Page 64977]]
be linked for interstate trading, i.e., mass-based trading programs can
link to mass-based trading programs only, and rate-based trading
programs can link to rate-based trading programs only.
The state plan must use the identical compliance
instrument as the federal plan (this requirement is detailed below).
The state plan must be approved as a ready-for-interstate-
trading plan.
The state plan must use an EPA-administered tracking
system (we are also requesting comment on expanding this to include a
state plan that uses an EPA-designated tracking system that is
interoperable with an EPA-administered system, as detailed below).
The EPA proposes that interstate ERC trading could occur both (1)
from affected EGUs in states covered by the rate-based trading federal
plan to affected EGUs in states with approved rate-based trading state
plans meeting the proposed conditions for linkages (including the
conditions for being ``ready-for-interstate-trading'' that were
finalized in the EG), and (2) from affected EGUs in such state-plan-
covered states to affected EGUs in federal-plan-covered states. The EPA
also requests comment on expanding the scope of interstate trading to
include linking states covered by the rate-based trading federal plan
with any state that has an approved rate-based trading state plan
meeting the proposed conditions for linkages and that uses an EPA-
designated ERC tracking system that is interoperable with an EPA-
administered ERC tracking system. The EPA also requests comment on
allowing a state that has an approved rate-based trading state plan
meeting the proposed conditions for linkages and that uses an EPA-
designated ERC tracking system to register with the EPA, and after
registration, to link with states covered by the rate-based trading
federal plan. There are multiple benefits to a registration
requirement, which include ensuring that the tracking systems are
functionally interoperable.
For the mass-based federal plan, the EPA proposes that interstate
allowance trading could occur in both directions, i.e., from affected
EGUs in states covered by the mass-based trading federal plan to
affected EGUs in states with approved mass-based trading state plans
meeting the proposed conditions for linkages, and from affected EGUs in
such state-plan-covered states to sources in federal-plan-covered
states.
The EPA proposes that a condition of linkage between a state plan
and the federal plan is the use of an identical compliance instrument.
In the mass-based federal plan the EPA proposes to issue allowances in
short tons; as a result, the EPA is proposing in this rule that linkage
for the mass-based federal plan is limited to state plans that issue
allowances in short tons. The agency also requests comment on whether
to extend linkage to state plans that issue allowances in metric tons
and on what provisions would be necessary to implement such linkages.
The EPA believes that considerations for linkages to state plans that
use metric tons may include tracking system design, and stipulation of
which parties convert state plan allowances denominated in metric tons
to allowances denominated in short tons and at what stage of compliance
operations the conversion occurs. The agency requests comment on these
and any other considerations for linkages between the federal plan and
state plans that issue allowances in metric tons.\18\
---------------------------------------------------------------------------
\18\ In this preamble all references to ``tons'' are short tons,
unless otherwise noted.
---------------------------------------------------------------------------
The EPA also requests comment on expanding the scope of interstate
trading to include linking states covered by the mass-based trading
federal plan with any state that has an approved mass-based trading
state plan meeting the proposed conditions for linkages and that uses
an EPA-designated allowance tracking system that is interoperable with
an EPA-administered allowance tracking system. The EPA also requests
comment on allowing a state that has an approved mass-based trading
state plan meeting the proposed conditions for linkages and that uses
an EPA-designated allowance tracking system to register with the EPA,
and after registration, to link with states covered by the mass-based
trading federal plan.
In the Clean Power Plan EGs, the EPA promulgated requirements that
apply to an emissions budget trading state plan that includes non-
affected EGU emission sources, to provide the opportunity for such a
state plan to be potentially approvable for linking to other state
plans (see Clean Power Plan EGs, section VIII). In this proposed rule,
the proposed approach to link from the mass-based trading federal plan
to state plans could result in linking of the federal plan to state
plans that include non-affected emission sources. The EPA requests
comment on this proposed approach.
The EPA believes that a broad trading region provides greater
opportunities for cost-effective implementation of reductions compared
to trading limited to a smaller region. The proposed approach to
interstate trading is intended to strike a reasonable balance between
providing the opportunity for a wide interstate trading system while
maintaining the integrity of the linked programs. The agency requests
comment on the proposed approach to interstate trading linkages in the
federal plans.
Whether the EPA ultimately finalizes rate-based or mass-based
federal plans, the agency believes that the ERC market and the
allowance market would be competitive. The opportunities for interstate
trading detailed above would reduce any potential for firms to exercise
market power in the ERC market or allowance market. The EPA requests
comment on this expectation of a competitive ERC market and a
competitive allowance market, and comment on potential program design
choices that could address any identified market power concern. The EPA
intends to provide information to the market and the public, consistent
with other trading programs that the agency administers, as detailed in
sections IV and V of this preamble, for the rate-based and mass-based
approaches, respectively.
A transparent and well-functioning allowance or ERC market is an
important element of a mass-based or rate-based trading program. The
EPA has over 20 years of experience implementing emissions trading
programs for the power sector and based on that experience, believes
the potential or likelihood of market manipulation is fairly low.
Nonetheless, the EPA is evaluating the options for providing oversight
of the allowance or ERC markets that may be established through the
final EGs and federal plans. This could include engaging with other
federal and state agencies as appropriate, and potentially with third
parties, in conducting market oversight. The agency requests comment on
appropriate market monitoring activities, which may include tracking
ownership of allowances or ERCs, oversight of the creation and
verification of credits, and tracking market activity (e.g.,
transaction volumes and prices).
2. Addressing Potential Leakage and Interstate Effects
The final EGs specify the concern of leakage, which is defined in
section VII.D of the final EGs as the potential of an alternative form
of implementation of the BSER (e.g., the rate-based and mass-based
state goals) to create a larger incentive for affected EGUs to shift
generation to new fossil fuel-fired EGUs relative to what would occur
when the implementation of the BSER took the form of standards of
performance incorporating the subcategory-specific emission performance
rates representing
[[Page 64978]]
the BSER. The final EGs specified that mass-based plan approaches must
address leakage, because the form of the mass goals may ultimately
impact the relative incentives to generate and emit at affected EGUs as
opposed to shifting generation to new sources, with potential
implications for whether the mass goal implements or is consistent with
the BSER and overall emissions from the sector. These circumstances are
much less likely to be present under a rate-based plan approach, where
the form of the goal ensures sufficient incentive to affected existing
EGUs to generate and thus avoid leakage, similar to the CO2
emission performance rates. By requiring mass-based plan components
that address leakage, the final EGs ensure that mass goals are
equivalent to the CO2 emission performance rates and are
thus an equivalent expression of the BSER. Section VII.D of the final
EGs details the requirement for addressing leakage and why it is
needed, and section VIII.J of the final EGs specifies options for mass-
based state plan components that address leakage. We are proposing, as
part of the mass-based approach under the federal plan and model rule,
to implement allowance allocation approaches to address leakage,
specifically through establishing an output-based allocation set-aside
and a set-aside that encourages the installation of RE. These proposed
strategies are detailed in section V.D of this preamble.
In the final EGs, the EPA also discussed the concern that
CO2 emission reductions would be eroded in situations where
an affected EGU in a rate-based state counts the MWh from measures
located in a mass-based state, but the generation from that measure
acts solely to serve load in the mass-based state. In that scenario,
expected CO2 emission reduction actions in the rate-based
state are foregone as a result of counting MWh that resulted in
CO2 emission reductions in a mass-based state. The proposed
rate-based approach, in accordance with the final EGs, restricts ERC
issuance for any emission reduction measures located in a mass-based
state, except for RE. RE measures located in a state with a mass-based
state plan can only be approved for ERC issuance for use by a state
under a rate-based federal plan if it can be demonstrated that load-
serving entities in the rate-based state have contracted for the
delivery of the RE generation that occurs in a mass-based state to meet
load in a rate-based state. As part of this federal plan, we are
proposing that this can be demonstrated through the provision of a
power delivery contract or power purchase agreement in which an entity
in the rate-based state contracts for the supply of the MWhs in
question and providing documentation that the electricity was treated
as comparable to a generation resource used to serve regional load that
included the rate-based state. This demonstration must be included as
part of the project application for ERC issuance to the EPA or its
agent from the RE provider in the mass-based state. Once the project is
approved, subsequent applications for issuance of credit to the EPA
will need to reference that the MWh submitted are associated with that
contractual arrangement with the mass-based RE provider. The EPA
requests comment on this approach. It should also be noted that we are
proposing that under the proposed mass-based approach, if RE located in
a mass-based state receives mass-based set-aside allowances for any
generation, that generation is not eligible to be issued ERCs in a
rate-based state.
The EPA requests comment on the proposed treatment of leakage and
of interstate effects under both the proposed rate-based federal plan
approach and the proposed mass-based federal plan approach, and as part
of the corresponding proposed model rules.
3. Provisions To Encourage Early Action
The EPA outlined and initiated the CEIP in the final EGs (see
section VIII.B.2 of the final EGs). The program is designed to
incentivize investment in certain types of RE projects, as well as
demand-side energy efficiency (EE) projects implemented in low-income
communities. These RE projects must commence construction, and these EE
projects must commence implementation after the date of submission of a
final plan to the EPA by the state they are located on or benefitting,
or after September 6, 2018 for those states on whose behalf the EPA is
implementing the federal plan, and will receive incentives for the MWh
they generate or the end-use energy demand reductions they achieve
during 2020 and/or 2021. The CEIP also provides an additional incentive
to drive investment in demand-side EE projects implemented in low-
income communities. The EPA proposes to apply the CEIP in all states
subject to either a rate-based or mass-based federal plan. The EPA's
proposed approaches to implementing the program in the rate-based and
mass-based federal plans are detailed in sections IV and V of this
preamble, respectively.
B. Inventory of Emissions
Fossil fuel-fired EGUs are by far the largest emitters of GHGs
among stationary sources in the United States, primarily in the form of
CO2, and among fossil fuel-fired EGUs, coal-fired units are
by far the largest emitters. This section describes the amounts of
these emissions and places these amounts in the context of the U.S.
Inventory of Greenhouse Gas Emissions and Sinks \19\ (the U.S. GHG
Inventory).
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\19\ ``Inventory of U.S. Greenhouse Gas Emissions and Sinks:
1990-2013'', Report EPA 430-R-15-004, United States Environmental
Protection Agency, April 15, 2015. http://www.epa.gov/climatechange/ghgemissions/usinventoryreport.html.
---------------------------------------------------------------------------
The EPA implements a separate program under 40 CFR part 98 called
the Greenhouse Gas Reporting Program \20\ (GHGRP) that requires
emitting facilities over threshold amounts of GHGs to report their
emissions to the EPA annually. Using data from the GHGRP, this section
also places emissions from fossil fuel-fired EGUs in the context of the
total emissions reported to the GHGRP from facilities in the other
largest-emitting industries.
---------------------------------------------------------------------------
\20\ U.S. EPA Greenhouse Gas Reporting Program Dataset, see
http://www.epa.gov/ghgreporting/ghgdata/reportingdatasets.html.
---------------------------------------------------------------------------
The EPA prepares the official U.S. GHG Inventory to comply with
commitments under the United Nations Framework Convention on Climate
Change (UNFCCC). This inventory, which includes recent trends, is
organized by industrial sectors. It provides the information in Table 3
of this preamble, which presents total U.S. anthropogenic emissions and
sinks \21\ of GHGs, including CO2 emissions, for the years
1990, 2005, and 2013.
---------------------------------------------------------------------------
\21\ Sinks are a physical unit or process that stores GHGs, such
as forests or underground or deep sea reservoirs of CO2.
[[Page 64979]]
Table 3--U.S. GHG Emissions and Sinks by Sector
[Million metric tons carbon dioxide equivalent (MMT CO2 Eq.)] \22\
----------------------------------------------------------------------------------------------------------------
Sector 1990 2005 2013
----------------------------------------------------------------------------------------------------------------
Energy \23\..................................................... 5,290.5 6,273.6 5,636.6
Industrial Processes and Product Use............................ 342.1 367.4 359.1
Agriculture..................................................... 448.7 494.5 515.7
Land Use, Land-Use Change and Forestry.......................... 13.8 25.5 23.3
Waste........................................................... 206.0 189.2 138.3
-----------------------------------------------
Total Emissions............................................. 6,301.1 7,350.2 6,673.0
Land Use, Land-Use Change and Forestry (Sinks).................. (775.8) (911.9) (881.7)
-----------------------------------------------
Net Emissions (Sources and Sinks)........................... 5,525.2 6,438.3 5,791.2
----------------------------------------------------------------------------------------------------------------
Total fossil energy-related CO2 emissions (including
both stationary and mobile sources) are the largest contributor to
total U.S. GHG emissions, representing 77.3 percent of total 2013 GHG
emissions.\24\ In 2013, fossil fuel combustion by the utility power
sector--entities that burn fossil fuel and whose primary business is
the generation of electricity--accounted for 38.3 percent of all
energy-related CO2 emissions.\25\ Table 4 of this preamble
presents total CO2 emissions from fossil fuel-fired EGUs,
for years 1990, 2005, and 2013.
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\22\ From Table ES-4 of ``Inventory of U.S. Greenhouse Gas
Emissions and Sinks: 1990-2013'', Report EPA 430-R-15-004, United
States Environmental Protection Agency, April 15, 2015. http://www.epa.gov/climatechange/ghgemissions/usinventoryreport.html.
\23\ The energy sector includes all greenhouse gases resulting
from stationary and mobile energy activities, including fuel
combustion and fugitive fuel emissions.
\24\ From Table ES-2 ``Inventory of U.S. Greenhouse Gas
Emissions and Sinks: 1990-2013'', Report EPA 430-R-15-004, United
States Environmental Protection Agency, April 15, 2015. http://www.epa.gov/climatechange/ghgemissions/usinventoryreport.html.
\25\ From Table 3-1 ``Inventory of U.S. Greenhouse Gas Emissions
and Sinks: 1990-2013'', Report EPA 430-R-15-004, United States
Environmental Protection Agency, April 15, 2015. http://www.epa.gov/climatechange/ghgemissions/usinventoryreport.html.
\26\ From Table 3-5 ``Inventory of U.S. Greenhouse Gas Emissions
and Sinks: 1990-2013'', Report EPA 430-R-15-004, United States
Environmental Protection Agency, April 15 2015. http://www.epa.gov/climatechange/ghgemissions/usinventoryreport.html.
Table 4--U.S. GHG Emissions From Generation of Electricity From Combustion of Fossil Fuels (MMT CO2) \26\
----------------------------------------------------------------------------------------------------------------
GHG emissions 1990 2005 2013
----------------------------------------------------------------------------------------------------------------
Total CO2 from fossil fuel-fired EGUs........................... 1,820.8 2,400.9 2,039.8
--from coal................................................. 1,547.6 1,983.8 1,575.0
--from natural gas.......................................... 175.3 318.8 441.9
--from petroleum............................................ 97.5 97.9 22.4
----------------------------------------------------------------------------------------------------------------
In addition to preparing the official U.S. GHG Inventory, which
represents comprehensive total U.S. GHG emissions and complies with
commitments under the UNFCCC, the EPA collects detailed GHG emissions
data from the largest emitting facilities in the United States through
its GHGRP. Data collected by the GHGRP from large stationary sources in
the industrial sector show that the utility power sector emits far
greater CO2 emissions than any other industrial sector.
Table 5 of this preamble presents total GHG emissions in 2013 for the
largest emitting industrial sectors as reported to the GHGRP. As shown
in Table 4 and Table 5 of this preamble, respectively, CO2
emissions from fossil fuel-fired EGUs are nearly three times as large
as the total reported GHG emissions from the next ten largest emitting
industrial sectors in the GHGRP database combined.
Table 5--Direct GHG Emissions Reported to GHGRP by Largest Emitting
Industrial Sectors (MMT CO2e) \27\
------------------------------------------------------------------------
Industrial sector 2013
------------------------------------------------------------------------
Petroleum Refineries.................................... 176.7
Onshore Oil & Gas Production............................ 94.8
Municipal Solid Waste Landfills......................... 93.0
Iron & Steel Production................................. 84.2
Cement Production....................................... 62.8
Natural Gas Processing Plants........................... 59.0
Petrochemical Production................................ 52.7
Hydrogen Production..................................... 41.9
Underground Coal Mines.................................. 39.8
Food Processing Facilities.............................. 30.8
------------------------------------------------------------------------
C. Affected EGUs
For the Clean Power Plan and this federal plan, an affected EGU is
any SGU, IGCC, or stationary combustion turbine that was in operation
or had commenced construction as of January 8, 2014,\28\ and that meets
the following criteria, which differ depending on the type of unit. To
be an affected EGU, such a unit, if it is SGU or IGCC, must serve a
generator capable of selling greater than 25 MW to a utility power
distribution system and have a base load rating greater than 260 GJ/h
(250 MMBtu/h) heat input of fossil fuel (either alone or in combination
with any other fuel). If such a unit is a SCT, the unit must meet the
definition of a combined cycle or CHP combustion turbine, serve a
generator capable of selling greater than 25 MW to a utility power
distribution system, and have a base load rating of greater than 260
GJ/h (250 MMBtu/h).
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\27\ U.S. EPA Greenhouse Gas Reporting Program Dataset as of
August 18, 2014. http://ghgdata.epa.gov/ghgp/main.do.
\28\ Under section 111(a) of the CAA, determination of affected
sources is based on the date that the EPA proposes action on such
sources. January 8, 2014 is the date the proposed GHG standards of
performance for new fossil fuel-fired EGUs were published in the
Federal Register (79 FR 1430).
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When considering and understanding applicability, the following
definitions may be helpful. Simple cycle
[[Page 64980]]
combustion turbine means any stationary combustion turbine which does
not recover heat from the combustion turbine engine exhaust gases for
purposes other than enhancing the performance of the stationary
combustion turbine itself. Combined cycle combustion turbine means any
SCT which recovers heat from the combustion turbine engine exhaust
gases to generate steam that is used to create additional electric
power output in a steam turbine. CHP combustion turbine means any SCT
which recovers heat from the combustion turbine engine exhaust gases to
heat water or another medium, generates steam for useful purposes other
than exclusively for additional electric generation, or directly uses
the heat in the exhaust gases for a useful purpose.
We note that certain affected EGUs are exempt from inclusion in a
state plan and this federal plan. Affected EGUs that may be excluded
under the EGs are those that (1) Are subject to subpart 40 CFR part 60,
subpart TTTT as a result of commencing modification or reconstruction;
(2) are SGUs or IGCC that are currently and always have been subject to
a federally enforceable permit limiting net-electric sales to one-third
or less of its potential electric output or 219,000 MWh or less on an
annual basis; (3) are non-fossil units (i.e., units that are capable of
combusting 50 percent or more non-fossil fuel) that have historically
limited the use of fossil fuels to 10 percent or less of the annual
capacity factor or are subject to a federally enforceable permit
limiting fossil fuel use to 10 percent or less of the annual capacity
factor; (4) are stationary combustion turbines that are not capable of
combusting natural gas (i.e., not connected to a natural gas pipeline);
(5) are CHP units that are subject to a federally enforceable permit
limiting, or have historically limited, annual net electric sales to a
utility power distribution system to the product of the design
efficiency and the potential electric output or 219,000 MWh (whichever
is greater) or less; (6) serve a generator along with other SGU(s),
IGCC(s), or stationary combustion turbine(s) where the effective
generation capacity (determined based on a prorated output of the base
load rating of each SGU, IGCC, or stationary combustion turbine) is 25
MW or less; (7) are a municipal waste combustor unit subject to subpart
Eb of 40 CFR part 60; or (8) are a commercial or industrial solid waste
incineration unit that is subject to subpart CCCC of 40 CFR part
60.\29\
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\29\ We had proposed in the Clean Power Plan EGs that affected
EGUs were those existing source fossil fuel-fired EGUs that met the
applicability criteria for coverage under the final GHG standards
for new fossil fuel-fired EGUs being promulgated under CAA section
111(b). However, we are finalizing in the EGs that states need not
include certain units that would otherwise meet the CAA section
111(b) applicability in this CAA section 111(d) EGs. These include
simple cycle turbines, certain non-fossil units, and certain CHP
units. The final CAA section 111(b) standards include applicability
criteria for simple cycle combustion turbines, for reasons relating
to implementation and minimizing emissions from all future
combustion turbines.
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The EPA also requests comment on an alternative compliance pathway
that could be available to units under a mass-based approach. The ways
that the approach could be implemented are further outlined in the
Alternative Compliance Pathway for Units that Agree to Retire Before a
Certain Date Technical Support Document (TSD). Under this approach, two
basic requirements would need to be met. The first is that the unit
would have to take a commitment that it would retire on a date on or
before December 31, 2029. The second is that the unit would have to
demonstrate that it will take an enforceable emission limitation that
would assure that the overall state emission goal is met. The TSD
explores ways that this approach could be implemented, including ways
that the enforceable emission limitation could be calculated and
implemented. The EPA requests comment on whether this approach should
be available for all units or limited to small units (e.g. less than
100 MW nameplate capacity). The EPA also requests comment on whether
and how such an approach could be included under a rate-based approach.
The applicability of this proposed federal plan follows the same
applicability criteria as the final EGs. The rationale for these
criteria is provided in section IV.D of the Clean Power Plan. We are
not reopening the criteria or rationale here.
In the federal plan Affected EGU TSD, the EPA lists all applicable
affected EGUs according to our records from the National Electric
Energy Data System (NEEDS), Energy Information Administration (EIA),
and comments from the Clean Power Plan. In this TSD, each affected EGU
is assigned its proposed applicable standards if a federal plan were to
be promulgated for that affected EGU at any time. The EPA requests
comments and updates to this list of affected units. Section VI.C of
the final EGs describes the data used in setting the standards and how
an inventory of affected units has been compiled.
D. Compliance Schedule
In accordance with the schedule set out in the EGs, the federal
plan is proposed to be implemented in a phased approach. The first
period, corresponding to the Interim Period in the EG, is proposed to
run from beginning of calendar year 2022 until end of calendar year
2029 (January 1, 2022 to December 31, 2029). The Final Period would run
from beginning of calendar year 2030 (January 1, 2030) indefinitely
into the future. The first period is proposed to be comprised of three
``compliance periods,'' set by calendar year. The first compliance
period will be from January 1, 2022 to midnight, December 31, 2024 (3
calendar years). The second compliance period will be from January 1,
2025 to midnight, December 31, 2027 (3 calendar years). The third
compliance period will be from January 1, 2028 to midnight, December
31, 2029 (2 calendar years).
Under the EGs, midnight, December 31, 2029 marks the end of the
Interim Period, and the beginning of the Final Period. The EPA proposes
that the compliance periods in the Final Period will each be 2 calendar
years. Thus, the first compliance period after 2030 would be from
January 1, 2030 to midnight, December 31, 2031. The second compliance
period would be from January 1, 2032 to midnight, December 31, 2033.
This would repeat accordingly unless changed by the EPA through a
revision to the federal plan or other action.\30\
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\30\ This schedule would be the same under either a rate- or
mass-based approach.
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The EPA recognizes that the compliance periods provided for in this
rulemaking are longer than those historically and typically specified
in CAA rulemakings. As reflected in long-standing CAA precedent,
``[t]he time over which [the compliance standards] extend should be as
short term as possible and should generally not exceed one month.'' See
e.g., June 13, 1989 Guidance on Limiting Potential to Emit in New
Source Permitting and January 25, 1995 Guidance on Enforceability
Requirements for Limiting Potential to Emit through SIP and Sec. 112
Rules and General Permits. The EPA determined that the longer
compliance periods provided for in this rulemaking are acceptable in
the context of this specific rulemaking because of the unique
characteristics of this rulemaking, including that CO2 is
long-lived in the atmosphere, and this rulemaking is focused on
performance standards related to those long-term impacts.
[[Page 64981]]
Prior to the beginning of the first compliance period in 2022, the
agency intends to establish the infrastructure for operating a federal
trading program and to work closely with affected EGUs in the states
where the federal plan is promulgated prior to the start of the first
compliance period in 2022. We request comment on whether it would be
possible to grant, on a case-by-case basis, certain affected EGUs,
particularly small entities, additional time to come into compliance,
and to request additional input from the public as to the design of
such flexibility that would be compatible with the EGs and a federal
plan that implements a trading system.
The EPA recognizes that it is important to ensure a degree of
liquidity in compliance instruments in either of the proposed trading
approaches, while also maintaining the stringency required by the final
EGs. A number of aspects of the rate-based and mass-based programs
would assist with this, including allocation methods or rules,
mechanisms to place allowances or credits into the market relatively
early, requirements for public transparency of information related to
allowance, or credit issuance, tracking, transfers and holdings. The
EPA solicits comment on other approaches to ensure market liquidity
while continuing to meet the stringency of the final EGs.
E. Addressing Reliability Concerns
The proposed federal plan has been designed to ensure that, to the
greatest extent possible, implementation would not interfere with the
power sector's ability to maintain electric reliability.\31\ Like the
EGs, the federal plan provides a long planning horizon and
implementation period. In addition the federal plan allows affected
EGUs to obtain tradable allowances and credits to meet obligations
which assures that reliability can be maintained without disruption to
the electricity system.
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\31\ The EPA evaluated certain aspects of electric reliability
in the context of modeling projections for the final Clean Power
Plan, and that evaluation is described in the ``Resource Adequacy
and Reliability Analysis TSD'' for that rulemaking, a copy of which
is also included in the docket for this rulemaking.
---------------------------------------------------------------------------
There are many features of the electricity system that ensure that
electric system reliability will be maintained. For example, in the
Energy Policy Act of 2005, Congress added a section to the Federal
Power Act to make reliability standards mandatory and enforceable by
the Federal Energy Regulatory Commission (FERC) and the North American
Electric Reliability Corporation (NERC), the Electric Reliability
Organization which FERC designated and oversees. Along with its
standards development work, NERC conducts annual reliability
assessments via a 10-year forecast and winter and summer forecasts;
audits owners, operators and users for preparedness; and educates and
trains industry personnel. Numerous other entities such as FERC, U.S.
Department of Energy (DOE), state public utility commissions (PUCs),
independent system operators and regional transmission organizations
(ISOs/RTOs), and other planning authorities also consider the
reliability of the electric system. There are also numerous remedies
that are routinely employed when there is a specific local or regional
reliability issue. These include transmission system upgrades,
installation of new generating capacity, calling on demand response,
and other demand-side actions.
Additionally, planning authorities and system operators constantly
consider, plan for and monitor the reliability of the electricity
system with both a long-term and short-term perspective. Over the last
century, the electric industry's efforts regarding electric system
reliability have become multidimensional, comprehensive and
sophisticated. Under this approach, planning authorities plan the
system to assure the availability of sufficient generation,
transmission, and distribution capacity to meet system needs in a way
that minimizes the likelihood of equipment failure.\32\ Long-term
system planning happens at both the local and regional levels with all
segments of the electric system needing to operate together in an
efficient and reliable manner. In the short-term, electric system
operators operate the system within safe operating margins and work to
restore the system quickly if a disruption occurs.\33\ Mandatory
reliability standards apply to how the bulk electric system is planned
and operated. For example, transmission operators and balancing
authorities have to develop, maintain and implement a set of plans to
mitigate operating emergencies.\34\
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\32\ Casazza, J. and Delea, F., Understanding Electric Power
Systems: An Overview of the Technology, the Marketplace, and
Government Regulations, IEEE Press, at 160 (2010).
\33\ Id.
\34\ NERC Reliability Standard EOP-001-2.1b--Emergency
Operations Planning, available at http://www.nerc.net/standardsreports/standardssummary.aspx.
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The EPA's approach in this proposed federal plan builds on the
foundation provided in the EGs' determination of the BSER to ensure
that the final federal plan, like the final EGs, does not interfere
with the industry's ability to maintain reliability of the nation's
electricity supply. First, the federal plan, like the EGs, provides
more than 6 years before reductions are required and an 8-year period
from 2022 to 2029 to meet interim goals. This allows time for planning
and steady, measured implementation.
Second, the federal plan is a market-based trading program which
will allow affected EGUs the opportunity to buy and sell emissions
credits or allowances as well as bank them. The EPA's proposed federal
plan includes two alternative approaches: A mass-based trading program
and a rate-based trading program. Trading programs of both types have
many positive attributes. Among them is that they help to ensure that
imposition of the federal plan will not interfere with the industry's
ability to maintain the reliability of the nation's electricity supply.
Such a program does not restrict unit-level operational decision-making
beyond requiring units to hold a sufficient number of tradable permits
(e.g., allowances or ERCs) to cover emissions. It, therefore,
inherently allows for unit-level operational flexibility to facilitate
the maintenance of reliability and makes the program enormously
resilient. If a unit finds it needs to run more than anticipated, the
market-based compliance system provides a way for the EGU to meet its
generation needs while it maintains compliance with the federal plan.
Third, just as we have required the states to do in developing
state plans, the EPA is considering reliability as a part of developing
this federal plan. For example, the EPA will consult with planning
authorities. The EPA will work with the ISO/RTO Council to convene a
face-to-face meeting for planning authorities with the EPA during the
comment period to discuss any concerns or other feedback on the federal
plan from those entities. This meeting will help to ensure that the EPA
is taking into consideration any concerns about the relationship of
this rulemaking to the ability of the industry to maintain electric
reliability across the country as we finalize the federal plan. It will
give the planning authorities an opportunity to hear directly from the
EPA how the federal plan is designed and gives the planning authorities
an opportunity to voice concerns and ask questions. This will help
inform comments that planning authorities may submit to the docket.
In the final Clean Power Plan EGs, the EPA laid out the
availability of a reliability safety valve that could be used if an
unanticipated catastrophic emergency caused a conflict between
[[Page 64982]]
maintenance of electric reliability and inflexible requirements that a
state plan might impose on an affected EGU or EGUs. Under the federal
plan, inflexible requirements are not imposed on specific plants.
Rather as explained earlier, the very nature of the federal plan, in
which affected EGUs can obtain allowances or credits if needed,
supports reliability. Therefore, a reliability safety valve for the
federal plan is not needed. The EPA invites comments on this aspect of
the proposed federal plan.
The EPA, DOE, and FERC have agreed to coordinate efforts to help
ensure continued reliable electricity generation and transmission
during the implementation of the final EGs and the final federal plan
in any state that does not have an approved state plan. The three
agencies have developed a coordination strategy that reflects their
joint understanding of how they will work together to monitor
implementation. The three agencies will work together to monitor
implementation, share information and resolve any difficulties that may
be encountered.
The EPA is not proposing to include an allowance set-aside, or
similar mechanism in a rate-based approach, to address reliability
issues in the federal plan; however, we request comment on including
such a set-aside in the context of a mass-based approach. The EPA
requests comment specifically on creation of an allowance set-aside for
the purpose of making allowances available in emergency circumstances
in which an affected EGU was compelled to provide reliability critical
generation and demonstrated that a supply of allowances needed to
offset its emissions was not available.
The set-aside would be in addition to the proposed set-asides that
are detailed in section V.D in this preamble. The EPA would set aside
allowances in each state under the mass-based federal plan, and if a
reliability issue is perceived by the EPA, DOE and FERC coordinated
monitoring process discussed above, the EPA would distribute allowances
from the set-aside to support affected EGUs during or after an
unforeseen, emergency reliability event. If there were unused
allowances remaining in the set-aside, then the EPA would distribute
them to affected EGUs pro rata based on the allocation approach that is
detailed in section V.D of this preamble. The EPA requests comment on
all elements of such an approach, including what events would trigger
the need for allowances from the reliability set-aside; eligibility
criteria to receive the set-aside allowances; the size of the set-
aside; and the timing of distribution of allowances from the
reliability set-aside. Additionally, the EPA requests comment on how a
reliability ``set-aside'' approach could be implemented in the rate-
based federal plan.
As detailed later in this preamble, the EPA proposes in the federal
plan to implement a CEIP, which was established in the EGs to reward
investment in certain clean energy projects that achieve MWh results
during 2020 and 2021 (see sections IV and V of this preamble for the
proposed approach to implement this incentive program in the rate-based
and mass-based federal plans, respectively). Implementation of the CEIP
in the federal plans would create ERCs and allowances before 2022,
allowing for creation of banks that could be used in the event of an
unforeseen, emergency reliability issue. The EPA requests comment on
the potential for these banks of ERCs and allowances to support
reliable electricity generation and transmission to be utilized in the
event of this kind of reliability emergency.
F. Worker Certification
In the EGs, the EPA suggested that to ensure that emission
reductions are realized, it is important that construction, operations
and other skilled work undertaken pursuant to state plans is performed
to specifications, and is effective, safe, and timely. The EPA asks for
comments as to whether the federal plan should encourage EGUs to ask
for a demonstration that the work undertaken under a federal plan is
performed by a proficient workforce. A good way to ensure such a
workforce is to require that workers have been certified by: (1) An
apprenticeship program that is registered with the U.S. Department of
Labor (DOL), Office of Apprenticeship or a state apprenticeship program
approved by the DOL; (2) a skill certification aligned with the DOE
Better Building Workforce Guidelines and validated by a third party
accrediting body recognized by DOE; or (3) other skill certification
validated by a third party accrediting body.
G. Remaining Useful Lives and Potential for ``Stranded Assets''
Section 111(d)(2) of the CAA provides, ``In promulgating a standard
of performance under a plan prescribed under this paragraph, the
Administrator shall take into consideration, among other factors,
remaining useful lives of the sources in the category of sources to
which such standard applies.'' 42 U.S.C. 7411(d)(2). This language
tracks similar language in CAA section 111(d)(1) with respect to state
plans. In the final EGs, we explained how the Guidelines permit states
in applying a standard of performance in their state plans to consider
the remaining useful life of a facility. We determined that it was
appropriate to specify that the general variance provisions in 40 CFR
60.24(f) should not apply to the class of affected facilities covered
by these Guidelines. We concluded that facility-specific factors and in
particular, remaining useful life, do not justify a state making
further adjustments to the performance rates or aggregate emission goal
that the Guidelines define for affected EGUs in a state and that must
be achieved by the state plan.
Because the Guidelines do not allow for states to deviate from
state goals based on remaining useful life, the EPA does not believe
such goal adjustments are necessary or appropriate in the federal plan
either. Nonetheless, this does not obviate the requirement that the EPA
itself, in the design of its federal plan, consider, among other
factors, the remaining useful lives of the affected facilities. The
agency therefore proposes the following analysis of this factor.\35\
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\35\ We note that the preamble and supporting materials for the
EGs discuss a related concern raised by some stakeholders, which is
whether the EGs could result in widespread ``stranded assets'' as a
direct result of the rule. As explained there, we believe this
concern is distinct from the ``remaining useful lives'' factor in
CAA section 111(d)(1), and for the same reasons, believe it is
distinct from the factor Congress directed the agency to consider in
CAA section 111(d)(2). Nonetheless, we undertook analysis in the
final EGs of whether and to what extent there may be a ``stranded
asset'' concern. See memorandum to Clean Power Plan Docket EPA-HQ-
OAR-2013-0602 titled ``Stranded Assets Analysis'' dated July 2015.
We believe that analysis demonstrates that this is not likely to be
a widespread issue under the federal plan either.
---------------------------------------------------------------------------
Congress added the ``remaining useful lives'' factor to CAA section
111(d)(2) in the 1977 CAA Amendments. Congress did not provide in the
statute any direction on how or to what degree ``remaining useful
lives'' of facilities subject to a section 111(d) federal plan is to be
considered. As discussed in the preamble to the final EGs, Congress'
intent in enacting the provision was to allow for older facilties with
short remaining useful lives to not be required to install capital-
intensive pollution control devices to meet emission standards that
would only be used for a short period of time before a plant ceased
operation. A House of Representatives report on a predecessor bill to
the enacted statute stated, ``Older plants with relatively short
remaining useful lives might have chosen to cease operation if the only
means of emission
[[Page 64983]]
limitation available to meet emission limits were pollution control
technology.'' H. Report 94-1175, at 159 (1976) (emphasis added). This
language is probative of the fact that Congress viewed ``remaining
useful lives'' as a consideration for facilities with relatively little
remaining useful life. We are confident the proposed federal plan will
not force costly pollution control investments at older plants with
short remaining useful lives.
Further, the statute provides that this factor is one ``among other
factors'' that the agency is to consider in promulgating a standard of
performance. Congress provided no guidance in the statute as to what
those other factors could be. The inclusion of unspecified factors that
the agency may determine for itself to consider, along with the use of
the term ``consider,'' highlights that Congress intended to give the
agency a substantial degree of discretion in determining how the
``remaining useful lives'' factor is considered. The statute does not
require, and Congress did not intend, that this consideration mandate
the agency to prevent all premature retirements of affected EGUs, to
impose no emission requirements on older affected EGUs, or to ensure
that profitability is maintained at all times for all affected EGUs.
Congress knew how to explicitly exempt older plants from CAA
requirements at the time of the 1977 Amendments. For example, Congress
excluded plants in existence before August 7, 1977 from the
preconstruction requirements of the prevention of significant
deterioration (PSD)/non-attainment new source review (NSR) program, see
CAA section 165(a). And in CAA section 169A related to visibility
impairment in federal class I areas, Congress excluded from
applicability units that began operation before August 7, 1962. 42
U.S.C. 7491(b)(2)(A). In CAA section 111(d) Congress did not set any
such specific criteria. Rather it directed the agency to ``consider''
the remaining useful lives of facilities, among other factors.
This view also accords with past agency practice in implementing a
similar provision. In the 1977 Amendments, Congress listed ``remaining
useful life'' as a factor for consideration in the visibility program
under section 169A. 42 U.S.C. 7491. The ``remaining useful life of the
source'' is one of several enumerated factors that the state or the EPA
is to consider in determining the best available retrofit technology
(BART) for a particular source. Consistent with congressional purpose,
the EPA has implemented this factor in the regional haze program for
many years through the BART guidelines, in appendix Y to 40 CFR part
51. In the context of the visibility program, we have interpreted this
provision to mean that the remaining useful life should be considered
when calculating the annualized costs of retrofit controls. See 40 CFR
part 51, appendix Y, section IV.D.4.k. In the agency's view, this
approach to ``remaining useful life'' aligns with congressional intent
and informs our view of how the ``remaining useful lives'' factor
should be considered under this CAA section 111(d) federal plan. The
key consideration is whether the time period associated with
amortizable costs of compliance will exceed the remaining useful lives
of the sources in question.
Consistent with legislative intent and past agency practice, we
propose that the federal plan adequately considers ``remaining useful
lives'' of affected EGUs by providing for trading and other
flexibilities authorized in the EGs. To summarize, these include:
Relatively long periods for affected EGUs to come into compliance, the
ability to credit early action, the use of emissions trading, the use
of multi-year compliance periods, and the ability to link to other
federal or state plans to create larger emissions markets. The federal
plan is proposed to include a Clean Energy Incentive Program as
provided for in the EGs, which will credit early action and ease
compliance in the initial years of the program. These tools will create
economic incentives that reward over-performance of some affected EGUs,
and allow others to simply acquire credits or allowances to comply with
their emission standard, thereby avoiding the need for installation of
costly pollution controls at sources with a short remaining life.
Thus, the proposed federal plan is designed in such a way that it
adequately, and inherently, takes into account the remaining useful
lives of affected EGUs. It provides substantial compliance flexibility,
including means of avoiding the need to make extensive capital
investments in control technologies that could not be recouped during
the remaining useful lives of a facility.\36\ The design of the federal
plan as a form of emission trading provides individual affected EGUs
the flexibility to make cost-conscious compliance choices. This
flexibility avoids or substantially diminishes any likelihood that
compliance will be a physical impossibility or result in unreasonable
costs.
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\36\ Because we believe that this is the case for all facilities
through the basic design of the federal plan, we also can confirm,
in line with the EGs, that the availability of variances from the
emission standards is unnecessary in the federal plan. Under the
general framework regulations, facility-specific variances from an
otherwise applicable standard of performance have been potentially
available under the application process in 40 CFR 60.27(e)(2), which
incorporates the factors provided in 40 CFR 60.24(f) for states.
Consistent with our view that the federal plan adequately considers
remaining useful lives, and for the same reasons, the need for
facility-specific variances under the circumstances of 60.24(f)
(unreasonable costs of controls, physical impossibility of
installation of necessary control equipment, or other factors that
make longer compliance times or less stringent standards
significantly more reasonable) is not expected to arise, and thus,
the agency proposes to make 40 CFR 60.27(e) inapplicable in this
federal plan.
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By relying on either rate- or mass-based emission trading, the
proposed federal plan capitalizes on the inherent flexibility available
through market-based techniques. In effect, under a trading program
with repeating compliance periods, a facility with a short remaining
useful life has a total outlay that is proportionately smaller than a
facility with a long remaining useful life, simply because the first
facility would need to comply for fewer compliance periods and would
need proportionately fewer ERCs or allowances than the second facility.
Buying ERCs or allowances as a compliance method could avoid excessive
up-front capital expenditures that might be unreasonable for facilities
with short remaining useful lives, and therefore addresses the
consideration of ``remaining useful lives.'' Buying ERCs or allowances
as a compliance method also would reduce the potential for stranded
assets.
In addition, the timing of the federal plan limits the immediate
costs of compliance, particularly for facilities that have useful lives
ending before 2022, but also for facilities that have useful lives
ending before 2030. There are no compliance obligations for affected
EGUs under this federal plan until 2022, when the first compliance
period begins. At that point, the agency is following the glide path
provided for in the EGs, which begins with relatively higher emission
targets that will slowly strengthen over the interim performance period
from 2022-2029 through three multi-year compliance periods. The final,
most stringent, compliance obligation does not begin until 2030.
Further, unlike state plans that can be more stringent under CAA
section 116, the federal plan is no more stringent than the EGs, and,
as explained in the EGs, the Guidelines reflect a reasonable, rather
than a maximum possible, implementation level for each building block
in order to establish overall goals that are achievable. As discussed
in the
[[Page 64984]]
EGs, the BSER determined an average level of emissions achievable by
groups of EGUs, rather than for an individual EGU. In considering the
remaining useful lives of facilities under a federal plan, the EPA
believes this approach to setting the emission standards, coupled with
the ability to trade, adequately accounts for remaining useful lives of
facilities. In essence, it allows the facilities to comply with the
federal plan through the purchase or acquisition of ERCs or allowances,
and to avoid the need to make costly investments in control technology
for plants that have short remaining useful lives.\37\ For these
reasons, the federal plan adequately considers ``remaining useful
lives.'' We invite comment on our consideration of facilities'
``remaining useful lives'' in the federal plan.
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\37\ In addition, the ability to generate ERCs for sale or to
sell unneeded emission allowances (depending on whether in a rate-
or mass-based system) may give some affected EGUs an economic
incentive to take measures to reduce emissions that otherwise would
have been uneconomical.
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H. Implications for Other EPA Programs and Rules
1. Title V Permitting
Under the proposed federal plan, title V permits for sources with
affected EGUs will need to include any new applicable requirements that
the plan places on the affected EGUs. The EPA, however, is not
proposing any permitting requirements independent of those that would
be required under title V of the CAA and the regulations implementing
title V, 40 CFR parts 70 and 71.\38\ All major stationary sources of
air pollution and certain other sources are required to apply for title
V operating permits that include emission limitations and other
conditions as necessary to assure compliance with applicable
requirements of the CAA, including the requirements of an applicable
CAA section 111(d) state plan or federal plan. CAA sections 502(a) and
504(a), 42 U.S.C. 7661a(a) and 7661c(a). The ``applicable
requirements'' that must be addressed in title V permits are defined in
the title V regulations, and include requirements under CAA section
111(d) (40 CFR 70.2 and 71.2 (definition of ``applicable
requirement'')).
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\38\ Part 70 addresses requirements for title V programs
implemented by state, local, and tribal governments, and part 71
governs the title V program implemented by the EPA or delegate
agencies in areas under federal jurisdiction, such as Indian
country.
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The EPA anticipates that, given the nature of the units covered by
the proposed federal plan, most of the sources at which they are
located are already or will be subject to title V permitting
requirements. For sources subject to title V, the requirements
applicable to them under the proposed federal plan will be ``applicable
requirements'' under title V and, therefore, will need to be addressed
in the title V permits. For example, requirements under the proposed
federal plan concerning designated representatives, monitoring,
reporting, and recordkeeping, the requirement to either meet an
emission rate (including through holding ERCs (rate-based approach)),
or to hold allowances covering emissions (mass-based approach) will be
``applicable requirements'' to be addressed in the permits.
The EPA does not believe this approach is affected by the Supreme
Court's decision in Utility Air Regulatory Group v. U.S. EPA, 134 S.
Ct. 2427 (June 23, 2014). The Supreme Court held that the EPA may not
treat GHGs as an air pollutant for purposes of determining whether a
source is a major source required to obtain a title V operating permit.
In accordance with that decision, the D.C. Circuit's amended judgment
on April 10, 2015 vacated the title V regulations under review in that
case (40 CFR 70.12 and 71.13) to the extent that they require a
stationary source to obtain a title V permit solely because the source
emits or has the potential to emit GHGs above the applicable major
source thresholds. The D.C. Circuit also directed the EPA to consider
whether any further revisions to its regulations are appropriate in
light of UARG v. EPA, and, if so, to undertake to make such revisions.
As the agency made clear in a memorandum to Regional Administrators
last year, ``While the EPA will no longer apply or enforce the
requirement that a source obtain a title V permit solely because it
emits or has the potential to emit GHGs above major source thresholds,
the agency does not read the Supreme Court decision to affect other
grounds on which a title V permit may be required or the applicable
requirements that must be addressed in title V permits.'' \39\
Accordingly, while the emission of GHGs alone cannot trigger the need
for a title V permit under UARG, the EPA believes a final federal plan
under CAA section 111(d) will create new ``applicable requirements'' in
the form of an emission standard (either an emission rate or an
allowance system) and related requirements for GHGs (here,
CO2) on affected EGUs. See 40 CFR 70.2, 71.2 (definition of
``applicable requirement'' includes ``any standard or other requirement
under section 111 of the Act, including section 111(d)'') (emphasis
added). Thus, an affected EGU may be required to modify its existing
title V permit, or obtain a new permit if it does not already have one,
if it becomes subject to an emission standard for CO2 under
a CAA section 111(d) federal plan.
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\39\ Memorandum from Janet McCabe, Acting Assistant
Administrator, Office of Air and Radiation, and Cynthia Giles,
Assistant Administrator, to Regional Administrators, Regions 1-10,
at 5 (July 24, 2014).
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The title V permits program is structured to provide flexibility
for market-based approaches, such as allowance trading programs under
the federal plan, including flexibility to make changes under such
programs without necessarily requiring a formal permit revision. For
example, the title V regulations provide that a permit issued under
title V shall include, for any ``approved * * * emissions trading or
other similar programs or processes'' applicable to the source, a
provision stating that no permit revision is required ``for changes
that are provided for in the permit.'' 40 CFR 70.6(a)(8) and
71.6(a)(8). Consistent with this provision in the title V regulations,
the proposed federal plan regulations include a provision stating that
no permit revision shall be required for the allocation, holding,
deduction, or transfer of allowances once the requirements applicable
to such allocations, holdings, deductions, or transfers of
CO2 allowances are already incorporated in such permit.
Consistent with title V regulations, this provision should be included
in each title V permit for a covered source. As a result, allowances
will be able to be traded (or allocated, held, or deducted) under the
federal plan without a revision of the title V permit of any of the
sources involved.
As a further example of flexibility under title V, and consistent
with 40 CFR 70.7(e)(2)(i)(B) and 40 CFR 71.7(e)(1)(i)(B), the EPA is
proposing that any changes that may be required to an operating permit
with respect to a trading program under the federal plan may be made
using the minor permit modification procedures of the title V rules.
The EPA proposes that such changes may include the initial changes
needed to the title V permit to establish the applicability of the
trading program to the source, specify the covered units, and to
include other permit terms that may be needed for implementation,
including the general approach for monitoring and reporting. The minor
permit modification procedures could also be used for any subsequent
changes
[[Page 64985]]
to permit terms that may be needed with respect to the trading program,
although we expect such changes to be infrequent. As noted above, once
a trading program has been established in the permit, there may be
transactions, such as individual trades, that will require no formal
permit modification procedures because such trading would be already
addressed and allowed by the permit (``provided for in the permit'')
provided the changes do not conflict with any existing terms of the
permit. If a source wishes to make a change that would go against any
express term of the permit, the permit must be revised to allow such a
change before the source begins operation of the change. Under the
implementation strategy described above, the EPA believes it would be
unlikely that any change in trading allowances would violate a term of
a permit, but this principle is important to keep in mind when deciding
if a minor permit modification is appropriate with respect to operating
a trading program in the context of a title V permit.
The EPA believes that the approach to permitting requirements we
are proposing here, which imposes no additional permitting requirements
independent of title V and provides for the use of minor permit
modification procedures, will streamline the process for sources
already required to be permitted under title V and for permitting
authorities. If there are any sources that would become newly subject
to title V as a result of the requirements of this proposed federal
plan, the initial title V permit that would be issued pursuant to 40
CFR 70.7(a) or 71.7(a) would address the federal plan requirements,
when finalized.
The EPA notes that the approach to title V permitting that is being
proposed is somewhat similar to the approach adopted in the final
CSAPR. See 76 FR 48299-48300 (August 8, 2011). The agency recently
issued guidance to assist permitting authorities and sources subject to
CSAPR in incorporating CSAPR requirements into title V permits.\40\ The
EPA invites comment on its proposed approach to permitting requirements
for the federal plan, including whether it would be of use to develop
guidance similar to the guidance developed for permitting under CSAPR.
The EPA invites comment on its proposed approach to incorporating
applicable requirements of the federal plan into title V permits and
revising those requirements, including specifically seeking comment on
whether all requirements should be eligible for incorporation into
title V permits via minor modification procedures or if only a
specified subset of such requirements should be eligible for such
procedures.
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\40\ Memorandum from Anna Marie Wood, Director, Air Quality
Policy Division, Office of Air Quality Planning and Standards
(OAQPS), and Reid P. Harvey, Director, Clean Air Markets Division,
Office of Atmospheric Programs (OAP), to Regional Air Division
Directors, 1-7, regarding Title V Permit Guidance and Template for
the Cross-State Air Pollution Rule (May 13, 2015).
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The EPA also notes that the applicable requirements of this
proposed federal plan would apply to a source and are independently
enforceable regardless of whether they have yet been included in the
source's Title V permit.
2. Implications for New Source Review Program
The NSR program is a preconstruction permitting program that
requires major stationary sources of air pollution to obtain permits
prior to beginning construction. The requirements of the NSR program
apply both to new construction and to modifications of existing major
sources. Generally, a source triggers these permitting requirements as
a result of a modification when it undertakes a physical or operational
change that results in a significant emission increase and a net
emissions increase. NSR regulations define what constitutes a
significant net emissions increase, and the concept is pollutant-
specific.
In the final EGs, the EPA recognized that, as part of its CAA
section 111(d) plan, a state may impose requirements that require an
affected EGU to undertake a physical or operational change to improve
the unit's efficiency that results in an increase in the unit's
dispatch and an increase in the unit's annual emissions. If the
emissions increase associated with the unit's changes exceeds the
thresholds in the NSR regulations for one or more regulated NSR
pollutants, including the netting analysis, the changes would trigger
NSR. We noted that while there may be instances in which an NSR permit
would be required, we expect those situations to be few.
The EPA believes the analysis of NSR applicability is basically the
same for sources under a CAA section 111(d) federal plan. That is, it
is conceivable that a source under a federal plan may choose, as a
means of compliance with either a rate-based or mass-based approach, to
undertake a physical or operational change to improve an affected EGU's
efficiency that results in a significant net emissions increase of a
regulated NSR pollutant. This would trigger NSR. However, as with state
plans, the EPA believes that these situations will be few.
After the proposal for the Clean Power Plan was published in June
of 2014, the U.S. Supreme Court issued its opinion in UARG v. EPA, 134
S. Ct. 2427 (June 23, 2014). The Supreme Court held that an increase in
GHG emissions alone cannot by law trigger the NSR requirements of the
PSD program under section 165 of the CAA. On remand from the Court, the
DC Circuit issued an amended judgment in Coalition for Responsible
Regulation, Inc. v. Environmental Protection Agency, Nos. 09-1322, 10-
073, 10-1092 and 10-1167 (D.C. Cir., April 10, 2015), vacating the
relevant regulations. Therefore, increases in emissions of GHGs alone,
including those that may occur through actions taken at sources to
comply with the proposed federal plan (such as may occur when an NGCC
unit increases its operations due to generation shift from a SGU),
cannot trigger NSR.
The EPA will invite comment on potential scenarios in which
affected EGUs, particularly small entities, could be subject to the
requirements of the NSR program as a result of taking compliance
measures under the federal plan, and any ideas for harmonizing or
streamlining the permitting process for such sources that are
consistent with judicial precedent. However, the EPA is not proposing
any changes to the NSR program in this action, and the agency is not
reopening or reconsidering any prior actions or determinations related
to NSR in this action. Any comments related solely to the NSR program
will be considered outside the scope of this proposed rule.
3. Interactions With Other EPA Rules
Existing fossil fuel-fired EGUs, such as those covered in this
proposal, are or will be potentially impacted by several other rules
recently finalized or proposed by the EPA.\41\ These rules include the
Mercury and Air Toxics Standards (MATS) (77 FR 9304; February 16,
2012); \42\ the CSAPR; Requirements for Cooling Water Intake Structures
at Power Plants (79 FR 48300; August 15, 2014); Disposal of Coal
Combustion Residuals from Electric Utilities, promulgated on April 17,
2015 (80 FR 21302); and the
[[Page 64986]]
proposed Steam Electric Effluent Limitation Guidelines and Standards
(78 FR 34432; June 7, 2013). These rules are discussed in more detail
in the final EGs along with steps the EPA is taking to enable
compliance with obligations under other power sector rules as
efficiently as possible. We solicit comment on whether there are
specific things the EPA can do in the design and implementation of the
federal plan that further this objective.
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\41\ We discuss other rulemakings solely for background
purposes. The effort to coordinate rulemakings is not a defense to a
violation of the CAA. Sources cannot defer compliance with existing
requirements because of other upcoming regulations.
\42\ The Supreme Court recently reversed and remanded a DC
Circuit Court of Appeals decision that had upheld the MATS rule.
Mich. v. EPA, No. 14-46 (S. Ct. filed June 29, 2015). The Court did
not vacate the rule, however, and it remains in effect.
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I. Administrative Appeals Process
Under either a rate-based or mass-based trading program, the EPA
anticipates that there may be situations in which individual parties
are affected by decisions of the agency. For example, under a rate-
based plan, a determination may be made that an eligibility application
by an ERC provider is denied. And, for set-asides in the mass-based
program, an affected EGU may believe that its allowance allocation
amount was miscalculated. Similar to prior trading programs, the agency
believes it would be efficient and potentially avoid the need for
recourse to litigation to provide an administrative appeals process.
Therefore we are proposing, and requesting comment on, the use of the
regulations for appeals procedures set forth in 40 CFR part 78, to
provide for the adjudication of certain disputes that may arise during
the course of implementation of a federal plan under CAA section
111(d). We also propose to revise part 78 to accommodate such appeals.
The part 78 procedures cover prior CAA emission trading programs and
were specifically designed with these types of disputes in mind.
The persons eligible to file such appeals would be designated
representatives as defined in this proposed rule and other ``interested
persons'' as defined in part 78. The filing of an appeal and the
exhaustion of administrative remedies under part 78 would be a
prerequisite to seeking judicial review. For purposes of judicial
review, final agency action would occur only when an agency decision
under the federal plan listed as appealable under part 78 has been
issued, and the procedures of part 78 for appealing the decision are
exhausted.
The actions we propose to list as appealable under the part 78
procedures are as follows:
In the case of the rate-based federal plan: Decisions on an
eligibility application for ERCs; decisions regarding the number of
ERCs generated; decisions on the transfer of ERCs; decisions on the
disallowance of ERCs for compliance; decisions that there has been an
excess of emissions requiring a 2-for-1 ERC administrative compliance
penalty; decisions regarding deduction or surrender of ERCs for
compliance from affected EGUs' compliance accounts; decisions on the
accreditation of independent verifiers; the use of error corrections
regarding information submitted by ERC providers, affected EGUs, or
other ERC account holders; and the finalization of compliance period
emissions data, including retroactive adjustment based on audit or
other investigation.
In the case of a mass-based federal plan: Decisions on an
eligibilty application for set-aside allowances; decisions regarding
the allocation of allowances to affected EGUs; decisions regarding the
allocation of allowances from set-asides; decisions on the transfer of
allowances; decisions regarding the finalization of emissions data by
affected EGUs during compliance periods; decisions making error
corrections to information submitted by affected EGUs and other account
holders; decisions that there has been excess emissions requiring a 2-
for-1 allowance administrative compliance penalty; and decisions
regarding the deduction or surrender of allowances for compliance from
affected EGUs' compliance accounts.
We request comment on this list of actions for both types of
approaches to the federal plan, and whether there are other decisions
that may be made in the course of implementation of the federal plan
that are party-specific that would be appropriate to list as appealable
under part 78. We also request comment on whether it would be
appropriate for the EPA to finalize an administrative appeals process
that differs in any way from that offered under part 78, or in addition
to that offered under part 78. If so, we request comment broadly on all
aspects of the alternative or additional adminsitrative appeals
process, including with respect to any structural, procedural,
subtantive, and timing requirements it should include, who should have
access to it and in what manner, and how it would differ from part 78.
Finally, we request comment on whether, similar to other programs
identified in 40 CFR 78.1(a)(1), the agency should make the procedures
of part 78 available to any actions of the Administrator under the
comparable state regulations approved as a part of a state plan under
the EGs.
J. Consistency of Program Structure With Clean Air Act Authority
The EPA is co-proposing two distinct forms of emissions trading as
the mechanism for federal implementation of standards of performance
that achieve the emission performance levels determined by application
of the BSER in the Clean Power Plan EGs. Both proposals are ``emission
standard'' approaches as defined in the EGs, and the EPA is not
proposing an approach like the ``state measures'' approach that is also
available to states in the final EGs. The EPA has legal authority to
establish either of the proposed trading systems as a federal plan
under CAA section 111(d)(2). We discuss this topic briefly here and
invite public comment. The EGs discussed the role of emissions trading
in the BSER, see, e.g., section V.A of the preamble to the final EGs.
The EPA regards this to be a separate issue and is not revisiting or
reopening the discussion of the BSER or the role of trading in the BSER
here. The EGs recognize and provide ample opportunity for states to
establish standards of performance that allow the use of emissions
trading or other multi-unit compliance approaches. Here we discuss why
an emissions trading program is a lawful and appropriate form of
federal ``implementation'' of a ``standard of performance'' under CAA
section 111(d)(2). We invite comment on this legal discussion and the
agency's interpretation of its authority.
1. General Section 111(d)(2) Authority
Section 111(d)(2) provides that ``[t]he Administrator shall have
the same authority [ ] to prescribe a plan for a State in cases where
the State fails to submit a satisfactory plan as he would have under
section 7410(c) of this title in the case of failure to submit an
implementation plan . . .'' 42 U.S.C. 7411(d)(2)(A).\43\
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\43\ Section 111(d)(2) further provides that ``[i]n promulgating
a standard of performance under a plan prescribed under this
paragraph, the Administrator shall take into consideration, among
other factors, the remaining useful lives of the sources in the
category of sources to which such standard applies.'' The agency's
interpretation of the ``remaining useful lives'' provision is
discussed above in section III.G of this preamble.
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The phrase ``same authority to prescribe'' indicates that Congress
viewed the EPA's authority to issue a federal plan for designated
pollutants under CAA section 111(d) as, in some sense, co-extensive
with its authority to issue a FIP for National Ambient Air Quality
Standards (NAAQS) pollutants under CAA section 110. This authority
under CAA section 111, of course, must be understood in reference to
the purpose of that section (i.e., to achieve emission reductions for
designated pollutants from designated facilities), rather than in
reference to the purpose of CAA section 110 (i.e., to attain and
[[Page 64987]]
maintain the NAAQS). However, it has been the agency's longstanding
view that, in both procedural and substantive respects, Congress
intended that the CAA section 110 authority be looked to under CAA
section 111(d)(2). See 40 FR 53340, at 53342 (November 17, 1975) (``It
is obvious that [the Administrator] could only prescribe standards on
some substantive basis. The references to section 110 of the CAA
suggest that (as in CAA section 110) [she] was intended to do generally
what the states in such cases should have done, which in turn suggests
that (as in CAA section 110) Congress intended the states to prescribe
standards on some substantive basis. Thus, it seems clear that some
substantive criterion was intended to govern not only the
Administrator's promulgation of standards but also [her] review of
state plans.'').
Over the several decades of implementation of the CAA, the courts,
and the EPA, have addressed the nature and scope of CAA section 110
authority. See, e.g., 71 FR 25328, 25338 (May 12, 2005) (CAIR final
rule). In general, the EPA has broad power under CAA section 110(c) to
cure a defective SIP. Thus, in promulgating a FIP under CAA section
110, the EPA may exercise its own, independent regulatory authority in
accordance with CAA section 110(c) and the CAA more broadly. When the
EPA has promulgated a FIP, courts have not required explicit authority
for specific measures: ``We are inclined to construe Congress' broad
grant of power to the EPA as including all enforcement devices
reasonably necessary to the achievement and maintenance of the goals
established by the legislation.'' South Terminal Corp. v. EPA, 504 F.2d
646, 669 (1st Cir. 1974). Further, the same authority that is exercised
by the states under the CAA in connection with the adoption,
implementation, and enforcement of a SIP may be assumed to be available
to the EPA when the agency issues a FIP, after determining that a state
has not adopted a satisfactory SIP. As the Ninth Circuit has held, when
the EPA acts in place of the state pursuant to a FIP under CAA section
110(c), the EPA ``stands in the shoes of the defaulting state, and all
of the rights and duties that would otherwise fall to the state accrue
instead to EPA.'' Central Ariz. Water Conservation Dist. v. EPA, 990
F.2d 1531, 1541 (9th Cir. 1993). Accord, South Terminal, 504 F.2d at
668 (``[T]he Administrator must promulgate promptly regulations setting
forth an implementation plan for a state should the state itself fail
to propose a satisfactory one. The statutory scheme would be unworkable
were it read as giving to the EPA when promulgating an implementation
plan for a state, less than those necessary measures allowed by
Congress to a state to accomplish federal clean air goals. We do not
adopt any such crippling interpretation.'').
By the same token, if there are clear limits to the EPA's CAA
section 110(c) authority, those too, would arguably carry over to CAA
section 111(d)(2). For instance, CAA section 110(c)(1) ties the EPA's
authority to promulgate a final FIP for a state to the EPA's predicate
action on a SIP (or lack thereof): Generally, either an action
disapproving a plan, or a finding that a state has failed to submit a
plan. However, even here, as the Supreme Court has recognized, ``the
plain text of the CAA grants EPA plenary authority to issue a FIP `at
any time' within the 2-year period that begins the moment EPA
determines a SIP to be inadequate.'' EPA v. EME Homer City Generation,
134 S. Ct. 1584, 1602 n.14 (2014).
Congress gave the EPA the same authority to prescribe a plan under
CAA section 111(d)(2) as it possesses under CAA section 110(c). The EPA
believes this authority is the ``same'' in the sense described above
and in the case law.\44\ The scope of the EPA's action to undertake a
FIP under CAA section 110 is informed by the scope of the state's
action to undertake a SIP; likewise, the scope of the EPA's action to
undertake a federal plan under CAA section 111(d) is informed by the
scope of the state's action to undertake a state plan.
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\44\ We interpret the cross-reference to be to the currently
enacted version of CAA section 110(c), rather than to a prior
version. As discussed in section VII of this preamble, below, the
current version of CAA section 110, including subsection (c),
reflects changes made in the 1990 Amendments based on experience
gained in the first two decades of the CAA's implementation. The
statute and legislative history do not expressly address the
question, but there is no indication Congress would have intended to
prevent these improvements from being available under CAA section
111 as well.
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The agency received comments on the proposed EGs from commenters
who stated that the EPA cannot require states to implement the building
blocks that make up the BSER; for example, ordering re-dispatch to
natural gas-fired units, or ordering the construction of RE projects.
These commenters went on to say that the EPA itself would have no
authority to order these types of actions under a federal plan. As we
explained in the Legal Memorandum for the final EGs, and reiterate
here, the premise of these comments is incorrect. The EPA is not
requiring the implementation of the BSER or the building blocks in the
EGs. Even where the EPA is directly implementing standards of
performance in a federal plan, the agency will not, and need not,
attempt to order sources to implement the measures that comprise the
BSER. Rather, as set forth in the co-proposed federal plans discussed
in sections IV and V of this preamble, the EPA would set emission
standards for each of the affected EGUs in the federal plan state,
provide mechanisms for their implementation and enforcement, and
otherwise leave to the owners and operators of the affected EGUs the
decisions about what measures they want to take to comply with the
emission standard. Though the emission standards will be federally
enforceable, as under a state plan, sources may achieve them through
implementation of measures in the BSER, or any other method.
Thus, the question whether the EPA would have the authority to
directly order the implementation of the measures in the building
blocks in this proposed federal plan is not only not relevant but
represents a categorical misunderstanding of the nature of the BSER in
relation to the imposition of standards of performance under a CAA
section 111(d) plan. To illustrate this, by the same token the EPA
could not enforce many logistical aspects of a control requirement such
as a scrubber--for instance, the EPA does not need to assert the
authority to order into existence companies that manufacture scrubbers,
or order their construction or delivery on a certain schedule. The EPA
need not in setting emission standards have before it all of the
information regarding manufacturing, transportation of parts, or other
logistical requirements to ensure that each scrubber gets constructed
and delivered to a source. Similarly, the EPA here does not, and need
not, propose an implementation approach of directly intervening to re-
dispatch certain units, construct new RE projects, or take other
measures, either included in the BSER or not. The agency determined the
BSER and emission performance levels in the EGs on a reasonable
assumption that all of those things can actually happen. In providing
for the implementation of federally enforceable standards of
performance in the federal plan proposed in this action, the agency is
ensuring that these things will happen.
2. Use of Market Techniques To Implement Standards of Performance Under
the Clean Air Act
The use of market techniques such as emission trading is well-
supported in the CAA and has many regulatory precedents. The EPA
discussed this history, and the reason why trading is a supportable
method of
[[Page 64988]]
implementation of standards of performance under CAA section 111(d) in
the EGs. See section V.A of the final EGs. Here we supplement that
discussion with respect to the agency's own authority under CAA section
111(d)(2) to use trading as a method of implementation of a ``standard
of performance'' in the federal plan.
The 1990 CAA Amendments added broad authorizations for the use of
market techniques in several sections of the statute, including Title
I. States were provided express authority to use such approaches in
their NAAQS implementation plans under CAA section 110(a)(2)(A): ``Each
[state] plan shall include enforceable emission limitations and other
control measures, means, or techniques (including economic incentives
such as fees, marketable permits, and auctions of emissions rights) . .
. .'' 42 U.S.C. 7410(a)(2)(A). The EPA was given similar authority in
the definition of a ``Federal Implementation Plan'' in CAA section 302,
which defines that term as an EPA-promulgated plan, which ``includes
enforceable emissions limitations or other control measures, means or
techniques (including economic incentives, such as marketable permits
or auctions of emissions allowances), and provides for attainment of
the relevant national ambient air quality standard.'' 42 U.S.C.
7602(y). Section 111(d)(2) of the CAA provides the EPA the same
authority to prescribe a federal plan under CAA section 111 as it would
have to promulgate a FIP under CAA section 110(c). Thus, the EPA
believes the plain language of the statute authorizes the use of market
techniques in CAA section 111(d) federal plans.
However, even if one were to view this language as not wholly
unambiguous with respect to the scope of federal authority under CAA
section 111, the EPA believes that CAA section 111, in conjunction with
authorizations and endorsements of market techniques throughout the
CAA, and other indicia of congressional intent, strongly support the
view that market techniques are within the EPA's authority to
promulgate a federal plan under CAA section 111(d).
Case law throughout the history of the CAA has generally confirmed
the legal viability of emissions trading as an implementation measure
so long as the trading ultimately achieves the emission reduction goals
of the statute. See, e.g., Sierra Club v. EPA, No. 12-3169 (6th Cir.
Filed March 18, 2015), Slip Op. at 11-14 (upholding EPA approval of
redesignation of area to attainment on basis that reductions in
emissions from cap-and-trade programs (NOX SIP Call, CAIR,
and CSAPR) are permanent and enforceable). Chevron, U.S.A., Inc. v.
Natural Res. Def. Council, Inc., 467 U.S. 837 (1984) (``Chevron''), the
seminal case establishing the Supreme Court's standard of review of
agency interpretations of the statutes they administer, upheld one of
the EPA's early emissions trading programs, the Netting Rules of 1980
(45 FR 52676; August 7, 1980), which the EPA in its discretion chose to
allow states to apply in both attainment and nonattainment areas (46 FR
50766; October 14, 1981). The Netting Rules allowed existing major
sources to modify without triggering certain requirements of PSD or
nonattainment NSR, so long as any increase in emissions associated with
the modification is compensated for by a corresponding decrease in
emissions elsewhere within the same facility, such that there is no
significant net increase in emissions from the facility as a whole. In
upholding this approach in Chevron, the Supreme Court gave deference to
the EPA's definition of the term ``source,'' finding in that term
sufficient ambiguity to support the agency's reasoned application of an
emissions averaging approach for total pollution emitted from the
source. See EPA v. EME Homer City, 134 S. Ct. 1584, 1603 (2014)
(``Because `a full understanding of the force of the statutory policy .
. . depend[s] upon more than ordinary knowledge' of the situation, the
administering agency's construction is to be accorded `controlling
weight unless . . . arbitrary, capricious, or manifestly contrary to
the statute.' '') (quoting Chevron, 467 U.S. at 844).\45\
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\45\ The EPA is not aware of any case since at least the Chevron
decision in which a trading program under the CAA was invalidated
simply by virtue of being a trading program. The CAIR trading
program was set aside by the DC Circuit because the court held it
did not accomplish the objective of the Good Neighbor provision of
the CAA, not because it used a trading approach per se. North
Carolina v. U.S. EPA, 531 F.3d 896, 921 (D.C. Cir. 2008). More
recently the Supreme Court upheld key portions of the CSAPR trading
program that replaced CAIR in EPA v. EME Homer City, 134 S. Ct. 1584
(2014).
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With the increasing recognition of the utility of trading,
crediting, and averaging to meet emission reduction goals efficiently,
the EPA set forth a comprehensive policy on trading in 1986. Emissions
Trading Policy Statement; General Principles for Creation, Banking and
Use of Emission Reduction Credits, 51 FR 43814 (December 4, 1986)
(hereinafter ``ERC Policy''). In the ERC Policy, the EPA stated that it
``endorses emissions trading and encourages its sound use by states and
industry to help meet the goals of the CAA more quickly and
inexpensively.'' At the same time, based on lessons learned from its
earlier 1982 trading policy, the EPA took steps to tighten its policies
on the use of ``bubbles'' to ensure environmental integrity of trading,
particularly in nonattainment areas. The agency emphasized the
requirements of enforceability, tracking (and preventing double-
counting), determining the appropriate baseline from which to measure
emissions, and demonstration of actual air quality benefits.
The use of an emissions trading system for CO2
reductions for affected EGUs under CAA section 111(d) is also analogous
to the trading system for chlorofluorocarbons (CFCs) under the pre-1990
CAA provision for control of stratospheric ozone depleting substances.
This program was reviewed by the Office of Legal Counsel (OLC) within
the Department of Justice in 1989. See Memorandum for Alan Raul,
General Counsel, Office of Management and Budget, from the Office of
the Assistant Attorney General (April 14, 1989) (hereinafter ``OLC
Memo'').\46\ The OLC was asked by OMB to opine whether a general grant
of regulatory authority to the EPA to ``control'' CFCs was sufficient
to authorize an emissions fee or a cap-and-trade system, including
auction, of tradable allowances. The statute authorized the EPA to
issue regulations ``for the control of any substance, practice,
process, or activity (or any combination thereof) which in his judgment
may reasonably be anticipated to affect the stratosphere, especially
ozone in the stratosphere, if such effect in the stratosphere may
reasonably be anticipated to endanger public health.'' Former CAA
157(b) (as enacted in the 1977 CAA amendments). The Office of Legal
Counsel concluded that this language--which it characterized as
``plain,'' ``unambiguous,'' and ``sweeping''--was sufficient to
authorize the EPA to establish a cap-and-trade program with auction for
CFCs. See id. at 7 (``It cannot seriously be argued that the use of
economic incentives to regulate pollution is a novel or strange idea
that could not have been anticipated by the authors of the Clean Air
Act Amendments [of 1977].'') (citing multiple examples from the policy
literature as early as E. Mishan, The Costs of Economic Growth (1967)).
The OLC noted that as of 1977, ``Congress was cognizant of economic
forms of regulation, did not prohibit them, but instead used general
language
[[Page 64989]]
permitting a wide scope of regulatory measures for the control of
CFCs.'' To interpret the general authority of this section of the CAA
as affirmatively prohibiting market incentives would be, in the OLC's
words, to read into the statute the italicized clause ``regulations for
the control [of CFCs] by traditional command and control or
specification standard methods,'' id. at 9--a rewriting ``unwarranted
in any case, but especially so where Congress was aware of economic
methods of control and where such methods so ably serve the underlying
purposes of the statute.'' Id.
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\46\ A copy of this memorandum has been placed in the docket for
this rulemaking.
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By the time of the 1990 CAA Amendments, as discussed above,
Congress was comfortable enough with the efficacy of market techniques
that they were broadly authorized for use in SIPs and FIPs for NAAQS.
See 42 U.S.C. 7410(a)(2)(A), 7602(y). In the wake of the 1990
Amendments, the EPA issued an ``Implementation Strategy for the Clean
Air Act Amendments of 1990.'' \47\ This Strategy included as one of
nine overarching implementation principles, ``Market-based: Use of
market-based approaches and other innovative strategies to creatively
solve environmental problems.'' Further, it announced that the EPA
would make ``full use of innovative market-based approaches,'' and that
the agency will supplement traditional approaches with broader use of
market incentives and other innovative approaches ``whenever
possible.'' Id. at 3, 9.
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\47\ U.S. EPA, Office of Air and Radiation, Implementation
Strategy for the Clean Air Act Amendments of 1990 (Update, 1992)
(July 1992), 400-K-92-004.
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Since the 1990 Amendments, the EPA has established three of its
most robust trading programs--the Federal NOX Budget Trading
Program (65 FR 2674; January 18, 2000), the CAIR (71 FR 25328; April
28, 2006), and the CSAPR (76 FR 48208; August 8, 2011), under CAA
section 110(a)(2)(D)(i)(I), relating to air pollution that causes
nonattainment or interference with maintenance of air quality standards
in downwind states.\48\
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\48\ The EPA notes that complications that arise with respect to
assigning a ``significant contribution'' among upwind states for
NAAQS pollutant levels in downwind states, and designing a trading
regime that accomplishes Good Neighbor objectives, are not present
with respect to CO2, which is a global pollutant;
emission reductions anywhere contribute to the environmental
objective of addressing climate change.
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As noted in the rulemaking action for the final EGs, the EPA has
instituted or authorized the use of emissions trading programs twice in
the past under CAA section 111(d). The EPA authorized NOX
emissions averaging or trading within or between facilities under the
Municipal Waste Combustors EGs in 1995. 60 FR 65387, 65402 (December
19, 1995) (codified at 40 CFR 60.33b(d)(1) and (2)). The EPA also
developed a cap-and-trade system for mercury under CAA section 111(d)
in the Clean Air Mercury Rule (CAMR). 70 FR 28606 (May 18, 2005). The
EPA proposed a federal plan for trading that was identical in all
relevant respects to the CAMR rule. 71 FR 77100 (December 22, 2006).
However, CAMR was vacated by the D.C. Circuit on grounds unrelated to
the establishment of a trading system for implementation before the
CAMR federal plan could be finalized. New Jersey v. EPA, 517 F.3d 574
(D.C. Cir. 2008).\49\
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\49\ The CAMR program was vacated because the EPA had not made
requisite findings under CAA section 112(c)(9) in delisting EGUs
with respect to emissions of a hazardous air pollutants (HAP). No
such procedural concern is present here with respect to
CO2, which is not a HAP under CAA section 112.
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The agency believes these legal and administrative precedents for
federal trading programs under the CAA going back decades amply support
its decision to propose two forms of emission trading as the method of
implementation of the Clean Power Plan EGs in the federal plan.
Notably, emissions trading is particularly appropriate with respect to
a global pollutant such as CO2 that is well-mixed in the
atmosphere and does not have direct, acute health impacts due to
inhalation at ambient levels.\50\
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\50\ We recognize that some commenters on the EGs raised
concerns about the localized impacts that may occur from the
potential for concentrations of co-pollutants associated with
CO2 emitted from affected EGUs. We address those concerns
in the communities sections of the final EGs, at section IX, and in
this preamble in section IX below.
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Finally, the Supreme Court has affirmed the breadth of the agency's
discretion under CAA section 111(d) to select the method by which it
would control CO2 emissions from existing power plants. See
AEP v. Connecticut, 131 S. Ct. 2527, 2538 (2011) (``Congress delegated
to EPA the decision whether and how to regulate carbon-dioxide
emissions from power plants.'') (emphasis added); see also id. at 2539
(``The appropriate amount of regulation in any particular GHG-producing
sector cannot be prescribed in a vacuum: As with other questions of
national or international policy, informed assessment of competing
interests is required. Along with the environmental benefit potentially
achievable, our Nation's energy needs and the possibility of economic
disruption must weigh in the balance. The CAA entrusts such complex
balancing to the EPA in the first instance, in combination with state
regulators.'').
This proposal is guided by the relevant cases and the experiences
of the agency in implementing the CAA trading programs discussed above.
The EPA invites comment on this discussion and the agency's
interpretation that CAA section 111(d)(2) authorizes the two approaches
to a federal plan proposed here.
IV. Rate-Based Implementation Approach
A. Overview
The EPA's federal plan requirements for CO2 from
affected EGUs implement the EGs as previously discussed. In this
federal plan and model rule proposal the EPA is proposing, as one
option, rate-based emission standards (i.e., the emission standard
approach) for affected EGUs not covered by an approved state plan as
specified in the Clean Power Plan. The EPA is proposing to apply the
subcategorized emission rates in this federal plan proposal. These
rate-based emission standards are consistent with, and would satisfy,
the degree of emission limitation achieved by the BSER determination
made in the final Clean Power Plan EGs, which included subcategorized
CO2 emission performance rates for affected EGUs to meet
during the plan performance periods. An affected EGU subject to this
federal plan will demonstrate compliance by achieving a stack emission
rate less than or equal to the rate-based emission standard or by
applying ERCs, acquired by the EGU, to its measured stack emissions
rate. The application of ERCs by an affected EGU to comply with an
emission standard has been determined in the final Clean Power Plan as
a mechanism available to affected EGUs with a CO2 emission
rate greater than its respective performance rate to meet compliance
obligations, see section VIII.K of the final EGs. Under a rate-based
federal plan, the EPA would act as the state described in section
VIII.C.1.a of the final EGs with the EPA acting as the issuer of ERCs,
and otherwise implementing and enforcing the standards of performance
for affected EGUs subject to the federal plan.
This section describes the proposed rate-based federal plan and
model trading rule and how each would be designed and operated,
consistent with the EGs. For the federal plan, the EPA is proposing to
limit the issuance of ERCs to designated categories of affected EGUs
and to RE resources and nuclear generation (from new capacity and
incremental capacity uprates) that are
[[Page 64990]]
measured by a revenue quality meter, rather than the full suite of
options discussed in the EGs. The EPA requests comment on whether to
limit the scope of the federal plan in this manner, and if not, what
other sources of low- or zero-emitting electricity in federal plan
states should also be eligible to generate ERCs for compliance
purposes. For both the proposed federal plan and model rule, the EPA
requests comment on which EM&V plan, measurement and verification (M&V)
report, and verification report requirements should apply for each
eligible resource. Further discussion of non-BSER measures that may be
eligible to generate ERCs can be found in the Clean Power Plan and
section IV.C.3 of this preamble. (The EPA is not reopening its
determination of the BSER.)
B. Rate Goals
In the Clean Power Plan the EPA identified a rate-based ``emission
standards'' approach as an approvable method for state plans to
implement the final EGs. In this approach the requirements for
compliance rest solely on affected EGUs in the form of federally
enforceable emission standards expressed as a rate of emissions of
CO2 per unit of energy output. In the Clean Power Plan, the
EPA established, through application of the BSER, separate
CO2 emission performance rates for affected EGUs in two
subcategories. The two subcategories are natural gas-fired stationary
combustion turbines (i.e., natural gas combined cycle units, or NGCC
units) and fossil fuel-fired EGUs (i.e., utility boilers and IGCC).\51\
The CO2 emission performance rates set in the Clean Power
Plan are reflected below in Table 6 of this preamble. The EPA is
proposing to apply these rates in the rate-based federal plan as the
emission standards for NGCC units, and SGUs, respectively. For a
thorough discussion of affected EGU category-specific CO2
emission performance rates and rationale, see section VI of the final
EGs. These calculated standards and the premises that these standards
are based on are not within the scope of comment in this rulemaking as
they were finalized in the Clean Power Plan.
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\51\ For simplicity, affected utility boilers and IGCC will
collectively be called ``steam generating units.''
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As discussed in section III.D of this preamble above, the EPA
proposes to implement a compliance schedule for the rate-based federal
plan with multi-year compliance periods as follows: A 3-year period
(2022 through 2024), followed by a 3-year period (2025 through 2027),
followed by a 2-year period (2028 and 2029), for the Interim Period;
and, commencing in 2030, successive 2-year compliance periods for the
Final Period. In the Clean Power Plan, the EPA established
CO2 emission performance rates for the subcategories of
affected EGUs for the performance periods. The EPA proposes to use
those emission performance rates promulgated in the Clean Power Plan as
the rate-based emission standard for the respective EGUs that would
become subject to this proposed federal plan if finalized. The EPA is
not opening for comment the determinations made in the Clean Power Plan
of each subcategorized CO2 emission performance rates. The
rate-based emission standards for respective EGU types are provided for
convenience in Table 6 of this preamble.
The EPA is proposing to use a glide path during the Interim Period
for EGUs to provide a smooth transition to the final compliance periods
after 2030. This approach is established in the final EGs. In Table 6
of this preamble, the applicable standards for each interim compliance
period are listed.
Table 6--Glide Path Interim Performance Rates (Adjusted Output-Weighted-Average Pounds of CO2 per Net MWh From
All Affected Fossil Fuel-Fired EGUs)
----------------------------------------------------------------------------------------------------------------
2022-2024 2025-2027 2028-2029
Technology Compliance Compliance Compliance Final rate
rate rate rate
----------------------------------------------------------------------------------------------------------------
SGU or IGCC..................................... 1,671 1,500 1,380 1,305
Stationary combustion turbine................... 877 817 784 771
----------------------------------------------------------------------------------------------------------------
The EPA is using the subcategorized rates in the rate-based trading
approach because it allows ERCs to be fungible across jurisdictional
borders and provides an incentive structure, as compared to other rate-
based approaches, that facilitates implementation of measures
identified as part of the BSER. Using subcategorized rates allows for:
(1) Consistently applied emission rates for power plants of different
types; and (2) free trading of fungible ERCs among all affected EGUs
subject to the federal plan and within the federal trading program. The
EPA solicits comments on whether the subcategorized rate approach is
the preferred rate-based approach for the federal plan and model
trading rule.\52\ If a subcategorized approach for a rate-based model
rule and federal plan is not preferred by commenters, the EPA requests
comment on the perceived benefits of an alternative rate or set of
rates (e.g., applying a uniform rate, i.e., the state goal, to all
affected units within the state as the EGUs' emission standard).
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\52\ Note that the values of limits and determinations made as
the BSER are not open for comment.
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C. Crediting Mechanism
Under a rate-based emission standard approach in the federal plan,
we are proposing that EGUs subject to the emission performance
requirements for GHGs will either need to emit at or below their rate-
based emission standard, or they will need to acquire ERCs to achieve
compliance. An ERC is a tradable compliance unit representing one MWh
of electric generation (or reduced electricity use) with zero
associated CO2 emissions. These ERCs may then be used to
adjust the measured and reported CO2 emission rate of an
affected EGU when demonstrating compliance with a rate-based emission
standard. For each ERC, one MWh is added to the denominator of the
reported CO2 emission rate, resulting in a lower adjusted
CO2 emission rate.
Under this proposed federal plan, ERCs will be issued by the EPA to
four categories of entities: (1) Affected EGUs that perform at a rate
below the applicable rate-based emission standard; (2) affected NGCC
units for all generation (represents shifting generation from SGUs to
NGCC units, as anticipated under Building Block 2); (3) new nuclear
units and capacity uprates at existing nuclear units; and (4) RE
providers that develop metered projects and programs whose results, in
MWh, are quantified and verified according to
[[Page 64991]]
EM&V criteria as described below in section IV.D.8 of this preamble. We
are also discussing in this preamble, requesting comment for the
federal plan, and proposing for the model trading rule a potential
fifth category: Other low- and zero-emitting non-BSER measures that are
described in section IV.C.3 of this preamble. The concept of using an
ERC as a crediting mechanism to meet compliance obligations is
consistent with the Clean Power Plan EGs and is being adopted in this
federal plan.\53\
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\53\ The use of ERCs and definition as a compliance mechanism to
meet the BSER emission performance rates is established in section
VIII.K of the final EGs.
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Because the goal of this rulemaking is the actual reduction of
CO2 emissions, it is fundamental that ERCs represent the MWh
of energy generation or savings they purport to represent. To this end,
only valid ERCs that actually meet the standards articulated in this
rule may be used to satisfy any aspect of compliance by an affected EGU
with emission standards. The responsibility for the validity of the ERC
rests with the affected EGU. Despite safeguards included in the
structure of ERC issuance and tracking systems, such as the review of
eligibility applications and M&V reports, and EPA issuance of ERCs,
ERCs may be issued that do not, in fact, represent eligible zero-
emission MWh as required in the EGs. A variety of situations may result
in such improper ERC issuance, ranging from simple paperwork errors to
outright fraud. The EPA requests comment on ways that the EPA could
safeguard the validity of an ERC.
1. ERCs Generated and Owed Against a Standard
The number of ERCs generated or needed for surrender by an affected
fossil fuel-fired EGU is based on the CO2 emission rate of
the EGU in comparison to a rate-based emission standard. The
calculation of ERCs generated by an EGU or needed for compliance is the
CO2 stack emission rate of the EGU subtracted from the
standard the EGU is subject to, and this value is subsequently divided
by the standard the EGU is subject to. This value is a normalized
quantity of how much better or worse the EGU is performing compared to
its standard. The normalized value is weighted by multiplying the MWh
electricity output from the EGU at that emission rate. This can be
generically expressed as:
[GRAPHIC] [TIFF OMITTED] TP23OC15.008
If the value calculated is positive, this indicates the number of
ERCs that are being generated; conversely, a negative value indicates
how many ERCs will need to be acquired to meet the unit's emission rate
for that compliance period. ERCs will be issued on an annual basis to
ERC providers (i.e., entities generating ERCs via the ERC approval and
issuance process detailed below). Surrender of ERCs for compliance by
affected EGUs will not occur until the end of the compliance period as
further described in section IV.D.10 of this preamble.
As an example, assume a steam EGU operating in the second interim
compliance period is subject to a rate standard of 1,500 lbs
CO2/MWh. Assume it operates at 2,000 lbs CO2/MWh,
and also assume it generates 1 million MWh over a compliance period.
Its total emission rate would be 2 billion lbs CO2/1 million
MWh. In order to achieve the emission standard, it would need to
purchase 333,334 ERCs (rounded to the nearest higher integer). In
essence, this quantity of ERCs represents the quantity of MWh that need
to be added to the steam EGU's denominator (i.e., generation, here, 1
million MWh), such that 2 billion pounds of CO2 (total
emissions), divided by total generation (i.e., in this case, 1,333,334
MWh) equals the emission rate for compliance (1,500 lbs/MWh).
The discussion in this subsection builds on and applies the
definition, benefits, use, and determination of using ERCs from the
final EGs (section VIII of the final EGs). We invite comment on use of
the approach just described as a method of implementation of a federal
plan and a model trading rule, and we request comment on any
alternatives to this approach that still fall within the established
criteria described in the Clean Power Plan EGs. Comments that solely
relate to determinations finalized in the EGs will be considered
outside the scope of this proposed rule.
2. Incremental NGCC ERCs
Building Block 2 (BB2) of the BSER determination in the Clean Power
Plan EGs describes shifting generation from SGUs to NGCC units because
NGCC units generate electricity at a less carbon intensive rate. BB2
describes NGCC units generating at 75 percent of the unit's annual
operating capacity. This level of generation, for most NGCC units,
would represent an increase in annual generation from a 2012 baseline.
For every hour of electricity generated by an NGCC unit beyond its 2012
baseline (i.e., incremental generation), there is a corresponding
emission reduction in the power system.\54\ The EPA is proposing to
reflect the emission reductions of BB2 by crediting all NGCC generation
on a pro rata basis that reflects expected incremental NGCC generation
to 75 percent capacity. This means that for every hour that an NGCC
unit generates electricity, it will also generate a partial credit
associated with the generation shift from fossil steam to NGCC units.
The NGCC unit will generate a partial credit because the emission
reductions associated with BB2 have been distributed on an hourly
basis. A discussion on the concepts behind the distribution of emission
reductions of incremental NGCC generation on an hourly basis can be
found at the end of this subsection.
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\54\ It is assumed that any increase in NGCC generation above
2012 levels is displacing fossil fuel-fired steam EGU generation.
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All affected NGCC generation will be credited, with ERCs, by a
factor that represents the described emission reductions from
incremental generation; ERCs credited in this way will be designated as
Gas Shift ERCs (GS-ERCs) for clarity.\55\ The collective sum of the GS-
ERCs generated realizes the amount of emission reductions described in
BB2 when 75 percent capacity is achieved. This incentive is not a
requirement, however. If NGCC units do not collectively increase to 75
percent capacity or above, the lost opportunity for ERC generation
simply will need to be achieved through other means (e.g., emissions
performance improvements at
[[Page 64992]]
affected EGUs or additional RE generation). The amount of GS-ERCs the
EPA proposes to be generated for every MWh of NGCC operation is set at
a factor relating the amount of electricity generation that NGCC units
collectively would generate at the level described in BB2 (i.e.,
reaching 75 percent capacity) and the associated emission reductions.
This means that fractional GS-ERCs are generated for every NGCC MWh and
when the interconnect region collectively reaches the level that would
be generated if all NGGC units in the region operated at a 75 percent
capacity factor there will be an amount of GS-ERCs that correlates to
the emission reductions anticipated under BB2 of the BSER. NGCC units
are expected to be incentivized to reach this level of generation in
part due to market demand for GS-ERCs. Thus, GS-ERCs have the potential
to play an important role in the sector meeting compliance obligations.
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\55\ A GS-ERC is treated and represents the same value as an
ERC, but has a compliance restriction that it can only be used by
steam generating units and not by stationary combustion turbines for
compliance obligations.
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The number of GS-ERCs that an NGCC unit generates is a combination
of three factors. The first is the GS-ERC Emission Factor. This
emission factor represents how much better an individual NGCC's
emission rate is compared against the fossil steam standard. This
measures the emission reductions because of the BB2 shift in
generation. The SGU standard used as reference here is as described
above in section IV.B of this preamble and established in the BSER
determination from the EGs of the least stringent region \56\ (i.e.,
the region with the highest calculated rate-based emission standard for
SGUs). The GS-ERC Emission Factor is expressed by taking the complement
of the ratio of the NGCC standard to the fossil-steam standard. It can
be summarized by the following expression:
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\56\ The regions that are used in the Clean Power Plan EGs and
for this proposal are the Eastern Interconnect, Western
Interconnect, and Electric Reliability Council of Texas (ERCOT).
[GRAPHIC] [TIFF OMITTED] TP23OC15.009
The second factor is the Incremental Generation Factor. This factor
represents the distribution of the increased NGCC generation across all
NGCC generation. In essence, it is prorating the incremental NGCC
generation over all NGCC generation. The Incremental Generation Factor
is calculated by taking the number of MWh beyond the 2012 baseline
needed for the corresponding region to reach 75 percent NGCC generation
capacity and dividing it by the MWh that is 75 percent NGCC generation
capacity, giving a factor. This factor can be summarized by the
following expression:
[GRAPHIC] [TIFF OMITTED] TP23OC15.010
The Incremental Generation Factor is a factor that the EPA will
calculate and will be calculated for every compliance period based on
the least stingent region's Incremental Generation Factor based on
increased utilization of RE and its replacement of fossil fuel-fired
generation (based on Building Block 3 of the Clean Power Plan EGs).\57\
For the calculation of this factor the EPA is using the least stringent
region for each compliance period and applying it for all GS-ERC
calculations subject to the federal plan. The calculations for
determinating the least stringent regional Incremental Generation
Factor can be found in the GS-ERC TSD. Table 7 of this preamble
presents the proposed values that would apply for all NGCC units to
calculate the amount of issued GS-ERCs.
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\57\ Note that per the discussion in section VI of the final
EGs, if the EPA had measured incremental NGCC generation for
reassignment to fossil steam rate as the difference from the post
building block three levels and full utilization, the post building
block three levels would be used in the numerator here, resulting in
a higher ``incremental generation factor'' and more ERCs for the
same amount of NGCC generation.
Table 7--Incremental Generation Factors for Interim and Final Compliance Periods
----------------------------------------------------------------------------------------------------------------
Corresponding incremental generation factor
-----------------------------------------------------------------------------------------------------------------
Compliance period 1 2022- Compliance period 2 2025- Compliance period 3 2028-
2024 2027 2029 2030-2031 and thereafter
----------------------------------------------------------------------------------------------------------------
0.22 0.32 0.28 0.26
----------------------------------------------------------------------------------------------------------------
The third factor in calculating an NGCC unit's generaton of GS-ERC
is the NGCC Generation. The NGCC Generation is the total net energy
output generation of the affected NGCC unit during the year that ERCs
are being calculated. The three factors combine to make the following
equation:
GS-ERCs = NGCC Generation * Incremental Generation Factor * GS-ERC
Emission Factor
The GS-ERC equation above gives the number of GS-ERCs that an NGCC
unit will generate. The Incremental Generation Factor and GS-ERC
Emission Factor combine to make the GS-ERC generating rate for the NGCC
unit. This functions by the Incremental Generation Factor prorating all
incremental NGCC generation and the GS-ERC Emission Factor designating
the proportion of the incremental NGCC generation that will generate
ERCs. The GS-ERC generating rate multiplied by the total NGCC
Generation gives the total GS-ERCs generated by the NGCC unit for the
year.
The EPA is proposing this approach, which provides GS-ERCs for all
affected EGU NGCC generation but at a fractional, pro rated level,
using the three factors above, for several reasons. This approach has
the benefit of
[[Page 64993]]
allowing NGCC units to bid into the electricity market without having
to adjust bids based on a projection of whether or not the NGCC unit
will have generation incremental to its baseline in a given year. The
proposed method also promotes the best performers within the NGCC
subcategory by crediting them with a higher rate of generating GS-ERCs,
as shown by the calculations above. The better the emission performance
of an NGCC unit, the more GS-ERCs it is capable of earning per MWh. The
proposed method also promotes and incentivizes all NGCC units,
regardless of historical generation, to continue to operate at a
greater capacity to replace steam generation. The EPA believes that
this will allow for more fluidity in the market and flexibility for
greater NGCC generation.
In the Clean Power Plan the BSER determination for subcategory
rates is calculated by using the least stringent region and applying
the standards from that region on a national level. The determination
of the BSER in the final EGs was a one-time determination and is not
being altered, updated, or changed here. Rather, in this preamble the
EPA is proposing to use the same regions and to apply the least
stringent components to an NGCC unit's GS-ERC calculation at a national
level (i.e., applying the GS-ERC calculation components that generate
the most GS-ERCs for every MWh). The EPA solicits comment on applying
the least stringent regional factor to calculate GS-ERCs for all
affected NGCC units subject to the federal plan and model rule on a
national level. Conversely, the EPA also requests comment on applying,
for each region, its own regional GS-ERC generation rate. As proposed,
the least stringent region could change from compliance period to
compliance period. The EPA requests comment on whether a single ``least
stringent'' region should be chosen and used for calculations or
whether being ``least stringent'' should be evaluated on a compliance
period by compliance period basis. The EPA also requests comment on
whether ``least stringent'' should be evaluated on a year-to-year
basis.
The EPA also requests comment on whether the GS-ERC Emission Factor
should be calculated on a unit by unit basis (as currently proposed) or
be calculated based on the least stringent region's baseline 2012
average emission rate. This will simplify the practice of calculating
and distributing GS-ERC generation, but would not reward the better
performing NGCC units within the subcategory. In the GS-ERC TSD, the
EPA used the regions' average emission rate to calculate a factor that
would credit GS-ERCs to all NGCC units subject to the federal plan. For
2030 and beyond, this value is based on the Eastern Interconnect and is
0.08 GS-ERCs/MWh. So for every MWh that an NGCC unit generates it would
be issued 0.08 GS-ERCs and, if this were the approach the EPA proposed,
this would apply to every NGCC unit that would be subject to the
federal plan.
In the GS-ERC TSD, the spreadsheet can be manipulated to show what
an individual NGCC unit's GS-ERC Emission Factor would be in the
proposed method. This is done by adjusting the cell for a year's
Average GS-ERC Emission Factor to account for the individual NGCC
unit's emission rate instead of the average NGCC emission rate.
The calculation of GS-ERCs for an NGCC unit is independent of the
calculation of ERCs generated or owed against the NGCC standard. It is
possible that an NGCC unit will owe ERCs against its assigned emission
standard for every MWh generated, but still be generating GS-ERCs. GS-
ERCs may only be used to meet steam generation units' compliance
obligations.
As an example, an NGCC unit is connected to the grid and generates
1 million MWh of electric output for the first year of the final
performance period. During this year it emits 850 million lbs of
CO2 giving it an emission rate of 850 lbs CO2/
MWh. The NGCC unit is subject to a Final Period emission rate limit of
771 lbs CO2/MWh. Since the NGCC unit is always subject to
its NGCC rate-based emission standard of 771 lbs/MWh and it is
operating at a rate above that standard it will owe non GS-ERCs for its
own compliance. The ERCs owed are calculated by solving for the number
of ERC MWh the NGCC unit will need to adjust its rate down to its
emission rate limit. This is shown in the following equation:
850,000,000 lbs CO2/[1,000,000 MWh + ERC MWh] = 771 lbs
CO2/MWh
When that equation is solved for the number of ERC MWh needed, the
NGCC unit would need to acquire 102,464 ERCs to adjust its emission
rate to its rate-based emission standard.
Additionally, the GS-ERC Emission Factor for this NGCC unit is
calculated by using 771 lbs CO2/MWh for the NGCC emission
rate and 1,404 lbs CO2/MWh for the SGU emission standard in
the equation described above.
[GRAPHIC] [TIFF OMITTED] TP23OC15.011
This calculation results in a GS-ERC Emission Factor of 0.45. This
is only an example. Because the Incremental Generation Factor is
calculated by the EPA, it can be found in the GS-ERC TSD and is
proposed to be 0.26. By using the GS-ERC Emission Factor and
Incremental Generation Factor calculated above with the NGCC unit's
generation for the year, the number of GS-ERCs for this NGCC unit can
be calculated.
0.45 * 0.26 * 1,000,000 = GS-ERC
The calculation results in 117 thousand GS-ERCs being generated.
Because an NGCC unit cannot use the GS-ERCs it generates to meet its
compliance obligations, this NGCC unit will both generate ERCs (117,000
GS-ERCs) and owe ERCs (102,464 non-GS-ERCs against NGCC standard). This
NGCC unit may sell (or otherwise transfer) or bank its GS-ERCs. If a
GS-ERC is sold, those proceeds may, in turn, be used to acquire non-GS-
ERCs to satisfy the NGCC unit's compliance obligations.
A GS-ERC may not be used to meet an NGCC unit's compliance
obligation because they are generated to reflect incremental NGCC
generation replacing a SGU's generation. The calculation to derive a
GS-ERC represents this generation shift. If a GS-ERC were to be used
for compliance for an NGCC unit it would represent a shift from one
NGCC unit to another, which serves little purpose in achieving emission
reductions.
The EPA requests comment on the proposed approach and requests
comment and suggestions on other approaches for existing NGCC units to
generate GS-ERCs at all times. The EPA is considering this methodology
that GS-ERCs are generated for all NGCC generation because it ensures
that all existing NGCC units are encouraged to run at a greater
capacity. The EPA requests comment on alternative methods to account
for NGCC units
[[Page 64994]]
generating GS-ERCs. Specifically, the EPA solicits comment on NGCC
units generating GS-ERCs once a threshold of electric generation for
the year is exceeded. This threshold is based on 2012 as a baseline and
any NGCC generation beyond this threshold would be considered
incremental generation. There are two different options to evaluate
against a baseline. The first is on a unit-level, if an NGCC unit
generates more than it did in 2012, all generation above the 2012 level
(i.e., incremental generation) is eligible to be credited with GS-ERCs.
The other threshold option is to use a percentage threshold. Evaluated
on a regional level, the 2012 baseline capacity percentage for NGCC
units in the least stringent region is applied to all units. Each unit
is considered to be incrementally generating after it exceeds the
capacity percent and will be credited with GS-ERCs accordingly. The GS-
ERCs in these instances are calculated by the following equation:
[GRAPHIC] [TIFF OMITTED] TP23OC15.012
This equation quantifies the reductions of the generation shift
from fossil steam to NGCC units by the NGCC operating rate being
evaluated against the fossil steam standard. For all incremental NGCC
generation the NGCC operating rate is compared against two different
standards: (1) The NGCC standard against which ERC generation is
evaluated; and (2) the steam standard against which GS-ERC generation
is evaluated. An evaluation against each standard is independent of one
another and GS-ERCs, in this situation, are only available for fossil
steam compliance purposes.
While having a baseline threshold for EGU generation to credit GS-
ERCs against closely resembles the EPA's BSER determination, it enables
a system in which GS-ERCs can be generated by replacing NGCC generation
from one unit with NGCC generation from another. In this situation
there is not necessarily any additional NGCC generation as a
subcategory, but a shift in which NGCC units are generating electricity
and to what degree. This allows for a situation in which GS-ERCs can be
generated without achieving the anticipated reductions in
CO2 emissions.
The EPA also requests comment on whether a distinct type of ERC
that comes with the proposed restrictions (i.e., GS-ERCs) is necessary
to maintain the integrity of the rate-based trading proposal. Comments
regarding this section that solely relate to determinations finalized
in the EGs will be considered outside the scope of this proposed rule.
3. Eligible Emission Reduction Measures for ERC Generation
Under the rate-based federal plan, the EPA is proposing to specify
emission reduction measures used to adjust an emission rate that are
eligible for ERC issuance under the federal plan. Specifically, the EPA
is proposing that RE generation that meets the requirements for
eligible resources in the EGs (as specified in section VIII.K of the
final EGs), meets all other requirements related to ERC issuance in the
EGs and this proposal, and falls into one of the following specific
categories of RE resources (as specified in section V.E of the final
EGs), are eligible to be issued ERCs: Wind, solar, geothermal power,
and hydropower.\58\ Further, the EPA is proposing for the federal plan
that new nuclear units and capacity uprates at existing nuclear units
that meet the requirements for eligible resources in the EGs (as
specified in section VIII.K of the final EGs) and all other
requirements related to ERC issuance in the EGs and this proposal are
eligible to generate ERCs. Further, these RE and nuclear measures must
have the ability to provide data from a revenue quality meter, a
requirement that is further discussed in section IV.D.8 of this
preamble.
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\58\ This treatment for RE as an eligible measure type is also
proposed for the set-aside for RE that is part of the proposed mass-
based implementation approach co-proposed in section V of this
preamble as the federal plan, and all proposed aspects of the
eligible measure types described in this section and the requests
for comment included below also apply in the mass-based set-aside
context. Incremental nuclear is not eligible for the RE set-aside.
The set-aside method and the use of this eligibility treatment
within it are specified in section V.D.3 of this preamble.
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The EPA is proposing the inclusion of these measure types in the
federal plan for the following reasons. These technologies, with the
exception of nuclear, are part of the quantification of RE generation
potential for the BSER. Thus, they are included in the quantification
of CO2 emission performance rates and should be available to
affected EGUs to meet their CO2 emission performance rate
under the federal plan. See the final EGs for details on the treatment
of these measures in BSER (see section V.E of the final EGs). These RE
technologies are also expected to be able to deploy on an economic
basis during the compliance period, as discussed in the final EGs (see
section V.E.6 of the final EGs). These technologies also provide the
simplest and most timely path for EM&V implementation under a federal
plan, because they can use their existing metering infrastructure to
quantify generation and submit it for ERC issuance. A concern unique to
federal plan implementation is the need for an ERC issuance process
that can be implemented in a streamlined manner across many
jurisdictions in the time frame allowed by the federal plan while still
assuring a rigorous EM&V process. By limiting eligibility to measures
that can be directly metered, a feasible federal plan process for ERC
issuance across a potentially large number of jurisdictions is ensured.
This approach would allow for easier determinations of compliance with
the requirements for EM&V proposed in section IV.D.8 of this preamble
below (see also section VIII.K.3 of the final EGs).
The agency requests comment on the inclusion of other emission
reduction measures as eligible for ERC issuance under the rate-based
federal plan. This may include other RE technologies not included
above, such as distributed RE generation and various types of biomass.
In this proposal, the EPA is also offering for comment a treatment
option for biomass fuels, if it is included as an eligible measure
under the federal plan (see below).
The EPA requests comment on the inclusion of various types of
demand-side EE as eligible measures for ERC issuance under the federal
plan, such as state and utility EE programs, project-based demand-side
EE, state building codes, state appliance standards, and conservation
voltage reduction. The agency also requests comment on the inclusion of
CHP as an eligible measure under the federal plan. Later in this
section, the agency has provided detailed requirements for the issuance
of ERCs for CHP, and we request comment on these requirements for
inclusion in the federal plan.
The EPA requests comment on the inclusion as eligible for ERC
issuance under the federal plan of any other
[[Page 64995]]
emission reduction measures beyond those mentioned here, as long as
they meet the eligibility requirements outlined in the final EGs for
rate-based crediting. For all of the above measures on which the EPA
requests comment, the agency is particularly interested in comments on
how EM&V methods can be implemented for these measures across
applicable jurisdictions in the timeframe provided by this proposal in
a way that is rigorous, straightforward, widely demonstrated, and in
accordance with the EM&V requirements in this proposal, outlined in
section IV.D.8 of this preamble, and within the requirements outlined
in the final Guidelines (see section VIII.K.3 of the final EGs). It
should also be noted that any eligible measure will be subject to the
eligibility requirements outlined in this proposal and the final EGs,
including the requirement that the measure be incremental to 2012.
The EPA acknowledges that as new technologies mature, there should
be an avenue to add new technologies to this specified set of eligible
measures under the federal plan. The agency requests comment on
appropriate processes through which, after the federal plan is
finalized, the EPA or stakeholders could demonstrate the
appropriateness of new measure types and the EPA could evaluate and
approve the demonstration so that a new measure type could be
considered eligible for ERC issuance under the federal plan.
Under the rate-based model rule, the EPA is proposing that any
emission reduction measure is eligible as long as the requirements for
eligible resources in the final EGs (as specified in section VIII.K of
the final EGs) and all other requirements related to ERC issuance under
the model rule that are specified in the EGs and this proposal. In
particular, these measures should be able to meet the requirements for
EM&V as finalized in the final EGs section VIII.K and those proposed
for the model rule in section IV.D.8 of this preamble. In this section,
the EPA is also providing detailed requirements for CHP and waste heat
power (WHP); these requirements are proposed under the model rule, and
we request comment on their inclusion in the federal plan. We are
requesting comment on the inclusion of biomass and an option for the
treatment of biomass in both the proposed rate-based federal plan and
proposed rate-based model rule.
As mentioned above, the EPA requests comment on the inclusion of
biomass as an eligible measure for rate-based crediting. The EPA is
also requesting comment on the following treatment option for biomass
if biomass is included as an eligible measure. In the final EGs, the
EPA recognizes that the use of some biomass-derived fuels can play an
important role in controlling increases of CO2 levels in the
atmosphere (see section VIII.I.C of the final EGs). The use of some
kinds of biomass has the potential to offer a wide range of
environmental benefits, including carbon benefits. However these
benefits can typically be realized only if biomass feedstocks are
sourced responsibly and attributes of the carbon cycle related to the
biomass feedstock are taken into account. Many states have already
recognized the importance of waste-derived feedstocks via mandatory and
voluntary programs supporting such efforts.\59\ Some states have also
acknowledged the potential role of certain forestry and agricultural
industrial byproducts (such as black liquor) in energy production. Many
states have also recognized the importance of forests and other lands
for climate resilience and mitigation, and have developed a variety of
sustainable forestry policies, biomass-related RE incentives and
standards, and GHG accounting procedures.\60\
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\59\ Types of waste-derived biogenic feedstocks may include:
Landfill gas generated through the decomposition of municipal solid
waste (MSW) in a landfill; biogas generated from the decomposition
of livestock waste, biogenic MSW, and/or other food waste in an
anaerobic digester; biogas generated through the treatment of waste
water, due to the anaerobic decomposition of biological materials;
livestock waste; and the biogenic fraction of MSW at waste-to-energy
facilities (as discussed in section VIII.I.2.C of the final EGs).
\60\ Some states, for example Oregon and California, have
programs that recognize the multiple benefits that forests provide,
including biodiversity and ecosystem services protection as well as
climate change mitigation through carbon storage. Others, like
California's Forest Practice Regulations, support sustained
production of high-quality timber while considering ecological,
economic and social values. Several states focus on sustainable
bioenergy, as seen with the sustainability requirements for eligible
biomass in the Massachusetts renewable portfolio standard (RPS),
which, among other requirements, limits old growth forest harvests.
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In addition to acknowledging such state programs, the EPA has
undertaken a technical assessment of biogenic CO2 emissions
from stationary sources associated with the production, processing and
use of biomass fuels. In November 2014, the agency released a second
draft of the technical report, Framework for Assessing Biogenic Carbon
Dioxide for Stationary Sources. The revised Framework, and the EPA's
Science Advisory Board (SAB) peer review of the 2011 Draft Framework,
concluded that it is not scientifically valid to assume that all
biogenic feedstocks are ``carbon neutral'' and that the net biogenic
CO2 atmospheric contribution of different biogenic
feedstocks generally depends on various factors related to feedstock
characteristics, production, processing and combustion practices, and,
in some cases, what would happen to that feedstock and the related
biogenic emissions if not used for energy production.\61\ The EPA is
engaging in a second round of targeted peer review on the revised
Framework with the SAB in 2015.\62\ Information in the revised
Framework and the second SAB peer review process, including stakeholder
comments, will assist the EPA in assessing potential qualified biomass
feedstocks in federal plan applications.
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\61\ Specifically, the SAB found that ``There are circumstances
in which biomass is grown, harvested and combusted in a carbon
neutral fashion but carbon neutrality is not an appropriate a priori
assumption; it is a conclusion that should be reached only after
considering a particular feedstock's production and consumption
cycle. There is considerable heterogeneity in feedstock types,
sources and production methods and thus net biogenic carbon
emissions will vary considerably. Of course, biogenic feedstocks
that displace fossil fuels do not have to be carbon neutral to be
better than fossil fuels in terms of their climate impact.'' http://www.epa.gov/climatechange/ghgemissions/biogenic-emissions.html.
\62\ http://www.epa.gov/sab.
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If biomass is included as an eligible measure, we are taking
comment on an option for biomass treatment under the rate-based federal
plan, which would also potentially apply to eligible generation under
the proposed mass-based model trading rule allowance set-aside and to
the calculation of covered emissions for affected EGUs that are co-
firing biomass.
This option offered for comment is to specify a list of pre-
approved qualified biomass fuels. For example, the EPA could recognize
the CO2 and climate policy benefits of waste-derived
feedstocks (e.g., landfill gas) and certain industrial byproduct
feedstocks (e.g., black liquor or other forestry and agricultural
industrial byproducts with no alternative markets). As another example,
the EPA could also recognize biomass feedstocks from sustainably
managed forest lands, provided that these feedstocks meet certain
requirements such as demonstration that the feedstock is sourced from
sustainably managed lands (for example, feedstocks from forest lands
with sustainable practices like improved management to increase carbon
sequestration benefits) and therefore helps control increases of
CO2 in the atmosphere. The pre-approved qualified biomass
feedstocks list could be amended in the future as the science related
to biogenic CO2 emissions assessments evolves. The EPA asks
for
[[Page 64996]]
comment on whether to include a provision that allows sources to seek
approval for other types of biomass to be added to the pre-approved
list and what that process would entail. For example, this process
could include consideration of the production, processing and use of
forest- and agriculture-derived biomass fuels and related
CO2 benefits.
The EPA also requests comment on options for how EGUs would
demonstrate that feedstocks meet the requirements to be accepted as a
pre-approved qualified biomass feedstocks. These requirements could
include demonstration of certification or verification of practices
that are additional to other monitoring, reporting and EM&V
requirements discussed in this proposal, such as provision of
sufficient credible analysis of carbon benefits, third party
verification and/or certification, or a determination of the net
biogenic CO2 effects related to the production, processing
and use of the feedstock.
The EPA requests broad comment on the types of qualified biomass
feedstocks that should be specified in the final model rule, if any. We
request comment on the methods that we should specify in the final
model rule for the measurement of the associated biogenic
CO2 for such feedstocks, as well as what other requirements
we should specify in the final model rule related to biomass.
Specifically, we seek comment on the level of detail provided and
whether more or less detail (and what detail) should be included in the
final model rule. We request comment on any other requirements that
should be included in the final model rule regarding EM&V for qualified
biomass. Discussion of the biomass EM&V requirements in the rate-based
model rule can be found in section IV.D.8 of this preamble below.
The eligibility requirements for ERC resources discussed in this
section meet the requirements outlined in the final EGs (see section
VIII.K.2 of the final EGs). The agency in this proposal is including in
the regulatory text for the model rule language related to the
crediting of these other potential ERC resources, even though they are
not being proposed as a part of the federal plan. Our intent is to
provide states further direction through the model rule on how states
may include this broader set of ERC-generating resources in a rate-
based plan. To reduce confusion over the applicability of these
provisions, the agency has added a note in the regulatory text to
clarify that these resources, and provisions throughout the proposed
subpart that are related to those resources, are not applicable in the
case of a federal plan. Rather they are proposed as part of the model
trading rule only. However, again, the agency requests comment on the
inclusion of these resources in the federal plan.
The EPA is proposing with respect to the rate-based model rule that
CHP units are eligible to generate ERCs. With respect to the federal
plan, the EPA requests comment on the incorporation of non-affected CHP
units. Electric generation from non-affected CHP units \63\ may be used
to adjust the CO2 emission rate of an affected EGU, as CHP
units are low-emitting electric generating resources that can replace
generation from affected EGUs. Electrical generation from non-affected
CHP units that meet the eligibility criteria under section VIII.K.1.a
of the Clean Power Plan preamble can be used to adjust the reported
CO2 emission rate of an affected EGU.
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\63\ The accounting treatment described in this section is for a
``topping cycle'' CHP unit. A topping cycle CHP unit refers to a
configuration where fuel is first used to generate electricity and
then heat is recovered from the electric generation process to
provide additional useful thermal and/or mechanical energy. A CHP
unit can also be configured as a ``bottoming cycle'' unit. In a
bottoming cycle CHP unit, fuel is first used to provide thermal
energy for an industrial process and the waste heat from that
process is then used to generate electricity. Some waste heat power
(WHP) units are also bottoming cycle units and the accounting
treatment for bottoming cycle CHP units is provided with the WHP
description below.
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The electrical generation from a non-affected CHP unit that can be
used to adjust the CO2 emission rate of an affected EGU must
be calculated in accordance with the method specified in this section.
The CHP unit's electrical output is prorated based on the
CO2 emission rate of the electrical output associated with
the CHP unit (a CHP unit's ``incremental CO2 emission
rate'') compared to a reference CO2 emission rate.\64\ This
``incremental CO2 emission rate'' related to the electric
generation from the CHP unit would be relative to the applicable
CO2 rate-based emission standard for affected EGUs in the
state and would be limited to values between 0 and 1. The CHP unit's
electrical output is prorated as follows:
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\64\ The applicable CO2 rate-based emission standard
is in Table 6 of this preamble.
Prorated MWh = (1-incremental CHP electrical emission rate/applicable
---------------------------------------------------------------------------
affected EGU rate-based emission standard)* CHP MWh output
Where the ratio is limited to values between 0 and 1.
The CHP electrical CO2 emission rate is the net emission
rate when the CHP unit's CO2 emissions related to its
thermal output are deducted from the CHP unit's total CO2
emissions. The CHP electrical CO2 emission rate is derived
as follows:
CHP electrical CO2 emission rate = [CHP fuel input \65\ *
fuel emission factor \66\ - (UTO/boiler efficiency) * fuel emission
factor]/CHP electrical MWh
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\65\ This term generally represents the thermal energy
associated with the total fuel input.
\66\ The fuel emission factor can be determined through 40 CFR
part 75 Appendix G.
Where UTO is the useful thermal output from a counterfactual
industrial boiler that would have existed to meet thermal load in the
absence of the CHP unit.
This accounting approach takes into account the fact that a non-
affected CHP unit is a fossil fuel-fired emission source, as well as
the fact that the incremental CO2 emissions related to
electrical generation from a non-affected CHP unit are typically very
low. To generate ERCs for CHP, the CHP Electrical CO2
Emission Rate that is calculated (from above) is applied against the
applicable affected EGU standards in the same fashion as described in
section IV.C.1 of this preamble. The low CO2 emission rate
for electrical generation from a non-affected CHP unit is a product of
both the fact that CHP units are typically very thermally efficient and
the fact that a portion of the CO2 emissions from a non-
affected CHP unit would have occurred anyway from an industrial boiler
used to meet the thermal load in the absence of the CHP unit. In
contrast, the CHP unit also provides the benefit of electricity
generation while resulting in very low incremental CO2
emissions beyond what would have been emitted by an industrial boiler.
As a result, the accounting method does not presume that emission
reductions occur outside the electric power sector, but instead only
accounts for the CO2 emissions related to the electrical
production from a CHP unit that is used to substitute for electrical
generation from affected EGUs.
The EPA is proposing with respect to the rate-based model rule that
WHP units are eligible to generate ERCs. With respect to the federal
plan, the EPA requests comment on the incorporation of non-affected WHP
units. WHP units that meet the eligibility criteria under section
VIII.K.1 of the Clean Power Plan preamble may be used to adjust the
CO2 emission rate of an affected EGU. There are several
types of WHP units. There are units, also referred to as bottoming
cycle CHP units, where the fuel is first used to provide thermal energy
for an industrial process and the waste heat
[[Page 64997]]
from that process is then used to generate electricity.\67\ There are
also WHP units where the waste heat from the initial combustion process
is used to generate additional power. Under both configurations, unless
the WHP unit supplements waste heat with fossil fuel use, there is no
additional fossil fuel used to generate this additional power. As a
result, there are no incremental CO2 emissions associated
with that additional power generation. As a result, the incremental
electric generation output from the WHP units could be considered non-
emitting, for the purposes of meeting the EGs, and the MWh of
electrical output could be used to adjust the CO2 emission
rate of an affected EGU.\68\ The MWh of electrical output from a WHP
unit that can be recognized may not exceed the MWh of industrial or
other thermal load that is being met by the WHP unit, prior to the
generation of electricity.\69\ In addition, where fossil fuel is used
to supplement waste heat in a WHP application, the EPA requests comment
on what provisions to include in the final model rule to prorate the
proportion of fossil fuel heat input to total heat input that is used
by the WHP unit to generate electricity. The EPA also solicits comments
on other potential accounting mechanisms for WHP. As noted above, the
EPA requests comment incorporating WHP as an ERC generating resource
for the federal plan.
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\67\ In such a configuration, the waste heat stream could also
be generated from a mechanical process, such as at natural gas
pipeline compressors.
\68\ This only applies where no additional fossil fuel is used
to supplement the use of waste heat in a WHP facility. Where fossil
fuel is used to supplement waste heat in a WHP application, MWh of
electrical generation that can be used to adjust the CO2
emission rate of an affected EGU must be prorated based on the
proportion of fossil fuel heat input to total heat input that is
used by the WHP unit to generate electricity.
\69\ This limitation prevents oversizing the thermal output of a
WHP unit to exceed the useful industrial or other thermal load it is
meeting, prior to generation of electricity.
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D. ERC Tracking and Compliance Operations
The EPA proposes that the rate-based federal trading program use
the agency's already-existing Allowance Tracking and Compliance System
(ATCS). Under the proposed rate-based trading program, the federal
trading program would be maintained in the EPA's existing data system.
The ATCS would be used to track the trading of ERCs held by affected
EGUs, as well as ERCs held by other entities. Specifically, the ATCS
would track the generation of ERCs, holdings of ERCs in compliance
accounts (i.e., accounts for affected EGUs) and general accounts (i.e.,
accounts for other entities and for affected EGUs, including affected
EGUs that are under a ready-for-interstate-trading state plan),
deduction of ERCs for compliance purposes, and transfers of ERCs
between accounts. The primary role of the ATCS is to provide an
efficient, automated means for covered sources to comply, and for the
EPA to determine whether covered sources are complying with the
emission rate standards. The ATCS would also provide data to the ERCs
market and the public, including a record of ownership of ERCs, dates
of ERC issuance, ERC transfers, buyer and seller information, serial
numbers of ERCs transferred, emissions data, and compliance
information. This information would be publicly available on the EPA's
Web site and in annual progress reports. The ATCS and the EPA would
provide all required elements of a qualified ERC tracking system as
described in section VIII of the final EGs.
In the subsections that follow, the mechanisms by which a rate-
based trading program would be implemented and administered are
detailed. The EPA requests comment on each component of the trading
system that is proposed in this preamble and the associated model rule,
the trading program as a whole, and specifically requests comment on
means to expedite the process of issuing ERCs, any minimum and maximum
periods for which ERCs should be issued (e.g., monthly, quarterly,
annually), and any means to ensure that the ERCs issued meet the
requirements of the EGs and these proposed rules. The rate-based
federal plan and model rule borrow many concepts from other successful
trading programs, and the agency is interested in receiving additional
information through comments on successful implementation of similar
programs.
1. Designated Representatives and Alternate Designated Representatives
This section establishes the procedures for certifying and
authorizing the designated representative, and alternate designated
representative, of the owners and operators of the affected EGU and for
changing the designated representative and alternate designated
representative. These sections also describe the designated
representative's and alternate designated representative's
responsibilities and the process through which he or she 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 affected EGU in matters
pertaining to the rate-based trading program. 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 EGUs at the source and for the designated representative and
alternate; the name of every owner and operator of the affected EGU;
and certification language and signatures of the designated
representative and alternate. All submissions (e.g., monitoring plans,
monitoring system certifications, and allowance transfers) for an
affected EGU 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 ATCS for the affected EGU
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
affected EGU 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 and
alternate to delegate authority to make electronic submissions on his
or her behalf. The designated representative and alternate could
designate agents to submit
[[Page 64998]]
electronically certain specified documents. The previously-described
requirements for designated representatives and alternates would
provide regulated entities with flexibility in assigning
responsibilities under the rate-based trading program, while ensuring
accountability by owners and operators and simplifying the
administration of the proposed rate-based trading program.
2. ERC Tracking and Compliance System
The rate-based trading program rules establish the procedures and
requirements for using and operating the ATCS (which is the electronic
data system through which the Administrator would handle ERC issuance,
holding, transfer, and deduction), and for determining compliance with
the ERC-holding requirements in an efficient and transparent manner.
The ATCS provides a record of ownership, dates of ERC transfers, buyer
and seller information, origin of ERCs, the serial numbers of ERCs
transferred, and ERC type (i.e., if it is a GS-ERC or not). ERC price
information would not be included in the ATCS. The EPA's experience is
that private parties (e.g., brokers) are in a better position to obtain
and disseminate timely, accurate price information than the EPA. For
example, because not all ERC transfers are immediately reported to the
Administrator, the Administrator would not be able to ensure that any
reported price information associated with the transfers would reflect
current market prices.
3. Tracking System Requirements
This federal plan and model rule's proposed tracking system and
tracking systems that will be presumptively approvable for state plans
fufill the criteria set forth in the final EGs. The EPA's tracking
system includes provisions to ensure that ERCs issued to any eligible
entity are properly tracked from issuance to submission by affected
EGUs for compliance (where ERCs are ``surrendered'' by the owner or
operator of an affected EGU and ``retired'' or ``cancelled'' by the
Administrator or administering state regulatory body), to ensure they
are used only once to meet a regulatory obligation. This is addressed
through specified requirements for tracking system account holders, ERC
issuance, ERC transfers among accounts, compliance true-up for affected
EGUs,\70\ and an accompanying tracking system infrastructure design.
Each issued ERC will have a unique identifier (i.e., serial number) and
the tracking system will provide traceability of issued ERCs back to
the program or project for which they were issued.
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\70\ ``Compliance true-up'' refers to ERC submission by an owner
or operator of an affected EGU to adjust a reported CO2
emission rate, and determination of whether the adjusted rate is
equal to or lower than the applicable rate-based emission limit.
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The EPA received a number of comments from states and stakeholders
on the Clean Power Plan about the value of the EPA's support in
developing and/or administering tracking systems to support state
administration of rate-based emission trading systems. As described
above in section III.A of this preamble, the EPA is proposing, as part
of both types of model trading rules, a federal trading platform that
would allow state plans that are ready-for-interstate-trading to
operate through a program in which the EPA provides the tracking and
compliance system. This system will meet the requirements of the Clean
Power Plan.
4. Compliance and General Accounts
This section describes two types of ATCS accounts: Compliance
accounts, which would be established by the Administrator for each
affected EGU 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 ERCs
used by the affected EGU for compliance with the emissions limitations
would have to be held until retired for compliance.
General accounts could be used by any person or group for holding
or trading ERCs. However, ERCs could not be used for compliance with
emissions limitations so long as the ERCs were held in, and not
properly and timely transferred out of, a general account. To open a
general account, a person or group would be required 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 to be 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 ERCs, and for delegating
authority to make electronic submissions would be analogous to those
applicable to comparable matters for designated representatives and
alternates. The EPA requests comment on these compliance mechanisms.
5. Compliance Demonstration
The EPA proposes that affected EGUs subject to this federal plan
are required to meet compliance obligations by November 1 of the year
following the end of the compliance period. For an affected EGU to meet
its compliance obligations its average stack emission rate over the
compliance period must be at or below its applicable rate standard, or
the affected EGU must use ERCs to adjust its average stack emission
rate to be at or below its applicable rate standard. An EGU's average
emission rate over the compliance period will be calculated based on
submitted data to ATCS. The compliance period average would be
calculated by taking the measured CO2 mass in units of
pounds (lbs) summed over the compliance period for an affected EGU and
dividing it by the total net energy output over the compliance period
for that affected EGU in units of MWh.\71\ This averaged emission rate
will be compared to the emissions standards that the affected EGU is
subject to during the corresponding compliance period. Accordingly, and
if necessary, the appropriate number of ERCs will be retired from the
affected EGU's compliance account to adjust the emission rate of the
affected EGU to be equal to the emission standard. The discussion of
using ERCs for compliance is found in section IV.D.10 of this preamble.
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\71\ Note that affected EGUs will submit these values to the EPA
and the values will go through a transparent review process.
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6. Recordation of ERC Generation and ERC Issuance
The EPA proposes to issue ERCs for ERC generating entities once per
year. Thus, in a 3-year compliance period, for instance, there would be
three points at which the agency issues ERCs. After
[[Page 64999]]
each calendar year, the EPA would calculate the ERCs generated for
affected EGU and non-EGU ERC generators based on data submitted to the
EPA through the Emissions Collection and Monitoring Plan System
(ECMPS). These calculated ERC quantities would be proposed as part of a
Notice of Data Availability (NODA) with a 30-day comment period.
Subsequently, the EPA would finalize this NODA and issue ERCs in
accordance with the NODA, with tracking and serial numbers. For
affected EGUs with compliance accounts, the ERCs would be issued to
these. For entities without compliance accounts, the EPA would issue
ERCs to an entity's general account. The timing for issuing ERCs would
be consistent with existing programs, and the EPA believes there is
value in consistency. However, we solicit comment on the annual
issuance of ERCs and whether issuance should occur at different
intervals (e.g., quarterly, biannually, or other time frames). The EPA
requests justification along with corresponding comments regarding ERC-
issuance intervals. We request comment on how reporting and
recordkeeping requirements could be minimized, particularly for small
entities, to the extent possible under the statute and existing
regulations.
a. Issuance of ERCs to Affected EGUs. Following the determination
of the number of ERCs an affected EGU is eligible to receive, based on
an affected EGU's reported CO2 emission rate compared to a
specified reference rate,\72\ the EPA will issue those ERCs into the
affected EGU's compliance account in ATCS. The issuance will occur
annually through the NODA process. ERCs will have a unique serial
number, tracking number, and will distinguish ERC type (i.e., if it is
BB2 or not) when issued to an affected EGU.
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\72\ As described in section IV.C.1 of this preamble.
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b. Issuance of ERCs for Measures Used to Adjust an Emission Rate.
In the final EGs, the EPA has specified requirements for an ERC
issuance process for the quantification and verification of measures
used to adjust an emission rate that provide the necessary rigor and
transparency while being efficient and streamlined. This is the intent
of the federal plan as well, where there is a particular concern with
implementing a streamlined and efficient federal process for ERC
issuance across federal plan states. As required in the final EGs, we
are proposing a two-step application process to the federal plan
tracking systems for ERCs that allows for project approval to take
place prior to the performance period, and makes the issuance of ERCs
as quick and efficient as possible after generation has been quantified
and verified, while still assuring a rigorous approval process. For the
first step in the ERC issuance application process, the EPA proposes
that RE and nuclear generation providers submit to the EPA or its
designated agent an eligibility application for EPA approval,
demonstrating that the project is eligible for the issuance of credits,
including an EM&V plan that meets EPA requirements. The EPA requests
comment on all aspects of the proposed ERC issuance process. The EPA
also requests comment on how an ERC issuance process would apply to
emission reduction measures for which we are requesting comment
regarding their eligibility for ERC issuance under the federal plan,
including types of RE not covered by the federal plan, demand-side EE,
CHP, WHP, biomass, and any other measure that could be considered
eligible under the final guidelines.
The following are proposed required components of the eligibility
application, as specified for these measures in the final EGs:
(1) The EPA proposes that the federal plan will require that
providers must show that the generation they would be providing to
the federal plan system for ERC issuance is only being credited in
the federal plan, and will not be submitted for ERC issuance in any
other rate-based crediting system in any other state. As discussed
in section IV.C. of this preamble, we are proposing that states with
rate-based emission standards plans that have eligibility and EM&V
requirements compatible with the federal plan would have the
opportunity to participate in the federal plan trading systems, and
create a shared pool of creditable reductions, in which case credits
approved by such states would be eligible for use by affected EGUs
in the federal plan.
(2) The provider must show that the project is using an eligible
RE or nuclear resource. Specific requirements are proposed in
section IV.C of this preamble.
(3) The provider must show that the project has an EM&V plan
that meets the federal plan requirements. Proposed requirements
specific to the federal plan are proposed in section IV.D.8 of this
preamble. As specified in section IV.D.8 of this preamble, we
request comment on whether nuclear energy resources should be
subject to the same EM&V requirements as RE resources, and if not,
we request comment on the EM&V requirements to which nuclear energy
resources should be subject.
(4) There are special conditions if the provider is located in a
state with a mass-based plan. For eligible RE capacity, the provider
can only be credited in a rate-based state or rate-based multi-state
system if the provider can demonstrate that the generation was
produced to meet electricity load in a state with a rate-based plan.
The EPA is proposing that an RE provider can make this demonstration
by providing documentation of a power purchase agreement or delivery
contract from the rate-based state and show that the measure was
treated as a generation resource used to serve regional load that
included the rate-based state. For incremental nuclear capacity, no
provider in a state with a mass-based plan can be eligible for ERC
issuance in a rate-based state. This requirement and the
justification for its inclusion is further discussed in section
III.A of this preamble on Interstate Effects and also discussed in
the Interstate Effects section of the final EGs (see sections
VIII.K.1 and VIII.L). The EPA is proposing that there would be no
other geographic limitation on the location of the providers of RE
and incremental nuclear generation submitted for ERC issuance under
the rate-based federal plan approach.
(5) This application must include an independent third-party
verifier's review and approval of the eligibility requirements, as
is reflected in EM&V requirements for the final guidelines, and
specified as part of the proposed federal plan EM&V requirements in
section IV.D.8 of this preamble.
We request comment on each criterion of the eligibility application
described herein and in the proposed model rule, for each eligible
resource. Specifically, we seek comment on the substantive content of
the criteria, and we seek comment on the level of detail provided and
whether more or less detail (and what detail) should be included in the
final model rule.
The EPA is proposing that ERCs would be tracked in the ATCS.
Additionally, the EPA is proposing that the agency would establish a
complementary tracking system for the ERC issuance process. It would
provide for transparent access to RE project and program eligibility
applications and regulatory approvals as well as information on the
activities of accredited third party verifiers (third party verifiers
are further discussed in section IV.D.7 of this preamble), as well for
the public to be able to generate reports based on this information.
The agency is proposing that the project eligibility applications
would be accepted after the finalization of the federal plan and prior
to the first compliance period, as soon as the agency is able to
establish an application process, and that applications would be
accepted on an annual basis. The agency requests comment on whether a
quarterly or biannual application process is more appropriate. These
applications would be accepted through the entirety of all compliance
periods. The EPA will review and approve the project applications. It
is proposed that the EPA
[[Page 65000]]
may designate an agent to coordinate the project application process
and assist with review of applications.
For the second step in the credit issuance application process, the
EPA proposes that providers submit an M&V report to the EPA, or its
designated agent, prior to the EPA's issuance of ERCs. This can only
occur after the approval of a project application, the RE has been
generated, and necessary EM&V has been completed.
The following are proposed required components of the M&V Report:
(1) Documentation of completed EM&V in accordance with the EM&V
plan submitted by the RE or nuclear provider, including
quantification of the MWh of generation to be credited and
verification of their creation.
(2) Documentation that the generation has not been submitted for
crediting under any other federal or state plan, including to
another rate-based credit tracking system.
(3) Documentation that the MWh resulted from RE or incremental
nuclear capacity eligible for crediting under the federal plan
requirements and in accordance with final EGs. This documentation
should note if the MWh are from an RE project located in a state
with a mass-based plan, and show if the generation is approved to be
eligible for ERC issuance under the federal plan. See above
geographic eligibility discussion and section III.A of this preamble
for specifics on the required demonstration for this type of RE
generation. As discussed in that section, this option is proposed to
not be available to incremental nuclear capacity located in a state
with a mass-based plan.
(4) This application must include a verification report from an
independent third-party verifier, submitted after the verifier's
review and approval of the eligibility application, as is reflected
in EM&V requirements for the final guidelines, and specified as part
of proposed federal plan EM&V requirements described below and
included in detail in the proposed model rule.
If the application meets these requirements, pursuant to review by
the EPA or its designated agent, ERCs will be issued to the provider by
the EPA through the ATCS. The specific steps of the process by which an
eligible resource seeks ERCs, and by which an affected EGU may use ERCs
in its compliance demonstration, are described in the proposed model
rule. One of the steps requires the proponent to register for a general
account in the EPA tracking system where the ERCs would be recorded.
See 40 CFR 62.16515 for the requirements to establish a general
account. While EPA is proposing to allow eligible resources to use a
general account to receive any ERCs issued under this section, the EPA
requests comment on extending the designated representative provisions
in 40 CFR 62.16485 to eligible resources instead of the general account
provisions. Requiring eligible resources to submit information similar
to that collected in the certificate of representation in 40 CFR
62.16500 and to appoint a designated representative to act on behalf of
all owners/operators for all projects requesting ERCs may improve the
EM&V process by making the eligible resources more accountable.
Because it is critical to the integrity of an ERC that it
represents the actual MWh of energy generated or saved that it purports
to represent, and as required in the EGs for state plans, the federal
plan and model rule include provisions to address error correction
(i.e., mechanisms to adjust the number of ERCs issued based on all form
of errors, e.g., clerical errors, over- and under-statements, material
inconsistency with rule provisions, fraud, etc.). In addition, the
federal plan and model rule include provisions that provide that, at
any time for cause, the EPA may temporarily or permanently revoke the
qualification status of eligible resources from being issued ERCs for
at least the duration it does not meet the requirements for being
issued ERCs and independent verifiers from providing verification
services for at least the duration it does not meet the requirements of
the state plan. For the federal plan, as discussed in section III.I of
this preamble above, we propose to use the administrative appeals
process set forth 40 CFR part 78 to address party-specific disputes
concerning the issuance or validity of ERCs. States may adopt a similar
procedural and substantive process at the state level to enable them to
rescind or withhold approval of specific credits. We request comment on
the content of each of these provisions in the model rule, and
specifically seek comment on whether the model rule should include
different or additional details related to either procedure or
substance for error correction and the revocation of the qualification
status of an eligible resource or independent verifier.
The agency is proposing that M&V reports will be accepted starting
before the beginning of the first compliance period (January 1, 2022),
through an application process the agency will establish and
administer, and that applications will be accepted on an annual basis.
These applications will be accepted through the entirety of all
compliance periods. The EPA will review and approve M&V reports, and
may designate an agent to coordinate and assist with M&V reports. The
EPA is proposing that it will issue ERCs for a given year no later than
6 months after the end of the relevant year. This amount of time may be
necessary to accommodate the ERC issuance process, including necessary
EM&V. The overall proposed schedule for trading and true-up has been
constructed to allow for this period of time for EM&V after the
compliance period.
For purposes of the proposed rate-based federal plan, the EPA
proposes to implement the CEIP on behalf of a state by issuing early
action ERCs for eligible actions located in or benefitting that state
that are implemented after September 6, 2018 and that generate zero-
emitting MWh or reduce energy demand in 2020 and/or 2021.\73\ The EPA
intends to implement the program in a way that maintains the stringency
of the rate-based emission standards for affected EGUs in the
compliance periods established in this rule. For the purposes of the
rate-based federal plan, the EPA is proposing to award early action
ERCs to two types of eligible projects, as listed below. The rationale
for including these projects is included in section VIII.B.2 of the
final EGs.
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\73\ As discussed in section VIII.B.2 of the final EGs, in the
case of a state that submits a final state plan including
requirements for the state's participation in the CEIP, eligible RE
projects may commence construction, and eligible EE projects may
commence implementation, following the date of submission of a final
state plan to the EPA. These projects must be implemented in or
benefit the state that submitted the final state plan to the EPA,
and may receive incentives for the zero-emitting MWh they generate
or the end-use energy savings they achieve during 2020 and/or 2021.
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RE investments that generate metered MWh from any type of
wind or solar resources; and
Demand-side EE programs and measures implemented in low-
income communities that result in quantified and verified electricity
savings (MWh).
The EPA proposes the following framework to implement the CEIP in
the rate-based federal plan. First, the EPA proposes to implement a
mechanism for issuing early action ERCs for eligible RE projects that
commence construction and eligeible EE projects that commence
implementation after September 6, 2018 and that generate zero-emitting
MWh or reduce end-use energy demand during 2020 and/or 2021. These
projects must be located in or benefit the state on whose behalf the
EPA is implementing the federal plan. The EPA proposes to design this
mechanism in a manner that would have no impact on the aggregate
emission performance of sources required to meet rate-based emission
standards during the compliance periods. The EPA requests comment on
the structure of this mechanism, which could include adjusting the
stringency of the emission standards during the compliance periods to
account for the issuance of early action ERCs for MWh
[[Page 65001]]
generated or avoided in 2020 and/or 2021. For example, during the
interim performance period, a number of ERCs could be retired in an
amount equivalent to the number of early action ERCs that were awarded
for MWh generated or avoided in 2020 and/or 2021. As another option,
the EPA, or a state under the model trading rule, could adjust their
targets to achieve the same stringency, taking into account the
additional borrowed ERCs. The EPA requests comments on all potential
methods to adjust state targets, including modeling-based approaches,
and on what information the state must present to demonstrate that the
new targets preserve the needed stringency. More generally, the EPA
requests comments on these ideas, as well as on alternatives for
maintaining the stringency of a rate-based plan implementing the CEIP
so as to have no impact on the aggregate emission performance of
sources required to meet rate-based emission standards during the
compliance periods.
Second, the agency proposes to create an account of ``matching''
ERCs for each state participating in the CEIP--regardless of whether a
state is implementing a state plan or the agency is implementing a
federal plan on its behalf. This distribution would reflect each
state's pro rata share--based on the amount of the reductions from 2012
levels the affected EGUs in the state are required to achieve relative
to those in the other participating states--of a federal pool of
additional ERCs, which would be limited to the equivalent of 300
million short tons of CO2 emissions. Thus, states whose
affected EGUs have greater reduction obligations will be eligible to
secure a larger proportion of the federal pool upon demonstration of
quantified and verified MWh of RE generation or demand side-EE savings
from eligible projects realized in 2020 and/or 2021. The EPA intends
that a portion of these matching ERCs would be reserved for eligible
wind and solar projects, and a portion would be reserved for eligible
EE projects implemented in low-income communities. The agency
recognizes that there have been historical economic, logistical and
information barriers to implementing EE programs in these communities,
and therefore believes it is appropriate to reserve a portion of the
federal pool to incentivize investment in these programs. The EPA
requests comment on the size of reserve of matching ERCs for eligible
low-income EE programs as well as for eligible wind and solar projects.
The EPA is proposing that unused ERCs in either reserve would be
redistributed among participating states. This redistribution could be
executed according to the pro rata method discussed above.
Alternatively, unused matching EE or RE ERCs could be swept back into a
federal pool and distributed to project providers on a first-come,
first served basis. EPA requests comment on these ideas as well as
alternative proposals regarding the method for redistributing matching
ERCs, as well as the appropriate timing for such a redistribution.
Following the effective date of a rate-based federal plan for a
state, the agency will create an account of matching ERCs for the state
that reflects the pro rata share of the 300 million short ton
CO2 emissions-equivalent matching poolthat the state is
eligible to receive. Any matching ERCs that remain undistributed after
September 6, 2018 will be distributed to those states with approved
state plans that include requirements for CEIP participation, as well
as to those states on whose behalf EPA is implementing a federal plan.
These ERCs will be distributed according to the pro rata method
outlined above. Unused matching ERCs that remain in the accounts of
states participating in the CEIP on January 1, 2023, will be retired by
the EPA.
7. Independent Verifiers
The EPA has determined in the final EGs that independent
verification requirements are necessary to ensure the integrity of any
rate-based emission trading program, given the types of eligible
measures that may generate ERCs and the broad geographic locations in
which those measures may occur. Inclusion of an independent
verification component provides technical support for the EPA in the
context of the proposed federal plan, and the states in the context of
their plans, to ensure that eligibility applications and monitoring and
verification reports are appropriately reviewed prior to issuance of
ERCs. Inclusion of an independent verification component is also
consistent with similar approaches required by state PUCs for the
review of demand-side EE program results and GHG offset provisions
included in state GHG emission budget trading programs.
The remainder of this section and the related language in the
proposed model rule provide the proposed basis by which the EPA intends
to evaluate the independence of the verifiers that it uses to provide
verification reports pursuant to the federal plan. The qualifications
described here and in the model rule would be presumptively approveable
in the context of a state plan.
As a starting point, an independent verifier must have the
necessary technical qualifications to provide verification services for
the subject in question, as well as fulfill certain codes of conduct in
providing verification services. Only verifiers approved or
``accredited'' by the EPA may provide verification services related to
ERC issuance for the federal plan, in the same way that only verifiers
approved by a state may be eligible to perform verification services
pursuant to a state plan.\74\
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\74\ In this section, the term ``verifier'' is used
interchangeably to refer to both a ``verification body'' (i.e., a
verification company or organization) and a ``verifier,'' which is
an individual that is a principal or employee of a verification
body.
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In addition, verifiers must have sufficient knowledge of the rate-
based emission trading program rules, technical expertise, and
knowledge of auditing, accounting, and information management
practices, in order to perform verifcation services related to the
Clean Power Plan. Accredited verifiers must be independent. Accredited
verifiers may not provide verification services for any eligible
resource for which they have a financial, management, or other
interest.\75\ Such relationships constitute a conflict of interest
(COI). COI situations may also arise as a result of personal
relationships among individuals representing an ERC provider and an
accredited verifier. A verification report would not be
[[Page 65002]]
accepted as part of an eligibility application or M&V report where the
accredited verification body or any individual verifier has a COI.
Accredited verification bodies must have management protocols in place
to identify and remedy any COI prior to provision of verification
services. The proposed federal plan and model rule provide that failure
of an accredited verifier to identify and adequately address any COI
prior to provision of verification services is grounds for revocation
of accreditation. The EPA would perform periodic reviews of accredited
verifiers, to ensure that verifiers are maintaining necessary technical
and professional qualifications and are meeting program requirements
for provision of verification services. The EPA may recognize, in part,
accreditation by an outside organization where such outside
accreditation demonstrates that federal plan requirements are met.\76\
The EPA requests comment on the proposed necessary requirements for an
independent verifier to perform verification services in connection
with the federal plan, including those requirements specifically
detailed in this section of the preamble and the related language in
the proposed model rule, and including whether there are any
requirements that are not included in this proposal that should be
included in the final rule. We further request comment on the level of
detail that we should include in the final model rule regarding all
requirements for indepenent verifiers, and all aspects of verification.
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\75\ Accredited verification bodies and individual verifiers may
not have any direct or indirect organizational or personal
relationships with an ERC provider that would impact their
impartiality in assessing the validity and accuracy of the
information in an eligibility application or M&V report. In addition
to this general requirement, the following specific requirements
also apply. Accredited verifiers must have no direct or indirect
financial interest in, or other financial relationships with, an ERC
provider or any related program or project that seeks issuance of
ERCs. Accredited verifiers must have no relationship with the
implementer of a program or project that seeks the issuance of ERCs,
or any related ERC provider, that would represent a COI. Accredited
verifiers must have no role in the development and implementation of
a program or project that seeks issuance of ERCs, beyond the
provision of verification services. Accredited verifiers must not be
compensated, directly or indirectly, in relation to the quantified
and verified MWh in an M&V report or on the basis of program or
project approval, ERC issuance, or the number of ERCs issued.
Accredited verifiers may not hold ERCs, or other financial
derivatives related to ERCs, or have a financial relationship with
other parties that hold ERCs or other related financial derivatives.
Verification reports must include an attestation by the accredited
verifier that it assessed potential COI related to an ERC provider
and adequately addressed any identified COI. The EPA requests
comment the potential for payments to be channeled through the EPA
as fees.
\76\ An example is American National Standards Institute (ANSI)
accreditation under ISO 14065:2013 for GHG validation and
verification bodies. More information is available at https://www.ansica.org/wwwversion2/outside/GHGgeneral.asp.
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8. Evaluation, Measurement, and Verification Plans, Monitoring and
Verification Reports, and Verification Reports
This section identifies and discusses the EM&V approaches used to
quantify and verify MWh from RE, demand-side EE, and other eligible
measures used to generate ERCs or otherwise adjust an emission
rate.\77\
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\77\ EM&V is defined here as the set of procedures, methods, and
analytic approaches used to quantify the MWh from RE, demand-side
EE, and other eligible measures to ensure that the resulting savings
and generation are quantifiable and verifiable. In this proposal, we
are proposing EM&V for the eligible RE, and we request comment on
EM&V for demand-side EE and any other measures that could be
eligible.
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Only a subset of the potentially creditable ERC resources discussed
in this section are actually being proposed as part of the federal
plan. The remainder, and their associated requirements, are provided as
part of the proposed model trading rule. Thus, all provisions of this
subsection relating to such resources are presented only for the
purpose of comment in the context of the federal plan, but are actually
proposed for inclusion in the model trading rule. The ERC resources
proposed in the federal plan must meet the following criteria: (1) They
are in the following categories of measures: On-shore wind, solar,
geothermal power, hydropower, or new nuclear units and capacity uprates
at existing nuclear units; and (2) they can provide quantified
generation data from a revenue quality meter. The language pertaining
to all other measures (e.g., demand-side EE) is proposed only for the
model rule. While they are currently being proposed as part of the
model rule and not the federal plan, the EPA requests comment on the
inclusion of other RE measures, demand-side EE measures, and any other
measures that may be eligible under the final guidelines as eligible
measures under the federal plan. For stakeholders that are submitting
comments on the inclusion of such additional measures, the EPA requests
comment on how the EPA could implement across applicable jurisdictions
a rigorous, straightforward, and widely demonstrated set of EM&V
methods, procedures, and approaches that could be implemented in the
time frame allowed by the federal plan and that also meet the
requirements outlined in the final guidelines. To the extent they are
proposed for inclusion in the model trading rule, we also invite
comment on these requirements in the context of state implementation as
part of a state plan. Thus, commenters on this aspect of the proposal
should consider whether and how these provisions could be implemented
at the state level. Comments that suggest an approach not authorized by
the EGs will likely be considered outside the scope of this proposed
rule.
Additionally, with respect to EM&V, the EPA describes certain
established industry best-practice methods, procedures, and approaches
that would be presumptively approvable if included in state plans.
States wishing to adopt the model rule must submit these methods,
procedures, and approaches as specified, or may submit alternative EM&V
that is functionally equivalent to the industry best-practices
described as presumptively approvable.\78\
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\78\ The EPA recognizes that EM&V is routinely evolving to
reflect changes in markets, technologies and data availability, and
expects to update its EM&V guidance over time. Therefore the agency
expects that alternative quantification approaches will emerge that
can be approved for use, provided that such approaches are
functionally equivalent to the provisions for EM&V outlined in this
section.
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As discussed in section IV.C.3 of this preamble, quantified and
verified MWh of RE generation and other means of generating ERCs may be
used to adjust a CO2 emission rate when demonstrating
compliance with the EGs. Providers other than affected EGUs who seek to
earn ERCs must develop EM&V plans outlining how they will quantify and
verify the resulting MWh from their efforts. These providers must then
submit these EM&V plans as part of their application to the
Administrator for project approval.\79\
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\79\ A full discussion of applicable requirements for the
establishment and functioning of the rate-based trading system is
provided above, in section IV.D of this preamble.
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a. Overall Approach and Measure-Specific Requirements. The proposed
Clean Power Plan stated that the EPA would establish EM&V requirements
and procedures to help states, sources, and resource providers quantify
and verify MWh savings and generation resulting from zero-emitting RE
and demand-side EE efforts. This action proposes those requirements
that the EPA committed to establish. The Clean Power Plan proposal and
associated ``State Plans Considerations'' TSD \80\ suggested that such
EM&V requirements would leverage existing industry practices,
protocols, and tracking mechanisms currently utilized by the majority
of states implementing RE and demand-side EE. The EPA further noted
that many state regulatory bodies and other entities already have
significant EM&V infrastructure in place and have been applying,
refining, and enhancing their evaluation and quality assurance
approaches for over 30 years, particularly with regard to the
quantification and verification of energy savings resulting from
utility-administered EE programs. The EPA also observed that the
majority of RE generation is typically quantified and verified using
readily available, reliable, and transparent methods such as direct
metering of MWh. The EPA is proposing EM&V methods, procedures, and
approaches, described herein, that are intended to be consistent with
and leverage prevailing industry best-practices.
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\80\ See discussion beginning on p. 34 of the State Plan
Considerations TSD for the Clean Power Plan Proposed Rule: http://www2.epa.gov/carbon-pollution-standards/clean-power-plan-proposed-rule-state-plan-considerations.
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In addition, the EPA's proposed EM&V methods, procedures, and
[[Page 65003]]
approaches reflect several overarching objectives and principles
offered by states, private organizations, and the public during the
comment period of the Clean Power Plan EGs. One of these is the
importance of balancing the accuracy and reliability of results with
the associated costs of EM&V. Another objective for the EPA's proposed
EM&V is to avoid excessive interference with existing practices that
are already robust, transparent and effective.
Submittals. Applicable submittals under a rate-based emission
trading program include eligibility applications (including EM&V
plans), monitoring and verification reports, and verification reports.
These submittals are described in section VIII.K.3.b of the final EGs
preamble and in this model rule and federal plan. At the initiation of
a program or project, ERC providers develop and submit to the state or
the EPA, respectively, an EM&V plan that documents how requirements for
quantification and verification will be addressed as EM&V is performed
over the program or project period. After implementation has occurred,
the ERC provider must submit periodic M&V reports to document and
describe how each of the requirements were applied. These reports must
also specify the resulting MWh savings or generation values, as
determined on a retrospective (ex-post) or real-time basis. MWh values
may not be determined using projections or other ex-ante quantification
approaches.
Each EM&V plan submitted in support of an eligibility application
must identify the eligible resource covered by the plan, and provide
specific EM&V criteria that specify the manner in which the energy
generated or saved by the eligible resource will be quantified,
monitored and verified. The manner of quantification, monitoring and
verification must meet the criteria outlined below and included in the
proposed model rule, as applicable to the specific eligible resource.
We request broad comment on each criteria specified below and in the
proposed model rule, for each eligible resource. Specifically, we seek
comment on the substantive content of the criteria, and we seek comment
on the level of detail provided and whether more or less detail (and
what detail) should be included in the final model rule, and whether
the criteria should differ for each eligible resource.
Each M&V report submitted in support of the issuance of ERCs to a
specific eligible resource must include specific criteria described
here and in the proposed model rule. For the first M&V report
submitted, a key component is documentation that the electricity-
generating resources or electricity-saving measures were installed or
implemented consistent with the description in the approved eligibility
application. Each following M&V report must then identify the time
period covered by the M&V report, describe how the methods specified in
the EM&V plan were applied during the reporting period, and document
the quantity (in MWh) of energy generation and/or electricity savings
quantified and verified for the period covered by the M&V report. Any
change in the energy generation or savings capability of the eligible
resource during the period covered by the M&V report must also be
included in the M&V report, along with the date on which the change
occurred, and information sufficient to demonstrate whether the
eligible resource continued to meet all eligibility requirements during
the period covered by the M&V report. Any change should also be
specified in the report. The EPA requests broad comment on each of
these criteria, as described here and in the proposed model rule.
Specifically, we seek comment on the substantive content of the
criteria, and we seek comment on the level of detail provided and
whether more or less detail (and what detail) should be included in the
final model rule, and whether the criteria should differ for each
eligible resource.
Each verification report submitted by an independent verifier in
support of the issuance of ERCs to a specific eligible resource must
address the criteria described here and in the proposed rule text. Each
verification report must set forth the findings of the verifier, based
on an assessment of all relevant requirements, information and data,
including an assessment of any material misstatements or data
discrepancies. Any verification report included as part of an
eligibility application must further describe the review conducted by
the verifier and verify the following: The eligibility of the resource
to be issued ERCs; that the eligible resource exists and has been, or
will be, generating energy or saving electricity in the manner
required; that the EM&V plan meets its requirements; and any other
information required or that the verifier finds, in its professional
opinion, is necessary to assess the accuracy of the subject of the
verification report. Each verification report included as part of a M&V
report must also describe the review conducted by the verifier and
verify the following: The adequacy and validity of the information and
data submitted to quantify eligible MWh of electric generation or
electricity savings during the period covered by the report, as well as
all supporting information and data identified in the EM&V plan and M&V
report; evaluate whether all generation or savings data are within a
technically feasible range for that specific eligible resource
(determined through a quality assurance and quality control check of
the data); that the M&V report meets its requirements; and any other
information required or that the verifier finds, in its professional
opinion, is necessary to assess the accuracy of the subject of the
verification report. The EPA requests broad comment on each of these
criteria, as described here and in the proposed model rule.
Specifically, we seek comment on the substantive content of the
criteria, and we seek comment on the level of detail provided and
whether more or less detail (and what detail) should be included in the
final model rule, and whether the criteria should differ for each
eligible resource.
For demand-side EE, all EM&V plans that are developed for purposes
of adjusting an emission rate under this proposed rule are intended to
leverage and closely resemble the plans already in routine use for a
wide range of publicly or rate-payer funded EE programs and energy
service company (ESCO) projects. For RE, EM&V plans similarly leverage
resources and approaches to MWh tracking for RE that are broadly
applied in the state and regions. The existing reports and
documentation from existing tracking systems may serve as the
substantive basis for a monitoring and verification report for RE.
b. Renewable Energy EM&V Requirements. This section describes the
EM&V requirements associated with quantifying electricity generation
from eligible RE and nuclear energy, and for documenting these
requirements in EM&V plans and reports. Consistent with prevailing
views expressed in public comments, the EPA's requirements presume that
the quantification of RE generation can leverage the infrastructure and
documentation associated with the establishment of renewable energy
certificates (RECs) and registration of such certificates in REC
registries. These registries typically include well-established
safeguards, documentation requirements, and procedures for registry
operations intended to support the demonstration of compliance with
state RPS policies. A key element of RPS compliance is that each RE
generating unit must be uniquely identified and recorded in a registry
to avoid the double counting of RECs.
[[Page 65004]]
The primary metric for all RE is electricity generation, in units
of MWh. Measured output must be derived either from: (1) A revenue
quality meter that meets the applicable ANSI C-12 standard or
equivalent, which is the typical requirement for settlements with RTO
and other control-area operators; or (2) For customer-sited generators
that are interconnected behind the customer meter, measurement at the
AC output of an inverter, adjusted to reflect the energy delivered into
either the transmission or distribution grid at the generator bus bar.
Further, a RE generating facility of 10 Kilowatt capacity or less may
estimate the facility's output if the state where it is located
explicitly allows estimates to be used and provides rules for when it
will be allowed. In the latter case, calculations of system output must
be based on the RE unit's capacity, estimated capacity factors, and an
assessment of the local conditions that affect generation levels. All
such input parameters and assumptions must be clearly described and
documented. For RE units that are managed by regional transmission
operators or other control area operators, metered generation data
should be electronically collected by the control area's energy
management system, verified through an energy accounting or settlements
process, and reported by the control area operator to the REC registry
at least monthly. The EPA requests comment on this proposed requirement
for quantifying RE generation for the purpose of ERC issuance.
For RE units that do not go through a control area settlements
process, metered data may be read and transmitted to the ERC registry
by an independent third party, or may be self-reported. Third-party and
self-reported generation data must be reported on an annual basis. All
such data must be verified for reasonableness by the agency, the state,
or the REC registry.
For reporting purposes, RE generation may be aggregated from
multiple generators into a single MWh value for the group, provided the
following requirements are met: Each RE unit is uniquely identified in
the federal tracking system, the nameplate capacity of each RE unit is
less than 150 Kilowatt, the aggregated RE units collectively have
nameplate generating capacities less than 1.0 MW, the units aggregated
are located in the same state, the RE units being aggregated utilize
the same technology/fuel type, and the RE unit's generation data are
based on the same metering or the same generation estimating software
or algorithms. The EPA requests comment on how existing reporting
systems can play a role in meeting EM&V requirements under the federal
plan and model rule, particularly, in assuring that each MWh of RE
generation is uniquely identified and recorded to avoid double
counting.
An additional consideration regarding distributed RE units that
directly serve on-site end-use electricity loads is that avoided
transmission and distribution (T&D) system losses can be quantified, as
is commonly practiced with demand-side EE. If such T&D losses are
quantified, the requirements for demand-side EE would be applicable.
The EPA requests comment on all metering, measurement,
verification, and other requirements proposed in this subsection,
including the appropriateness of their use for each type of RE resource
(including the relevant size and distribution of such resource) that
qualifies for issuance of ERCs for use for compliance.
For RE resources with a nameplate capacity of 10 Kilowatt or more
and for RE resources with a nameplate capacity of less than 10 Kilowatt
for which metered data are available, we request comment on the
appropriateness of the requirement to use a revenue quality meter for
monitoring generation, and we request comment on the definition of
revenue quality meter. We request comment on the appropriateness of
other types of meters for monitoring generation. We request comment on
whether 10 Kilowatt is the appropriate threshold, under which an
eligible resource can be issued ERCs for generation based on data other
than metered generation, and if not, what would be the appropriate
threshold.
For RE resources of all sizes and means of monitoring, we request
comment on the appropriate requirements for allowing generation data to
be aggregated, including comment on the provisions in the proposed
model rule and any alternatives to them. We request comment on whether
all of the generating units have the same essential generation
characteristics, in order for their data to be aggregated, and if so,
what is the appropriate definition of ``essential generation
characteristics'' (e.g., are essential generating characteristics
determined on a resource by resource basis, or can generation from a
group of wind turbines be aggregated with generation from a group of
solar panels?) We seek comment on the appropriate thresholds for the
aggregated of individual units (e.g., nameplate capacity of less than
150 Kilowatt per unit and the units collectively do not exceed a total
nameplate capacity of 1 MW when aggregated, as in the proposed model
rule).
For non-metered units of less than 10 Kilowatt, we request comment
on whether the final model rule should specify the specific estimating
software or algorithms by which generation data should be measured, and
if so, we request broad comment on the appropriate estimating software
or algorithms and the appropriate characteristics for such estimating
software or algorithms.
We request comment on any other requirements that should be
included in the final model rule regarding EM&V of RE resources.
For all energy generating resources (such as RE, but also including
applicable resources requiring EM&V described below), we request
comment on the appropriate place of measurement of the generation,
including comment on whether measurement should be at the bus bar or at
a different location (or in the case of meters on units of less than 10
Kilowatt, at the AC output of the inverter or elsewhere), whether
measurement should be before or after parasitic load (and how to
separate out parasitic load). In addition, for all energy generating
resources, we request comment on whether generation data should go
through a control area settlement process prior to issuance of ERCs,
and if so, what level of specificity with respect to that process we
should include in the final model rule. If not, or if the unit does not
go through a control area settlement process, we request comment on how
the data collection should be specified in the final model rule.
Finally, we request comment on the frequency with which data should be
collected, for all energy generating resources, of all sizes.
c. Nuclear EM&V Requirements. The EM&V requirements associated with
quantifying electricity generation from eligible nuclear energy
resources, and for documenting these requirements in EM&V plans and
reports are the same as the requirements for RE discussed in the
preceding subsection.
The EPA requests comment on all metering, measurement,
verification, and other requirements in this subsection, including the
appropriateness of their use for each type of nuclear energy resource
(including the relevant size and distribution of such resource) that
qualifies for issuance of ERCs for use in Clean Power Plan compliance.
We request comment on whether nuclear energy resources should be
subject to the same EM&V requirements as RE resources, and if not, we
request
[[Page 65005]]
comment on to which EM&V requirements nuclear energy resources should
be subject.
d. Non-Affected Combined Heat and Power EM&V Requirements. In
additon to the CHP specific EM&V requirements discussed below and in
the associated provisions in the model rule, all CHP must follow the
requirements for RE discussed in the preceding subsection, including
metering requirements, special treatment for units of less than 10
Kilowatt, and how to account for T&D losses.
In order to determine the incremental CO2 emission rate,
a CHP unit would monitor CO2 emissions and energy
output.\81\ The monitoring requirements are standard methods currently
in use and the requirements would depend on the size of the CHP units
and the fuel used in the unit.
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\81\ When a CHP unit uses biomass fuel, it must report both
total CO2 emissions and biogenic CO2
emissions. Proposed requirements for reporting biogenic
CO2 emissions are discussed below in the subsection
titled Biomass EM&V requirements.
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Non-affected CHP facilities \82\ with electric generating capacity
greater than 25 MW would follow the same monitoring and reporting
protocols for CO2 emissions and energy output as are
required for affected EGU CHP units. These requirements are discussed
in section IV.D.13 of this preamble. For non-affected CHP facilities
with electric generating capacity less than or equal to 25 MW, which
use only natural gas and/or distillate fuel oil, the low mass emission
unit CO2 emission monitoring and reporting methodology
outlined in 40 CFR part 75 is acceptable.
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\82\ A CHP facility may consist of one or more electric
generators.
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The EPA requests comment on all metering, measurement,
verification, and other requirements included in this subsection with
respect to CHP, including the appropriateness of their use for CHP
(including with respect to the size of the CHP resource). We request
comment on whether a CHP unit should be subject to the same EM&V
requirements as RE resources, and we request comment on any additional
EM&V requirements to which CHP units should be subject. Specifically,
we request comment on specifying in the final model rule that if a CHP
unit has an electric generating capacity greater than 25 MW, its EM&V
plan must specify that it will meet the requirements that apply to an
affected EGU under 40 CFR 62.16540. We also request comment on
specifying in the final model rule that if a CHP unit has an electric
generating capacity less than or equal to 25 MW, the EM&V plan must
specify that it will meet the low mass emission unit CO2
emission monitoring and reporting methodology in 40 CFR part 75. We
request comment on any alternatives to these measurement methodologies
that should be specified in the final model rule. We request comment on
any other requirements that should be included in the final model rule
regarding EM&V of CHP.
e. Biomass EM&V Requirements. A state plan that is adopting the
rate-based model rule must propose EM&V requirements for monitoring and
reporting biogenic CO2 emissions from the use of qualified
biomass at RE facilities that are eligible for adjusting a
CO2 emission rate. If a state proposes to use the monitoring
and reporting requirements for biogenic CO2 emissions in 40
CFR part 98 (40 CFR 98.3(c), 98.36(b)-(d), 98.43(b), and 98.46) in its
plan submission, those requirements are presumptively approvable. An
EM&V plan that addresses biomass RE must follow the requirements for
monitoring and reporting biogenic CO2 emissions from the
facility that were approved by the EPA in connection with the specific
state plan.
The EPA requests comment on all metering, measurement,
verification, and other requirements included in this subsection with
respect to biomass, including the appropriateness of their use for
qualified biomass. We request broad comment on the types of qualified
biomass feedstocks that should be specified in the final model rule, if
any. We request comment on the methods that we should specify in the
final model rule for the measurement of the associated biogenic
CO2 for such feedstocks, as well as what other requirements
we should specify in the final model rule related to qualfied biomass.
We request comment on any other requirements that should be included in
the final model rule regarding EM&V for qualified biomass. Detailed
discussion on the role of qualified biomass feedstocks can be found in
section IV.C.3 of this preamble.
f. Waste-to-Energy EM&V Requirements. A state plan that is adopting
the rate-based model rule must propose EM&V requirements for monitoring
and reporting biogenic CO2 emissions from waste-to-energy
facilities that are eligible for adjusting a CO2 emission
rate. If a state proposes to include the monitoring and reporting
requirements for biogenic CO2 emissions in 40 CFR part 98
(40 CFR 98.3(c), 98.36(b)-(d), 98.43(b), and 98.46) in its plan
submission, those requirements are presumptively approvable. The EPA
may approve other requirements of similar rigor, at its discretion. An
EM&V plan that addresses the biogenic CO2 emissions from a
waste-to-energy facility must follow the requirements for monitoring
and reporting biogenic CO2 emissions from the facility that
were approved by the EPA in connection with the specific state plan.
As discussed in the final EGs (see section VIII.K.1 of the final
EGs), only the portion of electric generation at a waste-to-energy
facility that is due to the biogenic content of the MSW may be used to
generate ERCs or counted by a state towards its achievement of its
obligations pursuant to this regulation.
The EPA requests comment on all metering, measurement,
verification, and other requirements included in this subsection with
respect to waste-to-energy, including the appropriateness of their use
for waste-to-energy. We request comment on whether a waste-to-energy
resource should be subject to the same EM&V as RE resources, and we
request comment on any additional EM&V requirements to which waste-to-
energy resources should be subject, including comment on any specific
methods for determining the specific portion of the total net energy
output from the resource that is related to the biogenic portion of the
waste that the EPA should include in the final model rule.
g. Demand-Side Energy Efficiency EM&V Provisions. This subsection
proposes EM&V provisions that will be presumptively approvable if
included in state regulations governing how EE is to be quantified by
EE providers and verified by independent entities acting on behalf of
the state. As noted above these proposed provisions apply to all
demand-side EE used to adjust an emission rate if a state adopts the
model rule. The EPA is soliciting comment on the incorporation of EE
for the federal plan and by extension the EM&V associated with it.
For all demand-side EE used to generate ERCs, the EPA is proposing
that the metric is MWh of electricity savings, which must be quantified
on an ex-post or real-time basis and defined as a reduction in
facility- or premises-level electricity consumption due to an EE
program, project, or measure.
(1) Common Practice Baseline
Based on public input and assessments of industry best-practice
protocols and procedures, the EPA is proposing that it is presumptively
approvable to quantify EE savings as the difference between actual
metered electricity usage after an EE program, project, or measure is
implemented, and a ``common practice baseline'' (CPB). A
[[Page 65006]]
CPB is the equipment that would most frequently be installed at the
time an existing piece of equipment fails or is replaced at the end of
its effective useful life--or that a typical consumer or building owner
would have continued using for the remainder of the equipment's
effective useful life--in a given circumstance (i.e., a given building
type, EE program type or delivery mechanism, and geographic region) at
the time of EE implementation. It defines what would commonly have
happened in the absence of the EE program, project, or measure.
The applicable CPB depends on a number of factors, such as
characteristics of the EE program, project, or measure, the mechanism
by which electricity customers are engaged, local consumer and market
characteristics, and the applicable building energy codes and product
standards (C&S), including the C&S compliance rate. Examples of
appropriate CPBs to apply in specific circumstances, which may be
presumptively approvable, can be found in the EPA's EM&V guidance. EE
providers must document the selected CPB in their EM&V plans, along
with clear documentation and discussion of the rationale,
applicability, and relevant data sources, protocols, and other
supporting information. Monitoring and verification reports must refer
to the EM&V plan and confirm that the CPB was appropriately applied.
(2) Methods Used To Quantify Savings From Energy Efficiency Programs
and Projects
This section proposes criteria that are presumptively approvable
for the general types of EM&V methods that EE providers may use to
quantify the MWh savings from demand-side EE programs, projects, and
measures. During the Clean Power Plan EG's public comment period, the
EPA received input indicating that state PUCs typically allow utilities
and other EE providers to use a range of EM&V methods that reflect
applicable circumstances and on-the-ground conditions (versus mandating
which methods must be used in a particular situation). Consistent with
this approach, the EPA is proposing to offer flexibility for EE
providers to select from three broad categories of EM&V methods to
determine savings.
These categories include project-based M&V, deemed savings, and
comparison group approaches such as randomized control trials (RCT).
Regardless of the approach selected, the EPA is proposing that annual
savings values must be quantified using these EM&V methods at specified
time intervals (in years) on a recurring basis over the effective
useful life of the EE project or measure in order to ensure accurate
and reliable savings values. To be presumptivey approable, the EPA is
proposing that EE providers must apply the above methods at a minimum
of 4-year intervals for building energy codes and product standards;
every 1, 2, or 3 years for publicly- or utility-administered EE
programs, depending on the program type, magnitude of savings, and
experience with the program; and annually for large individual
commercial and industrial projects, unless the EE provider can credibly
demonstrate why this is not possible and how the accuracy and
reliability of savings values will be maintained. The EPA is further
proposing that, to be presumptively approvable, the selected method,
associated assumptions, and data sources must be identified and
described in EM&V plans.
For comparison group approaches, the EPA is propsing that states
and EE providers can refer to the EPA's draft EM&V guidance for a
discussion of industry best-practice protocols and guidelines. Where
feasible, the EPA is proposing to encourage the use of RCT methods,
which determine savings on the basis of energy consumption differences
between a treatment group and a comparison group, and therefore
increase the reliability of results.
As noted above, an alternative to comparison group methods is the
use of deemed savings values, which establish pre-determined annual
electricity savings values for specific EE measures. The EPA is
proposing that the use of deemed savings values would be presumptively
approvable if those values (a) are documented in a publicly available
database (also known as a Technical Reference Manual (TRM)) that is
accessible on a public Web site, or is otherwise readily accessible;
(b) specify the conditions for which each deemed value can be applied,
including but not limited to climate zone, building type, and EE
implementation mechanism; and (c) are updated at a minimum of every 3
years to reflect the per-measure MWh savings documented in ex-post EM&V
studies that apply M&V or comparison group methods.
For M&V methods to be presumptively approvable, the EPA is
proposing is that industry best-practice protocols and/or guidelines
must be followed. Examples of acceptable best-practice protocols and
guidelines are provided in the EPA's EM&V guidance. EE providers can
consult the EM&V guidance to assess the applicability of these
technical resources to the EE programs and projects generating savings,
and must document how one or more best-practice protocols or guidelines
will be appropriately applied in EM&V plans (along with clear
documentation and discussion of the rationale, applicability, and
relevant data sources, and other supporting information). The EPA is
also proposing that monitoring and verification reports must refer to
the EM&V plan and confirm that the relevant M&V protocol or guideline
was properly applied.
(3) Quantifying Savings
Regardless of the approach used to quantify and verify MWh savings,
the EPA is proposing that EM&V plans must describe how they will
address the following provisions:
How major changes in independent variable conditions
(weather, occupancy, production rates, etc.) that affect energy
consumption and savings estimates will be accounted for. The EPA is
proposing that the effects of these changes must be calculated using
industry best-practices such as real-time conditions or normalized
conditions that are reasonably expected to occur throughout the
lifetime of the EE project or measure.
How the initial installation of EE will be verified for EE
program categories that involve the installation of identifiable
measures (e.g., most utility consumer-funded EE programs and project-
based EE are evaluated site-by-site). The EPA is proposing that
verification is required within the first year of program
implementation and that all verification activities must be performed
using industry best-practice techniques (e.g., phone or mail surveys,
document review, site inspections, spot or short-term metering). For
projects implemented as part of a larger program, the EPA is proposing
that verification can be performed using a sample of projects to
represent the full program population.
How avoided T&D system losses \83\ will be quantified and
applied to EE savings determined at the customer facility or premises.
The EPA is proposing that demand-side EE programs (other than T&D
efficiency measures such as conservation voltage regulation or
reduction (CVR) and volt/VAR optimization \84\) may adjust
[[Page 65007]]
reported savings by using a T&D adder. If such an adder is applied, the
presumptively approvable approach is to use the smaller of 6 percent or
the calculated statewide annual average T&D loss rate (expressed as a
percentage) calculated using the most recent data published by the U.S.
EIA State Electricity Profile.\85\
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\83\ T&D losses are defined as the difference between the
quantified EGU generation required to serve a customer's load
(measured at the EGU bus bar) and the customer's actual electricity
consumption (measured at the customer meter).
\84\ More information about these technologies is in section
VIII.F.1 of the final EGs.
\85\ Estimated losses in MWh, total electric supply, and direct
electricity use values are available in the U.S. EIA's State
Electricity Profiles. See Table 10 on Supply and Disposition of
Electricity. Direct electricity use refers to the electricity
generated at facilities that is not put onto the electricity grid,
and therefore does not contribute to T&D losses.
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How the duration of EE program or project electricity
savings will be determined. This must be determined using industry
best-practice protocols and procedures involving annual verification
assessments, industry-standard persistence studies, deemed estimates of
effective useful life (EUL), or a combination of all three.
How the accuracy and reliability of quantifying MWh
savings values will be assessed, and the rigor \86\ of the methods used
to control the types of bias or error inherent to the applied EM&V
methods. Sampling of populations is appropriate, provided that the
quantified MWh derived from sampling have at least 90 percent
confidence intervals whose end points are no more than +/-10 percent of
the estimate.
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\86\ Rigor refers to the level of effort expended to minimize
uncertainty from factors such as sampling error and bias. The higher
the level of rigor, the more confident one is that the results of
the EM&V activities are both accurate and precise.
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How double counting will be avoided through the use of
tracking and accounting procedures to ensure that the same MWh of
electricity savings is not claimed more than one time (for example, two
EGUs claiming savings from the same lighting retrofit). The types of
double counting that may arise are discussed in the EPA's draft EM&V
guidance.
(4) Use of Energy Efficiency EM&V Protocols
In the Clean Power Plan EG's public comments, the EPA heard that
EM&V protocols for demand-side EE are currently in wide use, and that
they should be continued and encouraged. The agency agrees with this
observation and is therefore proposing the application of industry
best-practice protocols and procedures for demand-side EE. In
particular, the EPA is proposing that, to be presumptively approvable,
EM&V plans must specify the use of best-practice protocols and
procedures, and must also include a clear description and documentation
of how the relevant protocols and procedures will be applied. EM&V
reports must include documentation of how such protocols and procedures
were actually applied. EE providers can refer to the EPA's EM&V
guidance document for information about protocols that are considered
``industry best-practice protocols and procedures.''
(5) Eligible Demand-Side Energy Efficiency (DS-EE) Programs and
Projects
There has been stakeholder interest expressed through the Clean
Power Plan EGs rulemaking process in allowing states to issue ERCs for
quantified and verified MWh savings from DS-EE under state plans.
Consistent with these perspectives, the EPA is proposing that any
demand-side EE program, project, or measure that results in MWh savings
may be potentially eligible to generate ERCs, including under this
proposed model trading rule, provided that they meet the presumptively
approvable provisions for eligibility described in section IV.C.3 of
this preamble, and that supporting EM&V is rigorous, transparent,
credible, complete and fulfills the requirements provided in the EGs
and the state plan. Examples of potentially eligible demand-side EE
program and project types include:
Publicly or utility-administered EE programs, including
those implemented in low-income residences and facilities.
Project-based EE evaluated site-by-site, for example those
implemented by ESCOs at commercial buildings and industrial facilities.
State and local government building energy code and
compliance programs.
State and local government incremental product energy
standards.
The EPA's EM&V guidance contains supplemental information about
applicable best-practice protocols, methods, and other key
considerations for quantifying and verifying savings from the above-
listed EE activities in an accurate and reliable manner. The agency
also recognizes that the programs and policies listed above will evolve
and change over the rule period, as new technologies emerge and
efficiency improves. The agency also expects that new EE program types
will emerge and expand throughout the rule period, and that MWh savings
resulting from any such programs can similarly be considered if they
meet the requirements of the EGs.
(6) Requests for Comment on Energy Efficiency EM&V
We request broad comment on each EE EM&V criterion described herein
and in the proposed rule text, for each type of EE activity, project,
program, or measure. Specifically, we seek comment on the substantive
content of the criteria, and we seek comment on the level of detail
provided regarding these criteria and whether more or less detail (and
what detail) should be included in the final model rule. In addition,
we seek comment on whether some of the EE EM&V criteria (and if so,
which criteria) included in the draft guidance document released
simultaneously with this proposed rulemaking should instead be included
in the final model rule, instead of in guidance. Similarly, we seek
comment on whether some of the EE EM&V criteria (and if so, which
criteria) included in the proposed model rule should instead be
addressed in the final EM&V guidance. More generally, we seek comment
on what EE criteria the EPA should described in guidance versus what
criteria the EPA should specify in the final model rule, whether or not
those criteria are already included in the draft guidance or proposed
model rule.
We request broad comment on the appropriate EE EM&V criteria for
quantifying the electricity savings from every type of EE program,
project, or measure. We request broad comment on what constitute EE
best-practice protocols and procedures for every type of EE program,
project, or measure.
We request broad comment on whether, when, and how common practice
baselines should and should not be used in calculating electricity
savings from EE activities, projects, programs, and measures, including
comment on which common practice baselines should be used in which
circumstances. We also request comment on whether some alternative
metric should be used in lieu of the common practice baseline and, if
so, what that metric should be.
We request broad comment on the appropriateness of quantifying
electricity savings by applying one or more of the following methods
and comment on all aspects of each method: Project-based measurement
and verification (PB-MV), comparison group approaches, or deemed
savings. We take further comment on circumstances in which it is
appropriate (or inappropriate) to use each of these methods, including
when it is appropriate to use RCT and quasi-experimental methods, and
the circumstances in which they can be encouraged and applied in
practice (e.g., when a suitable control or comparison group can be
identified and applied in a cost-effective manner). In addition, we
request comment on whether the general suitability and applicaton of
quantification methods, such as RCT,
[[Page 65008]]
quasi-experimental techniques or other comparison group approaches when
they are available at reasonable cost for purposes of quantifying MWh
savings for particular EE programs, projects, or measures.
If deemed savings are to be used in quantifying electricity savings
from an EE program, project, or measure, we request comment on the
appropriate characteristics and presumptively approvable provisions for
their use in generating qualifying ERCs, including the basis and
frequency for their determination, and the appropriateness of their
application to particular EE programs, projects or measures in
particular states or regions. We further request comment on the
presumptively approvable provision for public access and input to the
development of the technical reference manuals (TRMs) used to house the
applicable deemed savings values.
We request comment on the minimum and maximum intervals (in years)
over which electricity savings must be quantified, including those time
intervals specified in the proposed model rule, and we request comment
on any factors that must be taken into consideration when determining
the appropriate time interval for specific EE programs, projects, or
measures.
Because many states have different EE programs in place today, and
we would expect them to leverage these programs if they incorporated EE
into a rate-based trading scheme with ERCs, it is theoretically
possible that an ERC could be issued in one state that would not have
been issued in another, even if both states have rate-based programs in
place that meet all of the EGs. The EPA requests comment on what
criteria it should include in the final model rule, and what level of
details with respect to those criteria that it should include, in order
to ensure that an ERC issued for an EE program, project, or measure in
one state reflects the same MWh of energy or electricity saved in
another state. We further request comment on whether there are
provisions that the EPA should include in the final model rule that
would prevent an entity seeking to be issued an ERC (whether from EE or
energy generation) from forum shopping, in an effort to find a state
with standards for ERC issuance that it deems more lenient or less
burdensome than those in another state.
We request comment on how to appropriately consider factors that
affect energy savings in the quantification and verification process,
including those identified in the proposed model rule, and we request
comment on whether these factors should be addressed in every plan or
just certain types of plans. Such factors may include the effect of
changes in independent factors, effective useful life (and its basis),
and interactive effects of EE programs, projects, and measures.
We request comment on the circumstances and frequency in which
savings verification must occur to ensure that EE measures have been
installed, are functioning, and have the potential to save energy.
We request comment on the appropriate steps for avoiding double
counting, and how such steps should be documented in an EM&V plan. In
particular, we request comment on the circumstances and conditions in
which double counting is most likely to occur (including those
identified in this section), and the presumptively approvable
provisions that must be adopted in state plans for avoiding and
mitigating double counting.
We request comment on the appropriate means by which an EM&V plan
can ensure the accuracy and reliability of electricity savings
estimates, including the necessary rigor of the methods selected to
evaluate the electricity savings, the methods used to control all
relevant types of bias and to minimize the potential for systematic and
random error, and the potential effects of such bias and error. We
further request comment on the presumptively approvable provision that
samples taken to quantify EE program savings must achieve 90/10
confidence and precision.
We request comment on the presumptively approvable approach to
quantifying the electricity savings that result from avoiding a
transmission and distribution system loss, including the provisions in
the proposed model rule, which specify that each EM&V plan must
quantify the transmission and distribution loss based on the lesser of
6 percent of the site-level electricity consumption measured at the end
use meter or the statewide annual average transmission and distribution
loss rate (expressed as a percentage) from the most recent year that is
published in the U.S. EIA State Electricity Profile. We request comment
on the appropriateness of including a restriction in the final model
rule that no other transmission and distribution loss factors may be
used in calculating the electricity savings.
We request comment on any additional criteria that we should
include in the final model rule regarding EE EM&V.
h. Skill Certification Standards. Using a skilled workforce to
implement demand-side EE and RE projects and other measures intended to
reduce CO2 emissions, and to evaluate, measure and verify
the savings associated with EE projects or the additional generation
from performance improvements at existing EGU's are both important.
Several commenters on the EGs pointed out that skill certification
standards can help to assure quality and credibility of demand-side EE,
RE, and other carbon emission reduction projects. The EPA also
recognizes that a skilled workforce performing the EM&V is important to
substantiate the authenticity of emission reductions.
The EPA agrees that in conjunction with other EM&V measures
discussed in this section, and in the context of the model trading
rules although this is not an aspect needed for presumptive
approvability, states are encouraged to include in their plan a
description of how states will ensure that workers installing demand
side EE and RE projects, or other measures intended to reduce
CO2 emissions, as well as workers who perform the EM&V of
demand side EE and existing EGU performance will be certified by a
third party entity that:
Develops a training or competency based program aligned
with a job task analysis and/or certification scheme;
Engages with subject matter experts in the development of
the job task analysis and/or certification schemes that represent
appropriate qualifications, categories of the jobs, and levels of
experience;
Has clearly documented the process used to develop the job
task analysis and/or certification schemes, covering such elements as
the job description, knowledge, skills, and abilities;
Has pursued third-party accreditation aligned with
consensus-based standards, for example ISO/IEC 17024 or IREC 14732.
Examples of such entities include: Parties aligned with the DOE's
Better Building Workforce Guidelines and validated by a third party
accrediting body recognized by DOE; or parties aligned with an
apprenticeship program that is registered with the federal DOL, Office
of Apprenticeship; or parties aligned with a state apprenticeship
program approved by the DOL, or by another skill certification
validated by a third party accrediting body. Entities such as these can
help to substantiate the authenticity of emission reductions due to
demand-side EE and RE and other carbon emission reduction measures.
9. ERC Transfers and Trading
All affected EGUs that may be subject to this proposed federal plan
would be required to be a part of the ATCS that
[[Page 65009]]
the EPA runs, although the affected EGUs that are regulated under the
rate-based federal plan would use ERCs as a compliance instrument, not
allowances. To register to participate in the ATCS an affected EGU must
submit designated representative information. More information on the
designated representatives is described above in section IV.D.1 of this
preamble. Non-EGUs who wish to participate (e.g., RE sources) may
submit registration criteria to participate in the ATCS. The ATCS will
allow the trading and holding of ERCs that qualify for Clean Power Plan
compliance in a system that also will be used to determine compliance.
Quarterly, an affected EGU under the federal plan must submit
information and data consistent with part 75.\87\ These quarterly
submission dates are the 30th of April, July, October and January
corresponding with the quarterly data ending the month previous the
submission deadline (e.g., an April 30, 2024 submission would include
data from January through March of 2024). The data that are posted
online would be publicly available.
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\87\ See section IV.D.11 of this preamble for more information.
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Non-EGU ERC generating sources are required to submit generation
data annually (see section IV.C.3 of this preamble for a comprehensive
discussion of non-EGU ERC generating sources). The data must follow the
EM&V procedures delineated in section IV.D.8 of this preamble. Because
of the required rigor of the EM&V process, the EPA provides a time
frame of January 1 to June 1 of the year that follows the data's
inception to complete all EM&V processes (e.g, 2024 RE data must go
through the EM&V process and be submitted to the EPA no later than June
1, 2025). After receiving all emission and generation data from ERC
generating sources and affected EGUs, the EPA will issue ERCs through a
NODA as described in section IV.D.6 of this preamble. The EPA is
proposing to issue ERCs annually. ERCs are acquired and traded
throughout the compliance period. An affected EGU is responsible to
hold sufficient ERCs that qualify for Clean Power Plan compliance in
its ATCS compliance account by November 1 at midnight of the year
following the conclusion of the compliance period.\88\
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\88\ This true-up process is further described in section
IV.D.10 of this preamble.
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The process for transferring ERCs from one account to another is
quite simple. A transfer would be submitted providing, in a format
prescribed by the agency, the account numbers of the accounts involved,
the serial numbers of the ERCs 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 EPA and, when the Administrator attempted to record the transfer,
the transferor account included the ERCs identified in the form, the
Administrator would record the transfer by moving the ERCs from the
transferor account to the transferee account within 5 business days of
the receipt of the transfer form.
10. Compliance With Emissions Standards
Once the compliance period has ended, affected EGUs would have a
window of opportunity to evaluate their reported emissions and obtain
any ERCs that they might need to cover their emissions during the
compliance period. The agency proposes to require sources to
demonstrate compliance, i.e., ERC true-up, on November 1 of the year
after the last year in the compliance period. For example, if the first
compliance period comprises the three years 2022, 2023, and 2024, then
the ERC transfer deadline \89\ for that first compliance period (after
which point the EPA would evaluate compliance) would be on November 1,
2025. The agency also requests comment on an earlier ERC transfer
deadline, such as June 1 or March 1, of the year after the last year in
the compliance period. Each ERC issued in the proposed rate-based
trading program would, if applied, be averaged into the compliance rate
as one MWh of energy with zero CO2 emissions deemed
associated with it for the compliance period that includes the year for
which the ERC was issued or be averaged into a later compliance period.
Consequently, each affected EGU would need, as of the ERC transfer
deadline, to have in its compliance account enough ERCs usable for its
compliance obligations for the compliance period. The authorized
account representative could identify specific ERCs to be applied, 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. The ERCs that are used to meet compliance obligations are moved
from the compliance account to the EPA's retirement account. ERCs that
are deducted for compliance will remain in the system in an EPA
account, which ensures they will not be used again.
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\89\ The ``ERC transfer deadline'' is the deadline for
transferring allowances that can be used for compliance in the
previous compliance period to a source's compliance account.
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The EPA will use the submitted generation, CO2 emissions
and ERCs in the affected EGU's compliance account to calculate an
average emission rate for the EGU. It is the responsibility of an
affected EGU to calculate the number of ERCs that will need to be held
in a compliance account to meet the EGU's compliance obligations. The
method for determining the quantity of ERCs needed to meet compliance
obligations has been discussed previously in an example. To reiterate
the process, the affected EGU would need to solve for the number of
zero-emitting MWh (i.e., ERCs) that would need to be added to the total
MWh of the EGU to make the adjusted emission rate equal to the emission
standard.
[GRAPHIC] [TIFF OMITTED] TP23OC15.013
[[Page 65010]]
If an affected EGU fails to hold sufficient ERCs to comply with its
emission standard then, upon notification of the deficiency, the owners
and operators of the affected EGU must provide, for deduction by the
Administrator, two ERCs as soon as available for every ERC that the
owners and operators failed to hold as required to cover emissions, in
addition to the ERCs owed for compliance in that next period. The owed
ERCs will be deducted from the EGU's compliance account as soon as they
are available in this account; the Administrator will not wait until
the next true-up date to make this deduction. The two ERCs owed for
each ERC needed for compliance but not supplied is in addition to any
other recourse provided in sections 113(a)-(h) or section 304 of the
CAA. This requirement to surrender two times the ERCs needed to make up
the shortfall for the prior period is an ongoing obligation until
compliance is achieved, and there is an ongoing obligation to comply in
the current period. Failure to surrender these replacement ERCs is an
additional violation that may be subject to federal enforcement. The
EPA solicits comment on sources owing two ERCs to make up for each
insufficient ERC in previous compliance periods and whether two for one
is the proper make-up rate or whether there should be a stricter or a
more lenient ratio.
The EPA believes that it is important to include a requirement for
an automatic deduction of ERCs. The deduction of one ERC per ERC that
the owners and operators failed to hold would offset this failure. The
deduction of another ERC per ERC that the owners and operators failed
to hold provides a strong incentive for compliance with the ERC-holding
requirement by ensuring that non-compliance would be a significantly
more expensive option than compliance. This is consistent with other
existing trading programs.
11. Other ERC Tracking and Compliance Operations Provisions
These sections also would provide that the Administrator could, at
his or her discretion and on his or her own motion and consistent with
existing federal trading programs, correct any type of error that he or
she finds in an account in the ATCS. In addition, the Administrator
could review any submission under the rate-based trading program, make
adjustments to the information in the submission, and deduct or
transfer ERCs based on such adjusted information. These provisions are
a standard part of other trading programs administered by the EPA
including the ARP and the CSAPR (see, e.g., 40 CFR 72.96, 73.37,
97.427, and 97.428). The EPA solicits comment on potential alternatives
for error correction that may be simpler or more efficient.
12. Banking of ERCs
The EPA is proposing to allow unlimited banking of ERCs within and
between the interim and final compliance periods. This means that if an
affected EGU has more ERCs than are necessary during true-up, it may
save (i.e., bank) those ERCs for application during a future compliance
period. The EPA requests comment on whether there should be a
quantitative limit or cap on the number of ERCs that can be banked. The
EPA also requests comment on whether an ERC should be eligible to be
banked between the interim and final compliance periods. The EPA is
also proposing that ERCs will not expire after any duration of time.
Other trading rules that the EPA has instituted (e.g., CSAPR) do not
have expiration on the tradable properties. The EPA requests comment on
the shelf-life of an ERC.
ERC ``borrowing'' is a flexibility that the EPA is not proposing,
but is soliciting comment on. ERC borrowing is the concept that an
affected EGU may use an ERC that the EGU will acquire in a future
compliance period to meet its current compliance obligations. The EPA
requests comment on a methodology that would allow ERC borrowing while
maintaining the integrity of the compliance obligations. The EPA also
has reservations concerning this concept due to the fact that future
ERC generation is not guaranteed.
13. Emissions Monitoring and Reporting
The EPA would require that emission and generation data be reported
to the EPA quarterly starting on April 30, 2022, and continuing every 3
months thereafter (i.e., the 30th of April, July, October, and
January). The EPA proposes that affected EGUs subject to the rate-based
federal plan trading program would monitor and report CO2
emissions in accordance with 40 CFR part 75. The EPA is proposing to
require affected EGUs in all states covered by the rate-based federal
plan trading program to monitor and report CO2 emissions by
and output data by January 1, 2022. Quarterly reporting would be
required, with each quarterly report due to the Administrator 30 days
after the last day in the quarter. The reporting would be in accordance
with 40 CFR 75.60. The use of 40 CFR part 75 certified monitoring
methodologies would be required. Many affected EGUs that might be
covered by the proposed federal plans will generally have no changes to
their monitoring and reporting requirements and will continue to
monitor and submit reports under 40 CFR part 75 as they have under
existing programs. The EPA anticipates fewer than 50 (approximately 10
of these affected EGUs are coal fired with the remainder being gas and
oil fired that will qualify for an excepted monitoring methodology)
affected EGUs, that would not otherwise be subject to the ARP, will
have to purchase and install additional continuous emissions monitoring
system (CEMS) and data handling systems or upgrade existing equipment
in order to meet the monitoring and reporting requirements of this
program. Several of the affected EGUs not otherwise subject to the ARP
are subject to the MATS program and therefore will have already
installed stack flow rate and/or CO2 monitors in order to
comply with the MATS rule which are also necessary to comply with this
rule. The CEMS used to comply and report data for MATS will be used for
this rule to generate and report CO2 emissions data without
having to install duplicative monitors. The same CO2 and
stack gas flow rate monitored data used in conjunction with mercury and
other CEMS to calculate a toxic pollutant emission rate may be used to
calculate a CO2 mass or CO2 emission rate for
this program. The Regional Greenhouse Gas Initiative (RGGI), ARP, MATS
and this rule all refer to CEMS installed and certified in accordance
with 40 CFR part 75. RGGI and ARP currently require the reporting of
CO2 mass emissions on an hourly basis and cumulative totals
at the end of each calendar quarter. The same monitors and data
collected may be used for multiple purposes for RGGI, ARP, MATS and
this rule. Relying on the same monitors that are certified and quality
assured in accordance with 40 CFR part 75 ensures cost efficient,
consistent, and accurate data that may be used for different purposes
for multiple regulatory programs. The majority of the affected EGUs
covered by this rule are already affected by the Acid Rain and/or RGGI
programs and will have minimal additional monitoring and reporting
requirements.
The EPA also requests comment on requiring monitoring and reporting
of CO2 mass and net generation for the year before the
initial compliance period begins, i.e., to commence January 1, 2021.
Only monitoring and reporting would be required in 2021--compliance
with an enforceable emission standard would commence on the compliance
[[Page 65011]]
period schedule that is detailed in section III.D of this preamble.
E. Federal Plan and State Plan Interactions
1. Interstate Trading
The EPA proposes that all affected EGUs within states that are
covered by the federal plan, if a rate-based federal plan is finalized
for two or more states, would be allowed to trade with one another
since there will be an assured commonality in the ERC currency and
criteria surrounding the trading program. In addition, the EPA
proposes, consistent with the provision for ``ready-for-interstate-
trading'' plans in the EGs, that affected EGUs located in states with
approved ready-for-interstate-trading state plans using the
subcategorized uniform rate standards, and a common credit currency
(i.e., ERCs representing one zero-emitting MWh) may trade with affected
EGUs operating under the federal trading program established in this
federal plan.
Rate-based EGUs subject to the federal plan and rate-based EGUs in
ready-for-interstate-trading state plans will be able to trade ERCs
seamlessly across jurisdictional borders because of the assurances of
being presumptively approvable. Ready-for-interstate-trading states
must submit information that lists all affected EGUs and the EGU type
to the Administrator to be able to trade within the federal trading
program. To be able to trade in the federal trading program an affected
EGU that is subject to a ready-for-interstate-trading state plan must:
(1) Certify and authorize a designated representative per section
IV.D.1 of this preamble; and (2) register a general account in the
federal trading program, ATCS, in order to have a means of transferring
ERCs with entities operating in the federal trading program. An
affected EGU under a state plan will not register a compliance account
in the federal system because it will not be demonstrating compliance
under the federal plan. Compliance will be achieved in the affected
EGU's corresponding state plan. Affected EGUs under a state plan have
the ability to acquire ERCs through the federal trading program. These
ERCs will be stored in the EGU's general account in the federal trading
program. To use these ERCs for compliance purposes, the ERCs must be
transferred to the EGU's compliance account in the state's program. The
EPA proposes to provide software to states to maintain a state's
compliance and tracking program. A state's program will have the
capability to interact with the federal trading program and software,
ATCS, for transferring ERCs if the state is ready-for-interstate-
trading. A state's program can be tailored to meet its needs while
still providing a platform for a state to be transferring ERCs between
the state's system and the federal trading program. ERCs can flow
between a state system and the federal trading program bilaterally. The
EPA acknowledges that states may have additional criteria for
generating ERCs that are not outlined as part of the federal plan, but
because the EPA will have vetted these criteria through a state plan
approval these ERCs will be able to be traded within the federal
trading program.
2. Treatment of States Entering or Exiting the Trading Program
The EPA proposes that a rate-based trading federal plan may be
replaced by a state plan for a future compliance period. The EPA is
proposing that a state must transition to a state plan at the
conclusion of a federal plan compliance period. The EPA requests
comment on whether there are reasons that a state should be allowed to
transition from a federal plan to a state plan in the middle of a
compliance period and if so what requirements should be put in place to
do so while ensuring the integrity of both the federal plan and the
state plan and while enabling the affected EGUs covered by the plans to
understand and meet their compliance requirements. If a state subject
to the federal plan transitions to a state plan, any affected EGU
impacted by the change remains responsible for meeting any outstanding
obligations under the federal plan. To make the transition to a state
plan, a state must have an approved state plan as laid out in sections
VIII.D and VIII.E of the final EGs.
V. Mass-Based Implementation Approach
A. Trading Program Overview
In addition to the rate-based implementation approach discussed
above, the EPA is proposing a mass-based implementation approach for
the federal plan. As with the rate-based approach, this proposed
federal plan is also a proposed model trading rule that states can
adopt. The mass-based approach that the agency proposes to implement is
a mass-based trading program (i.e., an emissions budget trading
program, also referred to as an ``allowance system''). This section
provides a brief overview of the proposed mass-based trading program.
The next sections describe the various elements of the proposed trading
program in further detail.
A mass-based trading program establishes an ``aggregate emissions
limit'' that specifies the maximum amount of emissions authorized from
affected EGUs included in the program, and creates allowances that
authorize a specific quantity of emissions. The total number of
allowances created are equal to, and constitute, the emissions budget
or the aggregated emissions limit expressed in terms of short tons of
emissions. The EPA is proposing that allowances be issued in short tons
for the federal plan.
Each facility with affected EGUs in the program must surrender
allowances equal in number to the quantity of the emissions of its
affected EGUs during the compliance period. A facility with affected
EGUs may buy allowances from, or transfer or sell allowances to, other
affected EGUs or other entities that participate in the market. A mass-
based trading program provides sources with great flexibility in
choosing compliance strategies.
In the proposed mass-based trading program for the federal plan,
the aggregate emissions limit for a state is its statewide mass-based
emission goal (or ``mass goal'') as finalized in the Clean Power Plan
EGs. The proposed approach to linking states for interstate allowance
trading is detailed in section III.A.1 of this preamble; in an
interstate trading program the aggregate emissions limit is the sum of
the mass goals for the covered states.
The EPA believes that a broad trading region provides greater
opportunities for cost-effective implementation of controls compared to
a smaller region. Therefore, the agency proposes that an affected EGU
in any state covered by the proposed mass-based trading federal plan
may use for compliance an allowance distributed in any other state
covered by the mass-based trading federal plan. The EPA also proposes
to provide for allowance trading between affected EGUs and other
entities in states with approved mass-based-trading state plans that
meet the conditions specified in section III.A.1 of this preamble,
above, and affected EGUs and other entities in any state covered by the
federal plan mass-based trading program.
A mass-based trading program can provide environmental certainty at
lower cost than other policy mechanisms, because it assures the
specified emissions outcome while maximizing compliance flexibility
available to individual affected EGUs. Further, allowance banking in
such a program creates an incentive to make reductions earlier than
required. Mass-based trading programs are relatively
[[Page 65012]]
simple to operate, which reduces administrative time and cost.
Additionally, to inform the mass-based trading approach proposed here,
the EPA draws upon more than two decades of experience implementing
federally-administered mass-based emissions budget trading programs
including the ARP SO2 trading program, the NOX
Budget Trading Program, CAIR, and CSAPR.
In the proposed mass-based trading program federal plans, the
emissions limits in each state would be the mass goals that the EPA
promulgated in the Clean Power Plan EGs (if there is interstate trading
then the sum of the mass goals for the states in the trading program
would constitute the aggregate emissions limit). The total amount of
allowances distributed in each state for each year would sum to the
state's mass goal for that year. As detailed in section V.E of this
preamble, the EPA is proposing that a state covered by the federal plan
can determine its own approach to distribute allowances, and believes
that state allocation has important merits. The EPA would distribute
allowances in a state if the state does not choose to do so, as
detailed below.
Each allowance would authorize the emission of one short ton of
CO2 during the compliance period applicable to the
allowance's vintage year or a later compliance period. The proposed
approach to distribute allowances, including three types of allowance
set-asides, is discussed in section V.D of this preamble, below.
After each compliance period, an affected EGU would surrender for
compliance an amount of allowances equal to its emissions during the
course of the compliance period. See section V.C of this preamble for
the proposed length of the multi-year compliance periods. Allowances
could be transferred, bought, sold, or banked (carried over for future
use) and any party could participate in the allowance market. The EPA
is not proposing allowance ``borrowing'' (i.e., the bringing forward of
future-period allowances for use in an earlier period); the multi-year
compliance periods inherently provide the flexibility to schedule
relatively greater emission reductions for later years within each
period, as discussed further in section V.C of this preamble. In the
proposed mass-based trading program, the emission standard applied to
individual affected EGUs is the requirement to surrender emission
allowances equal to reported emissions for each compliance period.
The EPA also proposes that a state may choose to replace the
federal plan allowance-distribution provisions with its own allowance-
distribution provisions (i.e., to determine the distribution of
allowances for its EGUs or other entities) using a state allowance-
distribution methodology. State allowance distribution can have
important advantages, because it allows a state to design and shape
allowance allocation to its specific goals and characteristics, and
because states may have additional flexibility on allocation
approaches, including auctions. See section V.E of this preamble for
further discussion of the proposed approach for state-determined
allowance-distribution methodologies.
This proposed requirement to hold and surrender allowances equal to
emissions for each compliance period would apply to all reported
emissions from a facility's affected EGUs including any emissions from
co-fired biomass if biomass is included as an eligible measure. Section
IV.C.3 of this preamble discusses an approach on which the EPA requests
comment on the inclusion of biomass as an eligible measure and on a
proposed option where the agency would identify qualified biomass
feedstocks (i.e., biomass feedstocks that are demonstrated to be a
method to control increases of CO2 levels in the atmosphere)
and potential methods for demonstrating compliance, and thus reduce the
mass emissions attributed to a biomass co-fired affected EGU. If the
EPA took such an approach, then for purposes of compliance with the
proposed mass-based federal plan trading program, the affected EGU
would need to hold allowances equal to its emissions less the emissions
attributed to the co-fired qualified biomass; such an approach would
reduce the number of allowances the affected EGU would need to hold to
demonstrate compliance. The EPA requests comment on this approach.
B. Statewide Mass-Based Emissions Goals
In the Clean Power Plan EGs the EPA established statewide mass-
based emission goals (``mass goals'') for all states that are
equivalent to the rate-based goals. As discussed in section V.C of this
preamble, below, the EPA proposes to implement the mass-based trading
program with multi-year compliance periods that are consistent with the
compliance timing provisions in the Clean Power Plan EGs, i.e., two 3-
year compliance periods followed by a 2-year compliance period in the
Interim Period, and successive 2-year periods in the Final Period. In
the Clean Power Plan EGs, the EPA established mass goals for all states
for this pattern of compliance periods. The EPA proposes to use those
mass goals promulgated in the Clean Power Plan EGs as the mass limits
(i.e., emissions budgets) for any state covered by the mass-based
trading program (or, if implementing interstate trading, then the EPA
would use the sum of a covered group of states' mass goals as the
aggregate mass limit). The EPA is not opening for comment the
determinations, made in the Clean Power Plan EGs, of each state's mass
goals. The mass goals are provided for convenience in Table 8 of this
preamble.
Table 8--Statewide Mass-Based Emission Goals (``Mass Goals'')
[Short tons]
----------------------------------------------------------------------------------------------------------------
Interim period Final period
---------------------------------------------------------------
State Step 1 2022- Step 2 2025- Step 3 2028- 2030-2031 and
2024 2027 2029 thereafter
----------------------------------------------------------------------------------------------------------------
Alabama......................................... 66,164,470 60,918,973 58,215,989 56,880,474
Arizona *....................................... 35,189,232 32,371,942 30,906,226 30,170,750
Arkansas........................................ 36,032,671 32,953,521 31,253,744 30,322,632
California...................................... 53,500,107 50,080,840 48,736,877 48,410,120
Colorado........................................ 35,785,322 32,654,483 30,891,824 29,900,397
Connecticut..................................... 7,555,787 7,108,466 6,955,080 6,941,523
Delaware........................................ 5,348,363 4,963,102 4,784,280 4,711,825
Florida......................................... 119,380,477 110,754,683 106,736,177 105,094,704
Georgia......................................... 54,257,931 49,855,082 47,534,817 46,346,846
[[Page 65013]]
Idaho........................................... 1,615,518 1,522,826 1,493,052 1,492,856
Illinois........................................ 80,396,108 73,124,936 68,921,937 66,477,157
Indiana......................................... 92,010,787 83,700,336 78,901,574 76,113,835
Iowa............................................ 30,408,352 27,615,429 25,981,975 25,018,136
Kansas.......................................... 26,763,719 24,295,773 22,848,095 21,990,826
Kentucky........................................ 76,757,356 69,698,851 65,566,898 63,126,121
Lands of the Fort Mojave Tribe.................. 636,876 600,334 588,596 588,519
Lands of the Navajo Nation...................... 26,449,393 23,999,556 22,557,749 21,700,587
Lands of the Uintah and Ouray Reservation....... 2,758,744 2,503,220 2,352,835 2,263,431
Louisiana....................................... 42,035,202 38,461,163 36,496,707 35,427,023
Maine........................................... 2,251,173 2,119,865 2,076,179 2,073,942
Maryland........................................ 17,447,354 15,842,485 14,902,826 14,347,628
Massachusetts................................... 13,360,735 12,511,985 12,181,628 12,104,747
Michigan........................................ 56,854,256 51,893,556 49,106,884 47,544,064
Minnesota....................................... 27,303,150 24,868,570 23,476,788 22,678,368
Mississippi..................................... 28,940,675 26,790,683 25,756,215 25,304,337
Missouri........................................ 67,312,915 61,158,279 57,570,942 55,462,884
Montana......................................... 13,776,601 12,500,563 11,749,574 11,303,107
Nebraska........................................ 22,246,365 20,192,820 18,987,285 18,272,739
Nevada.......................................... 15,076,534 14,072,636 13,652,612 13,523,584
New Hampshire................................... 4,461,569 4,162,981 4,037,142 3,997,579
New Jersey...................................... 18,241,502 17,107,548 16,681,949 16,599,745
New Mexico *.................................... 14,789,981 13,514,670 12,805,266 12,412,602
New York........................................ 35,493,488 32,932,763 31,741,940 31,257,429
North Carolina.................................. 60,975,831 55,749,239 52,856,495 51,266,234
North Dakota.................................... 25,453,173 23,095,610 21,708,108 20,883,232
Ohio............................................ 88,512,313 80,704,944 76,280,168 73,769,806
Oklahoma........................................ 47,577,611 43,665,021 41,577,379 40,488,199
Oregon.......................................... 9,097,720 8,477,658 8,209,589 8,118,654
Pennsylvania.................................... 106,082,757 97,204,723 92,392,088 89,822,308
Rhode Island.................................... 3,811,632 3,592,937 3,522,686 3,522,225
South Carolina.................................. 31,025,518 28,336,836 26,834,962 25,998,968
South Dakota.................................... 4,231,184 3,862,401 3,655,422 3,539,481
Tennessee....................................... 34,118,301 31,079,178 29,343,221 28,348,396
Texas........................................... 221,613,296 203,728,060 194,351,330 189,588,842
Utah *.......................................... 28,479,805 25,981,970 24,572,858 23,778,193
Virginia........................................ 31,290,209 28,990,999 27,898,475 27,433,111
Washington...................................... 12,395,697 11,441,137 10,963,576 10,739,172
West Virginia................................... 62,557,024 56,762,771 53,352,666 51,325,342
Wisconsin....................................... 33,505,657 30,571,326 28,917,949 27,986,988
Wyoming......................................... 38,528,498 34,967,826 32,875,725 31,634,412
----------------------------------------------------------------------------------------------------------------
* Excludes EGUs located in Indian country within the state.
C. Compliance Timing and Allowance Banking
The EPA proposes to evaluate compliance (i.e., compare emissions
from affected EGUs to allowances held by facilities) in multi-year
periods. A multi-year compliance period provides greater flexibility to
affected EGUs and reduces administrative burden, compared to a single-
year compliance period. The EPA seeks to strike a reasonable balance
between providing flexibility and reducing burden while assuring that
any noncompliance can be addressed in a timely fashion.
The compliance periods in the proposed mass-based trading program
would be the same as promulgated in the Clean Power Plan EGs, i.e., the
Interim Period would be divided into three compliance periods: A 3-year
compliance period (2022 through 2024), a second 3-year compliance
period (2025 through 2027), and then a 2-year compliance period (2028
and 2029), for the Interim Period. As in the EGs, the Final Period
would be divided into successive 2-year compliance periods commencing
in 2030. The EPA would evaluate compliance only after the end of a
compliance period in the mass-based trading federal plan, e.g., if a
compliance period is 3 years long, the agency would evaluate compliance
only after the end of the third year in the period. The EPA is not
reopening for comment the compliance periods promulgated in the Clean
Power Plan EGs.
Some existing GHG mass-based trading programs (i.e., emissions
budget trading programs) use multi-year compliance periods. The RGGI
uses 3-year compliance periods, along with intervening compliance
requirements. The RGGI intervening compliance requirement is that
sources must hold allowances to cover 50 percent of emissions for the
first two calendar years of each 3-year compliance period; at the end
of each 3-year compliance period sources must hold allowances to cover
100 percent of emissions for the period and allowances already deducted
for the intervening requirement are
[[Page 65014]]
subtracted from the 3-year obligation.\90\ The California Air Resources
Board (CARB) Cap-and-Trade Program also uses 3-year compliance periods,
along with intervening compliance requirements. The CARB intervening
requirement is to evaluate compliance on 30 percent of each source's
previous year's emissions every year, and evaluate compliance for the
remainder of emissions every 3 years.\91\ The EPA proposes to evaluate
compliance after each multi-year compliance period and is not proposing
to implement intervening compliance requirements such as those in the
RGGI or CARB programs, however, the agency requests comment on the
inclusion of such requirements.
---------------------------------------------------------------------------
\90\ RGGI, Summary of RGGI Model Rule changes: February 2013.
http://www.rggi.org/docs/ProgramReview/_FinalProgramReviewMaterials/Model_Rule_Summary.pdf Accessed June 9, 2015.
\91\ Overview of ARB Emissions Trading Program. http://www.arb.ca.gov/cc/capandtrade/guidance/cap_trade_overview.pdf.
Accessed June 9, 2015.
---------------------------------------------------------------------------
The EPA recognizes that the compliance periods provided for in this
rulemaking are longer than those historically and typically specified
in CAA rulemakings. As reflected in long-standing CAA precedent,
``[t]he time over which [the compliance standards] extend should be as
short term as possible and should generally not exceed one month.'' See
e.g., June 13, 1989 Guidance on Limiting Potential to Emit in New
Source Permitting and January 25, 1995 Guidance on Enforceability
Requirements for Limiting Potential to Emit through SIP and Sec. 112
Rules and General Permits. The EPA determined that the longer
compliance periods provided for in this rulemaking are acceptable in
the context of this specific rulemaking because of the unique
characteristics of this rulemaking, including that CO2 is
long-lived in the atmosphere, and this rulemaking is focused on
performance standards related to those long-term impacts.
The EPA proposes that allowances may be banked for use in any
future compliance period, with no restriction on the use of banked
allowances, including from the Interim Period (2022 through 2029) into
the Final Period (2030 and thereafter). The agency requests comment on
the proposal to provide for unlimited allowance banking including the
banking of Interim-Period allowances for use during the Final Period.
Allowance ``borrowing'' is a type of timing flexibility wherein
allowances from a future compliance period may be ``brought forward''
and used for compliance in an earlier compliance period (thus reducing
the amount of allowances available for the future period). The EPA
notes that the proposed multi-year compliance periods inherently
provide the flexibility to emit at relatively higher amounts in earlier
years of a given compliance period by using allowances from future
years within each compliance period (e.g., if the first compliance
period covers years 2022 through 2024, a vintage 2024 allowance could
be used to cover a ton emitted in 2022). The EPA is not proposing to
allow allowance borrowing across compliance periods in the mass-based
trading federal plans; however the agency requests comment on the use
of borrowing across compliance periods.
Allowance borrowing across compliance periods would increase the
complexity of the proposed mass-based trading program and reduce the
flexibility for states to replace the federal plan with an approved
state plan. First, in order for borrowing to occur, the EPA would have
to make allowances from future compliance periods available early so
that sources could use these future allowances in earlier compliance
periods. The EPA proposes to record allowances in source accounts for
one compliance period at a time in order to maximize the opportunities
for a state to replace the federal plan (or replace the allowance-
distribution provisions of the federal plan) with an approved state
plan (or approved state allowance-distribution methodology). The EPA
proposes to allow a state to replace the mass-based trading federal
plan (or the federal plan allowance-distribution provisions) with a
state plan (or state allowance-distribution methodology) for a
compliance period for which the agency has not yet recorded allowances
in source accounts. Recording allowances for multiple compliance
periods at once--in order to make future-period allowances available
for borrowing--would therefore limit these opportunities for states to
take over implementation (or implementation of the allowance-
distribution).
If allowance borrowing from a future compliance period were
allowed, and the EPA provided the opportunity for a state to replace
the federal plan for a year for which allowances had already been
borrowed and retired for compliance in an earlier period, those
borrowed allowances would constitute additional emissions beyond the
levels specified in the Clean Power Plan EGs. In that event, the EPA
would then need to address whether and how to remove allowances from
circulation to prevent inflation of the allowable emissions at affected
EGUs in the remaining states subject to the federal plans (to ``repay''
the borrowed allowances). To avoid disruption to sources already
subject to the mass-based trading federal plan, the EPA is not
proposing to allow allowance borrowing across compliance periods.
Although not proposing to provide for allowance borrowing across
compliance periods, the agency requests comment on the potential
inclusion of allowance borrowing in the proposed mass-based trading
federal plans, including from how far into the future to allow
allowances to be borrowed, how inclusion of borrowing would affect
opportunities for states to take over implementation of the EGs (or
implementation of the allowance-distribution provisions in the mass-
based trading federal plan), how to address removing the extra
allowances from circulation that would result if borrowed allowances
originate in a state that subsequently withdraws from the mass-based
trading program, and on other complexities that borrowing across
compliance periods would introduce.
The agency proposes to require sources to demonstrate compliance,
i.e., allowance true-up, on May 1 of the year after the last year in
the compliance period. For example, if the first compliance period
comprises the three years 2022, 2023, and 2024, then the allowance
transfer deadline \92\ for that first compliance period (after which
point the EPA would evaluate compliance) would be on May 1, 2025. The
agency also requests comment on an earlier or later allowance transfer
deadline.
---------------------------------------------------------------------------
\92\ The ``allowance transfer deadline'' is the deadline for
transferring allowances that can be used for compliance in the
previous compliance period to a source's compliance account. For
further information see section V.G of this preamble.
---------------------------------------------------------------------------
The EPA proposes to evaluate compliance (i.e., allowance true-up)
at the facility level, not at the individual affected-EGU level, in the
mass-based trading program. Facility-level compliance may ease
implementation compared to unit-level compliance; each facility has a
single compliance account in which to hold allowances to cover
emissions from all its affected EGUs rather than having individual
unit-level compliance accounts. Fewer accounts may make it easier for
the designated representatives to manage their allowances. The EPA has
adopted facility-level compliance in previous emissions budget-trading
programs including the ARP, see 70 FR 25162, at 25296-98 (May 12,
2005); the CAIR FIP, see 71 FR 25328, at 25365 (April 28, 2006); and
the CSAPR, see 75 FR 45210, at 45323 (August 2, 2010). The EPA
[[Page 65015]]
would continue to track unit-level emissions--while evaluating
compliance at the facility level--allowing us to track increases and
decreases of pollutants at individual EGUs.
D. Initial Distribution of Allowances
Establishing a mass-based trading program requires that
policymakers establish an approach for the initial distribution of
allowances, historically referred to as ``allowance allocation.'' The
EPA believes that states may be well positioned to design their own
allowance distribution approach because they can take into account a
wide range of considerations and tailor decisions to the particular
characteristics and preferences of their state. The EPA proposes that
states have the flexibility to determine their own approach for
distributing allowances in the federal plan, through a process that is
detailed in section V.E of this preamble. The EPA believes that states
should have the opportunity to make decisions about allowance
distribution and that they may have additional flexibility on
approaches, including allowance auctions. The EPA is also proposing an
allocation approach that we intend to use in the event we implement the
federal plan in a state that does not choose to determine its own
allowance-distribution approach. The EPA requests comment on all of
these, and any other, approaches to distribute allowances.
The initial allowance allocation approach that is based on
historical data does not affect the environmental results of the
program or generation patterns; regardless of the manner in which
allowances are initially distributed, the finite total number of
allowances limits allowable emissions across all affected EGUs.
Allowance allocations also are not intended to prescribe or suggest any
unit-level compliance requirements nor do they limit unit-level
operational flexibility, because a mass-based trading program provides
operators of affected EGUs with the flexibility to buy, sell, or bank
allowances. Allowance allocation is simply a procedure by which
allowances are distributed into the marketplace so that they may be
available for affected EGUs to acquire as desired to authorize
emissions under the program. However, because these allowances are
finite in number and thus a limited resource, they have value, and as a
result, initial allowance allocations may raise issues of equity among
recipients.
Thus the agency recognizes that its choice of allocation
methodology is important from the perspective of distributional
effects, and the importance of selecting an approach that is fair and
reasonable in light of this consideration and the overall purpose of
CAA section 111 informs the agency's thinking in this proposal. We also
invite comment on these considerations, and on any other factors or
considerations which commenters believe should inform the allocation
method.
The EPA believes that the most reasonable basis for an initial
allowance allocation procedure is an approach that uses historical data
reported by the affected EGUs subject to the requirement to hold
allowances under this program. This approach relies on known data
rather than future projections. The EPA believes this approach is
preferable because any approach tied to future indicators (e.g., the
expected future EGU-level pattern of emissions or the ultimate use of
allowances) would depend on future outcomes that the EPA cannot project
with perfect certainty in advance. Basing allocation on historical data
is also consistent with the EPA's approach to initial allowance
allocation under previously established mass-based trading programs.
The EPA proposes to allocate most CO2 emission
allowances to existing affected EGUs in each state covered by a final
mass-based trading federal plan, with set-asides for a portion of
allowances (discussed in more detail below). For each compliance
period, the agency would distribute CO2 allowances in each
covered state in the amount of the state's CO2 ``mass goal''
(i.e., the state's CO2 statewide mass-based emission goal as
promulgated in the Clean Power Plan EGs) for that compliance period.
For example, if a compliance period is 3 years long, the EPA would
aggregate and distribute allowances for all 3 years at the same time.
The agency is not proposing to allocate allowances to new EGUs, which
do not have a compliance obligation under this proposed federal plan.
For each year of the program, the agency proposes to allocate most of
the allowances directly to affected EGUs using a historical-generation-
based approach. The EPA is also proposing three set-asides of
allowances, which are detailed below.
Although the EPA cannot anticipate the future EGU-level pattern of
emissions, it is possible to consider potential future emission
patterns at the source subcategory level. In developing the Clean Power
Plan EGs, the agency conducted analysis of emission reduction potential
in the two affected EGU source subcategories, i.e., electric utility
steam generating units (steam generating units) and NGCC units. With
that analysis as a basis, the EPA requests comment on an alternative
allocation approach that would first divide the total number of
allowances from each state's mass goal into source subcategories based
on analysis done in developing the source category-specific
CO2 emissions performance rates promulgated in the EGs and
then allocate to affected EGUs within each category based on shares of
historical generation. This alternative is described later in this
section.
The EPA recognizes that states may prefer different approaches to
distribute CO2 allowances from the EPA's approach and that
there may be advantages in having states tailor and apply their own
allocation approach. Therefore, the agency is proposing that a state
may choose to replace the federal plan allowance-distribution
provisions with its own allowance-distribution provisions, using any
approach to distribute allowances that the state chooses, including
methods that the EPA is not proposing here, provided that the state's
approach addresses emissions leakage and includes a Clean Energy
Incentive Program. The proposed requirements for addressing leakage, as
well as how the EPA proposes to implement the Clean Energy Incentive
Program for the mass-based federal plan, are detailed in sections V.E
and V.D.4 of this preamble, respectively.\93\ The EPA proposes that a
state could choose its own method for distributing allowances for any
compliance period including the first period that would commence in
2022. The proposed process for a state to replace federal plan
allowance-distribution provisions with its own allowance-distribution
provisions is detailed in section V.E of this preamble.
---------------------------------------------------------------------------
\93\ As detailed in section V.E in this preamble, we propose
that a state that chooses to determine its own allowance-
distribution approach under the proposed federal plan must address
leakage through its allocation strategy (such as the set-aside
approaches in section V.D.3 of this preamble). We request comment on
whether a state may make a justification regarding leakage as
detailed in section V.E of this preamble.
---------------------------------------------------------------------------
The following sections discuss and request comment on the EPA's
proposed approach to allocate CO2 allowances to affected
EGUs based on shares of historical generation, the proposed timing of
allowance recordation, three proposed allowance set-asides, allocations
to units that change status, and the proposed approach for states to
replace federal plan allocation provisions with their own allowance-
distribution approaches. In addition, we
[[Page 65016]]
request comment on alternative allowance distribution approaches--such
as auctioning or allocations to load-serving entities--that the EPA or
states might adopt. The EPA requests comment on all of these aspects of
allowance distribution.
1. Proposed Allocation Approach and Alternatives
The EPA proposes to allocate most of the CO2 allowances
in the mass-based trading program to affected EGUs based on historical
generation (output) data. The EPA also proposes three allowance set-
asides. The first would set aside a portion of allowances in each state
from the first compliance period only; this set-aside is for a proposed
Clean Energy Incentive Program that is detailed in section V.D.4 of
this preamble. The second would set aside a portion of allowances in
each compliance period except for the first period; the EPA proposes to
distribute allowances from this set-aside to affected EGUs via an
updating output-based approach as detailed in section V.D.3 of this
preamble). The third would set aside 5 percent of allowances in each
state, in all compliance periods, to be distributed to RE projects as
detailed in section V.D.3 of this preamble. In summary, the proposed
set-asides include:
(1) Clean Energy Incentive Program. This set-aside would be of
first compliance period allowances only.
(2) Output-based allocation set-aside. This set-aside would
start in the second compliance period and continue for each
compliance period.
(3) Renewable energy set-aside. This set-aside would be
implemented in all compliance periods.
This section describes the proposed historical-generation-based
approach that the agency would use to allocate all allowances except
for the set-aside allowances. The EPA is proposing affected-EGU-level
allocations (based on available data) in every state. Further detail on
this proposed allocation approach is provided in the Allowance
Allocation Proposed Rule TSD in the docket. The affected-EGU-level
allocations resulting from this proposed historical-generation-based
approach are provided in the docket in an appendix to the TSD. The
agency requests comment on the proposed historical-generation-based
allocation approach and on other allocation approaches.
The EPA proposes to allocate the historical-generation-based
portion of the allowances (i.e., the mass goal minus the set-asides)
\94\ to individual affected EGUs based on each affected EGU's share of
the state's historical generation, using 2010 through 2012 data. The
calculation steps for this proposed historical-generation-based
allocation approach are as follows:
---------------------------------------------------------------------------
\94\ In the first compliance period this would be the mass goal
minus the Clean Energy Incentive Program set-aside and the RE set-
aside. In all other compliance periods this would be the mass goal
minus the output-based allocation set-aside and the RE set-aside.
---------------------------------------------------------------------------
(1) For each unit in the list of likely affected EGUs in each
state, identify annual net generation values for the historical period
of 2010 through 2012 (reflecting affected-EGU-specific generation
assumptions incorporated in the data adjustments, e.g., assumed
capacity factor for ``under construction'' units). For a year for which
an affected EGU has no generation data (e.g., a year before the year
when a unit started operating), assign the affected EGU a value of
zero.\95\ (See step 2, below, for how zero values would be treated in
the calculations.)
---------------------------------------------------------------------------
\95\ The EPA proposes that for affected EGUs that were under
construction and began operation during 2012 or after 2012 (and thus
don't have a full year of generation data from the 2010 through 2012
period), the allocation calculations be based on the same 2012
generation estimate as the agency used in the Clean Power Plan EGs
for the goal-setting calculations. That is, the EPA proposes to
estimate 2012 generation for such units based on a unit's net summer
capacity and assuming a 55 percent capacity factor for gas units and
a 60 percent capacity factor for steam units.
---------------------------------------------------------------------------
The EPA proposes to use a 3-year historical period (i.e., 2010
through 2012) to reflect unit-level operations over time. In the Clean
Power Plan EGs, the EPA identified a reasonable basis for using
aggregate data at the regional level largely based on the most recent
data year (in that case, 2012) to inform the establishment of category-
wide EGs (as opposed to individual, unit-specific parameters). As a
distinct matter, in this context the EPA is considering data at the
unit level to inform unit-specific initial allowance allocations;
notwithstanding that these allowance allocations do not impose any
unit-level compliance requirements in and of themselves, the EPA finds
it reasonable to consider a multi-year data period to inform unit-level
initial allocations in order to consider a broader range of unit-
specific operations over time.
(2) Determine each affected EGU's average generation value by
averaging all (non-zero) 2010 through 2012 annual generation values for
the unit. The proposed approach would use only non-zero values in
calculating a unit's average generation. For example, if generation
data for a unit were available for only 2011 and 2012 then the EPA
would only use the 2011 and 2012 values to determine the unit's
unadjusted average generation value. The EPA included generation from
all units in the historical data set in the proposed allowance
calculations and calculated allowances for all such units; the agency
requests comment on the treatment of generation from and allocations to
units that operated in the historical data set but retire before the
start of the program.
(3) In each state, sum the average generation values from all
affected EGUs to obtain that state's ``total average historical
generation.''
(4) Divide each affected EGU's average generation value by the
state's total average historical generation to determine that affected
EGU's share of the state's total average historical generation.
(5) Multiply each affected EGU's share of the state's total average
historical generation by the historical-generation-allocation portion
of the state's mass goal (i.e., the state's mass goal minus the set-
asides) to determine that affected EGU's allocation.
The agency believes that this proposed historical-generation-based
allocation approach is a reasonable approach for several reasons:
The agency believes that the proposed historical-
generation-based approach maximizes transparency and clarity of
allowance allocations. The EPA has placed in the docket the historical
generation data and the calculations used to determine the proposed
affected-EGU-level allocations. The agency also placed the proposed
affected-EGU-level allocations, resulting from these calculations, into
the docket. These calculations can be relatively easily replicated.
To calculate allocations, the EPA proposes to use
historical affected-EGU-level net generation data compiled using a
methodology similar to the Emissions & Generation Resource Integrated
Database methodology. The proposed calculation approach is described
further below and in the Allowance Allocation Proposed Rule TSD in the
docket. The historical-data methodology is described in the
CO2 Emission Performance Rate and Goal Computation TSD for
Clean Power Plan Final Rule. The majority of the generation-unit-level
data in this approach are from reports that emissions sources submit to
the EPA under 40 CFR part 75 and to the EIA on forms EIA-860 and EIA-
923. The EPA believes these are the best data available to the agency
at the time of this proposed rule for calculating affected-EGU-level
allocations.
Allocating based on historical data (as opposed to data
not yet reported)
[[Page 65017]]
allows for the distribution of allowances prior to the start of the
program, which can facilitate compliance planning.
The proposed approach is transparent, based on reliable data, and,
like the approaches used in the NOX SIP Call, the ARP, and
CSAPR, based on historical data. For all these reasons, the agency
believes that it is appropriate to use a historical-generation-based
allocation methodology in this proposed rule. The EPA also requests
comment on a historical-data approach based on historical emissions.
The proposed historical-data-based allocations approach would not
generally affect the ultimate pattern of generation across individual
power plants, as compared to other methods of allocation. The
combination of plants, and their contributing generation, that will be
used to meet a particular demand for electric power will be based on
the relative efficiency (cost of production) of available plants. The
relevant measure of this efficiency is the marginal cost of generation,
which for a particular power plant would be the sum of the cost of
additional fuel to generate an additional MWh, additional maintenance
costs to increase output by an additional MWh, and costs associated
with the additional emissions that result from generating an additional
MWh. In a mass-based trading program, additional emissions must be
covered by additional allowances, so the cost of emitting is the price
of the allowances that must be consumed to authorize those emissions.
These emissions-related costs of electricity production are the same
regardless of whether the allowances used to cover those emissions were
initially allocated to the user or whether they were acquired
subsequently in the marketplace.
The same concept applies to any other cost of electricity
production. For example, a coal-fired EGUs operator would account for
the cost of consuming coal to produce generation whether or not the
coal was discovered already on-site, given to the unit at ``no
charge'', or purchased from the marketplace; in all cases, the
combustion of that coal consumes its value (i.e., it can no longer be
sold). Similarly, the approach taken to distribute allowances does not
affect the cost accounting for emissions at units because the use of
any tradable allowance has an opportunity cost--a firm loses the
opportunity of selling an unneeded allowance when it emits an
additional ton. Because a firm loses the opportunity of selling an
unneeded allowance when it emits an additional ton, even the emission
of a ton covered by a ``free'' allowance causes the generator to incur
the cost of emissions based on the market price of allowances the owner
must forgo by emitting that ton and using that allowance.
The proposed historical-data-based allocation approach would not be
expected to have any effect on freely competitive electricity markets,
because the marginal cost of emitting under the mass-based trading
program is determined by the level of the overarching mass goals and is
not affected by the distribution of the underlying allowances. This
marginal cost of emitting is what will inform prices, outputs, and
competition among power plants. While cost-of-service markets are
structured differently from competitive markets, the regulated utility
still makes the dispatch decision on the basis of marginal costs among
the units in its fleet, which is not affected by the amount of
allowances that any particular unit in that fleet was initially
allocated (assuming a competitive allowance market).
The EPA recognizes that some stakeholders are concerned about the
potential future distribution of emissions at the facility level, and
possible effects on communities. However, for the reasons discussed in
the above paragraphs, allowance allocations that do not change based on
future activity (such as allocations under the proposed historical-
generation-based approach) do not affect the distribution of emissions
under the program. This proposed rule is expected to achieve
significant emission reductions across the electric power sector; see
section IX of this preamble for discussion of anticipated broad
benefits to communities.
In addition to the proposed historical-data-based allocations
approach, the EPA also requests comment on other allocation approaches.
One alternative approach on which the agency requests comment is
similar to the proposed approach in that it allocates allowances based
on historical generation. However, this alternative approach would
divide the total number of allowances from a state's mass goal (minus
the set-asides) into affected EGU source categories--based on analysis
done in developing the source category-specific CO2
emissions performance rates promulgated in the Clean Power Plan EGs--
before determining unit-level allocations. The EPA requests comment on
this alternative approach because dividing the allowances in a state by
source category in this manner may result in an initial distribution of
allowances that would be closer at the source-category level to the
future category-level pattern of emissions, and thus to allowances
ultimately used, than the proposed approach. To the extent that this
category-level division of allowances is a reasonable proxy for the
future category-level emissions pattern under the program, this
approach may reduce wealth transfer between parties that occurs as a
consequence of a less-anticipatory initial allocation procedure. The
EPA cannot observe in advance the future affected-EGU-level pattern of
emissions.
In this alternative approach, for each state the EPA would multiply
historical steam-generating-unit generation by the steam-generating-
unit source category-specific CO2 emissions performance
rate, and multiply historical NGCC-unit generation by the NGCC-unit
source category-specific CO2 emissions performance rate. The
EPA would do these calculations for each of the compliance periods in
the Interim Period using the glide path interim performance rates, and
for the Final Period using the final performance rates. These
performance rates are shown in Table 6 in section IV.B of this
preamble, above. The EPA established the source category-specific
emissions performance rates in the Clean Power Plan EGs (see section VI
of the final EGs); these rates are not within the scope of this
proposed federal plan rulemaking. Next, for each compliance period the
EPA would split the total number of allowances from the state's mass
goal (minus the set-asides) into affected-EGU source categories in
proportion to the values resulting from the above calculation. The EPA
would then allocate the steam-generating-unit portion of the allowances
to individual SGUs using the same historical-generation-based approach
described above, and would also allocate the NGCC-unit portion of the
allowances to individual NGCC units using the historical-generation-
based approach.
The EPA notes that there are multiple approaches that policymakers
may use to distribute allowances, beyond the proposed or alternative
allocation approaches we included in this proposed rule. Examples of
other allocation approaches include allocating based on historical heat
input (fuel) or historical emissions data, rather than historical
generation data. The choice to use historical data for allocation
(e.g., generation, heat input, or emissions) means that the
distribution of allowance value will be based on past behavior. For
example, allocations based on historical emissions would benefit those
that have historically been the largest emitters, whereas allocations
based on historical heat input or generation (output) would benefit
those that have
[[Page 65018]]
historically used the most fuel or generated the most electricity.\96\
Alternatively, allocations could be distributed based on projected or
observed future activity (e.g., generation, heat input, or emissions).
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\96\ Tools of the Trade, A Guide to Designing and Operating a
Cap and Trade Program for Pollution Control, EPA, 2003.
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The proposed and alternative allocation approaches would determine
most of the allocations before the start of the program. Other
potential allocation approaches would change allocations for future
compliance periods based on future activity--referred to as
``updating'' allocations. This proposed rule includes an updating-
allocation component, as we are proposing to set aside a portion of the
allowances in each state for distribution using an updating output-
based approach as detailed in section V.D.3 of this preamble. The EPA
requests comment on the use of other updating allocation approaches.
Another allowance allocation approach that could minimize the
difference between the initial allowance allocation and the ultimate
distributional pattern of allowance use for compliance is to conduct an
auction, a process whose express intent is to align the allocation of a
scarce good (in this case, the limited authorization to emit
CO2) with the parties most willing to pay for its use. Many
ascribe benefits, in terms of economic efficiency, to the use of
auctioning as a means of allocating allowances. The EPA notes that some
states (e.g., RGGI participating states) have used auctions to
distribute allowances and have used auction revenues for a variety of
purposes, including the implementation of demand-side EE measures
intended to help reduce electricity rate impacts and overall program
costs, as well as targeted investments in low-income communities. The
EPA believes that if it conducted allowance auctions, any revenue from
such auctions received by the agency must be deposited in the U.S.
Treasury under federal law.\97\ As a result, the EPA notes that states
implementing state plans may have greater flexibility than the federal
government would to direct auction funds for particular activities. The
agency requests comment on the idea of auctioning all, or a portion of,
each state's allowances in the proposed federal plan, on how much of
each state's allowances to auction if not the entire amount, on the
frequency (e.g., yearly or every few years), design of auctions (e.g.,
spot or advance; first, second-price or other) and who may participate
in the auction.
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\97\ The EPA believes authority to conduct auctions is located
in CAA section 111 alone, as well as by its reference to CAA section
110(c) FIPs. The statutory definition of a FIP authorizes
``techniques (including economic incentives, such as marketable
permits or auctions of emissions allowances).'' 42 U.S.C. 7602(y).
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The EPA requests comment on an alternative approach, which is
allocating a portion of the allowances to load-serving entities (LSEs)
rather than to affected EGUs. LSEs are the entities responsible for
delivering power to retail consumers.
Allocation to LSEs can help mitigate bill impacts on electricity
consumers when applied in concert with certain additional design
features. In particular, if LSEs commit and/or are required to pass
through to ratepayers the value from their selling of the allocated
allowances, this approach can mitigate the impact of electricity bill
increases on consumers that might otherwise result from application of
the federal plan. As described in the Allowance Allocation TSD, this
type of approach can also help to avoid or mitigate the potential for
windfall profits for affected EGUs. The EPA could apply this approach
by conditioning the receipt of allowances by LSEs on the pass through
to consumers of any allowance value if necessary.
The EPA requests comment on the design and utility of allocating
allowances to LSEs to help mitigate electricity price impacts. In
particular, the EPA requests comment on options to establish conditions
requiring pass through of allowance value and verification of such
pass-through, whether it would be appropriate to identify any
conditions related to equitable distribution of allowance value among
ratepayer categories, as well as the EPA's legal authority to apply any
such conditions.
The EPA requests comment on the additional design aspects of any
potential allocation to LSEs, including but not limited to the
following questions: In particular, what metric should provide the
basis for LSE allocation, e.g., electricity demand served by the LSE,
population served by the LSE, emissions associated with generation
serving the LSE, or some other metric. If emissions are used as the
basis for such allocation, what approach should be taken: On a
historical basis or a continually updated basis, on the basis of
estimated emissions for the relevant region or some other basis, and
using what data to calculate such emissions. Also, the EPA requests
comment on the form by which LSEs may distribute the allowance value to
rate-payers, e.g. as a fixed amount, through reduced rates, etc.
Finally, the EPA requests comment on what share of the total number of
allowances should be distributed to LSEs and what monitoring and
reporting requirements may be necessary to support an effective
program.
The EPA also requests comment on the proposed historical-
generation-based allocation approach, the alternative approach that
divides total allowances from a mass goal into source subcategories
before allocating to individual affected EGUs within each source
category based on historical generation, and on the other alternative
approaches described in this section. The EPA also requests comment on
allocating allowances to all generation in a state (including non-
emitting generation) using a historical-generation-based approach. The
agency also requests comment on the proposed allowance set-asides,
which are detailed below. The agency requests comment on allocation
approaches that may minimize the impact of this proposed rule on small
entities. The EPA also requests comment on any other approaches to
distribute allowances. The agency notes that we propose to provide that
any state may choose to replace the federal plan allocation provisions
with an allocation approach of its choosing as discussed below.
Finally, with regard to alternative allocation methodologies (either
those specifically mentioned in this proposal or other allocation
methodologies), the EPA requests comment on how those alternatives
would satisfy the requirement that in a mass-based program where new
sources are not included as part of the program, the allocation
methodology must address leakage to new fossil fuel-fired sources.
2. Timing of Allowance Recordation
The proposed historical-data-based allocation approach--which the
EPA proposes to use to allocate all of the allowances in each state
except for the set-aside allowances--is a one-time determination that
is not updated. The allocations resulting from this approach would be
determined prior to the start of the program. The EPA proposes to
record the historical-data-based allowances for each compliance period
in source accounts prior to the start of each compliance period, and to
record allowances for one compliance period at a time. Recording
allowances prior to the start of a compliance period provides certainty
to affected EGUs of their allocations in advance of when the allowances
are needed for compliance and can facilitate long-term planning.
[[Page 65019]]
Recording allowances for one compliance period at a time provides
flexibility for a state to replace the federal plan with its own plan
in a timely way. As discussed in section V.F of this preamble, the EPA
proposes to allow a state to replace the federal plan with its own
approved state plan, for a compliance period for which allowances have
not yet been recorded (the proposed schedule for allowance recordation
is detailed below). The EPA also proposes that a state could choose to
replace the federal plan allocations to its affected EGUs (and other
entities) with its own allocations approach, for a compliance period
for which allowances have not yet been recorded as detailed in section
V.E of this preamble.
The agency proposes to record allowances for the mass-based trading
program in accounts of affected EGUs 7 months prior to the start of
each compliance period. For example, if compliance periods are 3 years
long and the first compliance period comprises the years 2022, 2023,
and 2024, the EPA would record allowances for 2022, 2023, and 2024 by
June 1, 2021. The EPA requests comment on the proposed approach of
recording allowances 7 months prior to the start of each compliance
period, and on an alternative of recording allowances 13 months prior
to the start of each compliance period. See section V.D.3 of this
preamble for timing of recordation of allowances from the proposed set-
asides.
3. Allowance Set-Asides To Address Leakage to New Sources
In addition to the general allocation method proposed above, the
EPA is proposing two additional components of allowance allocation
under a mass-based federal plan. These two set-asides are being
proposed to satisfy the requirement in the final guidelines that mass-
based plans demonstrate that they have addressed the risk of leakage to
new unaffected units, as specified below.\98\
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\98\ The EPA is also proposing a third set-aside, for a Clean
Energy Incentive Program, which is detailed in section V.D.4 of this
preamble, below.
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The final EGs specify the concern of leakage, which is defined in
section VII.D of the final EGs preamble as the potential of an
alternative form of implementation of the BSER (e.g., the rate-based
and mass-based state goals) to create a larger incentive for affected
EGUs to shift generation to new fossil fuel-fired EGUs relative to what
would occur when the implementation of the BSER took the form of
standards of performance incorporating the subcategory-specific
emission performance rates representing the BSER. The final EGs
specified that mass-based plan approaches must address leakage, because
the form of the mass goals may ultimately impact the relative
incentives to generate and emit at affected EGUs as opposed to shifting
generation to new sources, with potential implications for whether the
mass goal implements or is consistent with the BSER and overall
emissions from the sector. These circumstances are much less likely to
be present under a rate-based plan approach, where the form of the goal
ensures sufficient incentive to affected existing EGUs to generate and
thus avoid leakage, similar to the CO2 emission performance
rates. By requiring mass-based plan components that address leakage,
the final EGs ensure that mass goals are equivalent to the
CO2 emission performance rates and are thus an equivalent
expression of the BSER. Section VII.D of the final EGs details the
requirement for addressing leakage and why it is needed, and section
VIII.J of the final EGs specifies options for mass-based state plan
components that address leakage. We are proposing, as part of the mass-
based approach under the federal plan and model rule, to implement
allowance allocation approaches to address leakage, specifically
through establishing an output-based allocation set-aside and a set-
aside that encourages the installation of RE.
As noted in the EGs, if a state were to adopt allowance set-aside
provisions exactly as they are outlined in this model rule once it is
finalized, the requirement for that state plan to address leakage would
be considered presumptively approvable.
Section VIII.J of the final EGs provides a discussion of how set-
asides can effectively address leakage in a mass-based plan approach.
That section of the final EGs also describes why the allowance
allocation alternative for addressing leakage must be chosen for the
federal plan instead of the option to regulate new non-affected fossil
fuel-fired EGUs. This is because the EPA does not have authority to
extend regulation of and federal enforceability to new fossil fuel-
fired sources under CAA section 111(d), and therefore we cannot include
new sources under a federal mass-based plan approach.
The set-asides we are proposing--described in detail below--would
establish a pool of allowances that would be allocated to affected EGUS
or other entities based upon criteria designed to address leakage.
These set-asides are essentially a type of ``economic incentive''
authorized by the CAA as a means of pollution prevention and control,
and the expected benefits of this particular type of economic incentive
to address leakage make it appropriate here.\99\ The EPA believes these
set-aside programs are both authorized and consistent with the purpose
of the Clean Power Plan under CAA section 111(d) and the specific
requirements specified in the final guidelines. They do not have the
effect of increasing the stringency of the federal plan because the
overall budget of allowances (representing allowable emissions) remains
the same.
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\99\ In designing a federal plan under CAA section 111(d), the
EPA recognizes its authority as being, in some sense, the same as
that available under CAA section 110(c), where the use of economic
incentives is authorized. See CAA section 302(y), 42 U.S.C. 7602(y)
(authorizing use of ``economic incentives'' in FIPs).
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The EPA is aware of the successful use of set-asides and similar
programs in other emissions trading programs. The following are
examples of set-asides and similar programs used in other federal air
quality rules.
The EPA has previously established set-asides of emissions
allowances in FIPs under CAA section 110. For example, in the CSAPR,
the EPA used a 5 percent set-aside for new units, because we believed
it was ``important to have a small new unit set-aside in each state to
cover new units within the budget that was set aside in order to
address the state's significant contribution and interference with
maintenance.'' (75 FR 45310; August 2, 2010). This was important, in
the EPA's view, because it allowed for growth in the electric utility
sector consistent with the EPA's modeling, where new units showed up in
the modeling output as surrogate facilities representing potential new
EGUs that come online in future years in response to demand increases
or other market drivers.\100\ As between a choice of requiring these
new units to purchase their allowance on the open market, versus being
treated in the same manner as existing--and generally understood to be
less efficient and more polluting--units, i.e., by being eligible to
receive an initial allowance allocation out of the new unit set-aside,
the EPA chose the latter.
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\100\ See also EPA, Allowance Allocation Final Rule TSD, EPA-HQ-
OAR-2009-0491, at 3-4 (June 2011).
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As part of the ARP under Title IV of the 1990 CAA Amendments,
Congress established a ``conservation and renewable energy reserve''
account. See CAA section 404(f), 42 U.S.C. 7651c(f). This is in essence
a set-aside account of
[[Page 65020]]
SO2 allowances which the regulated utilities could earn by
undertaking ``qualified energy conservation measures'' and ``qualified
renewable energy'' projects. The size of the reserve was set at 300,000
allowances, and utilities could earn one SO2 allowance for
every 500 MWh of energy saved through demand-side EE savings or RE
generation. In the first years of the program, utilities received bonus
allowances equivalent to close to 3,000 tons of avoided SO2
emissions, while achieving co-benefits from reductions in other
pollutants, and, in the words of one industry representative,
``creating a culture change where utilities are looking for
opportunities everywhere.'' \101\ The reserve program was nonetheless
undersubscribed, and the EPA and other parties have learned from this
case and made adjustments to similar programs to promote participation.
This proposal seeks to minimize the administrative burden associated
with participation in this rule's proposed set-asides.
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\101\ U.S. EPA, Acid Rain Program, Conservation and Renewable
Energy Reserve, EPA 430-R-94-010 (November 1994).
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In the NOX SIP Call, the EPA encouraged states to
consider including energy efficiency and renewables as a strategy in
meeting their emission budgets through the use of set-asides. See 63 FR
57356, 57438 (October 27, 1998). A number of states created RE and
demand-side EE set-asides in their SIPs in response, and later, for the
implementation of CAIR. A ``roundtable'' meeting with 25 states in 2006
indicated that states that had established these programs were
generally having success with them, and provided a forum for exchanges
of ideas on how to handle a variety of implementation issues, such as
over- and under-subscription, application issues, compliance and
verification, the appropriate size of a set-aside account, how to
garner public input on which projects are selected, and other
issues.\102\ In general, the EPA believes its experience and those of
the states with these set-aside programs support the view that they are
an effective means to spur clean energy projects, which in turn we
believe can help to reduce the risk of leakage in this instance.\103\
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\102\ U.S. EPA, State Clean Energy-Environment Technical Forum
Roundtable on State NOXAllowance EE/RE Set Aside
Programs, Call Summary (June 6, 2006), available at http://www.epa.gov/statelocalclimate/documents/pdf/summary_paper_nox_allowance_6-6-2006.pdf.
\103\ The agency has extensive experience in the design and
establishment of set-aside programs. See, e.g., Guidance on
Establishing an Energy Efficiency and Renewable Energy (EE/RE) Set-
Aside in the NOX Budget Trading Program (March 1999),
available at http://www.epa.gov/statelocalclimate/documents/pdf/ee-re_set-asides_vol1.pdf; Creating an EE and RE Set-aside in the
NOX Budget Trading Program: Designing the Administrative
and Quantitative Elements (April 2000), available at http://www.epa.gov/statelocalclimate/documents/pdf/ee-re_set-asides_vol2.pdf; Creating an EE and RE Set-aside in the
NOX Budget Trading Program: Evaluation, Measurement, and
Verification of Electricity Savings for Determining Emission
Reductions from Energy Efficiency and Renewable Energy Actions (July
2007), available at http://www.epa.gov/statelocalclimate/documents/pdf/ee-re_set-asides_vol3.pdf.
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Below, the EPA describes two potential allowance set-asides. First,
the EPA proposes a set-aside for allowances distributed to existing
NGCC units based on output (i.e., output-based allocation) to mitigate
emission leakage to new sources. Second, the EPA proposes a set-aside
for electricity generation from qualifying renewables. This set-aside
also addresses the potential for leakage to new sources, as increased
RE capacity can serve electricity demand in place of new sources. The
EPA also solicits comment on other set-aside options that could address
leakage, including a set-aside that provides an incentive for demand-
side EE. The EPA seeks comment on all aspects of the set-aside options
specified in this section. This includes the inclusion of a set-aside,
the method for allocation of allowances to set-asides, the size of the
set-asides, the requirements for the process of distribution,
eligibility requirements for receiving set-aside allowances, the
proposed process for redistribution of undistributed allowances from
each set-aside, and any other appropriate set-asides.
a. Set-Asides for Output-Based Allocation
The EPA is proposing a set-aside approach referred to as output-
based allocation, which provides targeted allocations of a limited
portion of allowances to existing NGCC units as a means of mitigating
leakage. The EPA believes that this proposed set-aside would reduce
incentives for generation to shift away from EGUs covered under mass-
based plans to new unaffected EGUs. We seek comment on all aspects of
this proposal and its underlying rationale.
Under the output-based allocation approach we are proposing,
beginning with the second compliance period, a portion of the total
allowances within each mass-based federal plan state would be allocated
to existing NGCC units based, in part, on their level of electricity
generation in the previous compliance period. Each eligible EGU would
get a larger allowance allocation from this set-aside if it generates
more, such that owner/operators of eligible EGUs will have an incentive
to generate more in order to receive more allowances. Because the total
number of allowances is limited, this allocation approach will not
exceed the overall emission goal. Instead, it merely modifies the
distribution of allowances in a manner designed to align the generation
incentives for eligible EGUs in mass-based states with new emitting
EGUs that are not subject to a mass-based limit, mitigating emissions
leakage.
The EPA is inviting comment on key parameters for the appropriate
design of the output-based allocation approach used for this proposed
set-aside. Key parameters to be identified under the output-based
allocation approach include which affected EGUs receive the allocation,
the timing of the set-aside's allocation procedure, the allocation
rate(s), and the size of the set-aside. The EPA also invites comment on
what other parameters may be relevant for design of an appropriate
output-based set-aside.
The EPA first solicits comment on which EGUs should be eligible to
receive output-based allocation from the set-aside. The EPA proposes
that only NGCC units subject to the final EGs receive output-based
allocation from the set-aside. The EPA recognizes that performance of
output-based allocation may be improved by targeting which units
receive this additional incentive. In particular, this approach can
most effectively address emission leakage if targeted to those affected
EGUs subject to a mass goal that face the greatest difference in their
incentive to generate relative to otherwise similar EGUs that are not
subject to a mass goal. As noted in the discussion of the allocation
rate below, new combustion turbines (i.e., NGCC units and simple cycle
combustion turbines) would be expected to generate more absent this
set-aside. Therefore, the difference in generation incentives between
affected stationary combustion turbines subject to a mass goal and
otherwise similar new stationary combustion turbines that are not
subject to a mass goal is likely one of the most salient deviations in
production incentives to address.
The EPA also requests comment on extending output-based allocation
from this set-aside to affected SGUs. Output-based allocation for SGUs
may increase generation subject to the mass limit, leading to reduced
generation and emissions from new emitting sources. However, the EPA
does not propose this approach because it is not as effective as
output-based allocation to NGCC units.
[[Page 65021]]
This is because output-based allocation to SGUs would incentivize
generation from relatively high-emitting EGUs, which would likely
increase allowance prices as other emission reductions are made to
respect the overarching mass limit. This approach would thus strongly
counteract the intended effect of lowering the production cost from
sources subject to the proposed mass-based federal plan (compared to
emitting sources not subject to the plan). The EPA also requests
comment on extending output-based allocation from this set-aside to
zero-emitting generators (including both renewable and nuclear
generation), and how the design of the OBA set-aside for such
generators would differ relative to the NGCC approach (e.g., the amount
of allowances earned per MWh, the capacity-factor threshold, the size
of the total set-aside).
The EPA also proposes that this approach be targeted towards
marginal generation that may not have otherwise occurred absent this
set-aside, by providing allocations under this set-aside only to
eligible EGUs that exceed a 50 percent capacity factor on a net basis
over the compliance period, and only for the portion of their
generation that exceeds that capacity factor.\104\
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\104\ Effectively, the allocation rate (defined below) of
output-based allocation is zero up until this average capacity
factor.
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The EPA also solicits comment on the timing of the output-based
allocation set-aside's allocation procedure, which involves the
relationship between the time at which eligible generation occurs and
the vintage year(s) of the allowances allocated from this set-aside to
recognize that generation. The EPA is proposing a lagged accounting
procedure for this set-aside, where eligible generation that occurs
during a given compliance period would receive allowances through this
set-aside taken from vintage years in the subsequent compliance period.
In keeping with this lagged accounting procedure, the EPA is proposing
not to reserve any allowances of vintage years during the first
compliance period (2022-2024) for allocation through this set-aside;
eligible generation that occurs during the first compliance period
would be recognized through this set-aside with allowances of vintage
years from the second compliance period (2025-2027).
The EPA is proposing this lagged accounting procedure because the
amount and location of eligible generation in any given compliance
period remains uncertain until the compliance period has ended and the
relevant data has been reported and verified. Without this lagged
accounting procedure, the EPA would have to withhold an amount of
allowances for this set-aside from certain vintage years even as the
corresponding compliance period was already underway. Given the size of
this proposed output-based allocation set-aside in certain states, the
EPA believes it would be more advantageous for affected EGUs to know in
advance how many allowances they will be allocated in a given period,
inclusive of allowances allocated through this output-based allocation
set-aside.\105\
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\105\ The EPA recognizes that under this lagged accounting
procedure, if the federal plan is replaced by a state plan in a
future compliance period, the incentive to create eligible
generation in the last compliance period subject to the federal plan
is potentially diminished.
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The EPA requests comment on options for the allocation rate under
this approach. The allocation rate is the number of allowances, in an
amount equal to a specific amount of emissions, that the affected EGU
receives per one net MWh of generation eligible for the set-aside. The
EPA proposes to set the allocation rate equal to the rate-based
emission standard (on a net basis) for new NGCC units under 111(b), in
order to align the generation incentives across EGUs eligible for the
set-aside and the type of new emitting source that would generate more
absent this set-aside. Specifically, an additional MWh of eligible
generation would earn the affected EGU allowances equal to the level of
emissions permitted per MWh of net generation under the 111(b) new
source standard, which is 1,030 lbs/MWh-net (Carbon Pollution Standards
for new, modified, and reconstructed EGUs). The EPA requests comments
on other values for the allocation rate. For example the allocation
rate may be the expected net emissions rate of newly constructed NGCC
units, the historical average emissions rate from NGCC units, or the
NGCC or fossil steam source category-specific emissions performance
rates promulgated in the Clean Power Plan EGs (see section VI of the
final EGs).
The EPA proposes to calculate an NGCC unit's capacity factor based
on the previous compliance period's net generation and the net summer
capacity of the unit. The EPA is proposing to require affected EGUs to
report net generation to the agency.\106\ The EPA proposes to use net
summer capacity as reported to EIA. In the alternative, the EPA
proposes to require that NGCC units report net summer capacity directly
to the EPA by adding it as a required data field in the certificate of
representation that a unit's owner or operator would submit to the
agency (see section V.G of this preamble). The EPA notes that the EIA
net summer capacity data is reported at the generator level; if we add
this data point to the certificate of representation it would be
reported at the affected-EGU level, which would facilitate calculation
of capacity factors. The EPA also requests comment on whether the
``maximum load value,'' which is a parameter that EGUs report to the
EPA in their monitoring plans, is a reasonable proxy for EGU-level net
summer capacity for these calculations. The EPA also requests comment
on an alternative approach of basing the capacity-factor calculation on
nameplate capacity instead of net summer capacity, or other approaches
to the calculation.
---------------------------------------------------------------------------
\106\ See section V.H of this preamble for proposed monitoring
and reporting requirements. The EPA proposes to make the reported
generation data available to the public on the agency's Web site.
---------------------------------------------------------------------------
The EPA proposes to determine the size of the output-based set-
aside once, before the start of the program, and not to change the size
thereafter. The EPA proposes to determine the size of the set-aside
assuming that it would incentivize existing NGCC to increase
utilization to a 60 percent capacity factor. The assumed 60 percent
capacity factor offers a way to limit the size of this set-aside, which
allows the remainder of the allowances in a given compliance period to
be allocated through the historical-generation approach (as detailed
above) and the other proposed set-asides (as detailed below).
Furthermore, limiting the size of the set-aside avoids the risk of
incentivizing too much generation from eligible sources, as discussed
further in the Allowance Allocation Proposed Rule TSD.
The EPA proposes to determine the size of the output-based set-
aside using 2012 baseline data from the Clean Power Plan EGs.\107\ The
EPA would calculate the size of the set-aside as 10 percent of the NGCC
capacity in the state \108\ multiplied by the hours in a year
multiplied by the allocation rate for the set-aside. The EPA requests
comment on the proposed capacity data used as the basis for determining
the size of the output-based set-aside, and alternative sources of
capacity data that may be used for determining its size.
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\107\ CO2 Emission Performance Rate and Goal
Computation TSD for the Clean Power Plan Final Rule.
\108\ The sum of net summer capacity for affected NGCC units in
the 2012 baseline for the Clean Power Plan EGs (CO2
Emission Performance Rate and Goal Computation TSD for the Clean
Power Plan Final Rule).
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[[Page 65022]]
The set-asides resulting from this proposed approach are shown in
Table 9 of this preamble. The set-asides in the table would apply to
every compliance period except for the first compliance period for
which there would be no output-based set-aside. Although the size of
the set-aside would remain the same for each compliance period, as the
mass goals decrease with each step in the Interim Period and to the
Final Period, the set-asides would constitute an increasing share of a
state's mass goal. The Allowance Allocation Proposed Rule TSD further
details the proposed approach to determine the size of the set-aside.
The EPA requests comment on a potential limit for the size of the set-
aside in a compliance period based on a percentage of the state's total
allowances for the compliance period.
Table 9--Proposed Size of Output-Based Set-Aside for the Second
Compliance Period and Later
[Short tons]
------------------------------------------------------------------------
Allowances in
State output-based
set-aside
------------------------------------------------------------------------
Alabama................................................. 4,185,496
Arizona................................................. 4,197,813
Arkansas................................................ 2,102,538
California.............................................. 8,458,604
Colorado................................................ 1,348,187
Connecticut............................................. 1,090,811
Delaware................................................ 649,190
Florida................................................. 12,102,688
Georgia................................................. 3,563,104
Idaho................................................... 246,638
Illinois................................................ 1,598,615
Indiana................................................. 1,106,150
Iowa.................................................... 492,510
Kansas.................................................. 62,257
Kentucky................................................ 288,730
Lands of the Fort Mojave Tribe.......................... 248,127
Lands of the Navajo Nation.............................. 0
Lands of the Uintah and Ouray Reservation............... 0
Louisiana............................................... 2,207,879
Maine................................................... 563,925
Maryland................................................ 103,762
Massachusetts........................................... 2,439,991
Michigan................................................ 2,105,786
Minnesota............................................... 909,724
Mississippi............................................. 3,132,671
Missouri................................................ 815,210
Montana................................................. 0
Nebraska................................................ 144,635
Nevada.................................................. 2,326,529
New Hampshire........................................... 542,721
New Jersey.............................................. 3,413,100
New Mexico.............................................. 627,085
New York................................................ 3,815,381
North Carolina.......................................... 2,120,178
North Dakota............................................ 0
Ohio.................................................... 1,757,326
Oklahoma................................................ 3,121,167
Oregon.................................................. 1,291,027
Pennsylvania............................................ 4,392,931
Rhode Island............................................ 778,307
South Carolina.......................................... 1,029,366
South Dakota............................................ 130,831
Tennessee............................................... 632,949
Texas................................................... 15,990,657
Utah.................................................... 825,586
Virginia................................................ 3,011,811
Washington.............................................. 1,383,060
West Virginia........................................... 0
Wisconsin............................................... 1,181,175
Wyoming................................................. 45,114
------------------------------------------------------------------------
Given the proposed limit on the total size of the set-aside, and
the amount of potential generation eligible for the set-aside, there
may be fewer allowances available in the set-aside than can be earned
at the allocation rate. The EPA proposes that, if the amount of total
generation eligible for the set-aside multiplied by the allocation rate
exceeds the size of this set-aside, then the allowances in this set-
aside would be allocated to eligible generation on a pro-rata basis.
The EPA proposes that if the number of allowances allocated from
the set-aside is less than the size of this set-aside, then the
remaining allowances would be distributed to all affected EGUs using
the historical-generation-based approach described above.
The EPA proposes to provide notice of the capacity and generation
data used to calculate allocations from the set-aside, and the
resulting allocations, by August 1 of the first year in each compliance
period, e.g., by August 1, 2025 for the compliance period that
commences in 2025 (and based on the data from the prior compliance
period). The agency proposes to provide 30 days for comment on the data
and allocations, until August 31, and to provide notice of the final
set-aside allocations by November 1 of the same year and record the
allocations in the source accounts at that time. The EPA requests
comment on other approaches to providing notice of the data and
allocations.
The EPA requests comment on all aspects of the proposed approach to
calculate output-based set-aside allocations. Further details are in
the Allowance Allocation Proposed Rule TSD in the docket.
b. Set-Asides for Renewable Energy Projects
The EPA proposes to provide a set-aside of allowances for
distribution to RE projects in each state covered by the proposed mass-
based federal plan, and is also proposing this for the mass-based model
rule. The agency also requests comment on whether distribution should
extend to DS-EE, CHP, and other types of projects. Under this program,
the EPA would reserve a percentage of each state's allowances in a set-
aside account for each state. Developers of RE projects could apply to
receive set-aside allowances based on the projected generation from
eligible RE capacity.
This set-aside is expected to address concerns regarding leakage by
lowering the marginal cost of production of the incented clean energy
technologies within the state. This will make RE more competitive
against new sources, reducing the potential for leakage to new sources.
While the proposed set-asides would provide additional incentive for
the creation of additional RE capacity, it should also be noted that
the proposed mass-based trading program itself would provide incentive
for new and existing low and zero-emitting generation.
In the context of the proposed federal plan, the EPA is proposing
that it would create a unique set-aside for each state covered by a
mass-based federal plan. Under a model rule, the state would create
this set-aside. The allowances in each set-aside would be reserved from
each vintage of the assigned mass goal to that state prior to
allocation of allowances to sources. The EPA is proposing that 5
percent of allowances will be reserved from the allocation for each
state for the purpose of the set-aside. We are also requesting comment
on options for a percentage of allowances to be reserved ranging from 1
to 10 percent of total allowances in each state. The proposed
percentage has been determined to provide a meaningful additional
incentive for RE activities in each state, while ensuring that the vast
majority of allowances are freely allocated to affected EGUs. The EPA
made this conclusion based upon determining an appropriate volume of
set-aside resources that, at a range of possible allowance prices, are
projected to incent the development of additional RE projects. The
analysis is provided in the docket as part of the Renewable Energy Set-
aside TSD. We note that, under the proposed framework, these allowances
would be available to affected EGUs either in the marketplace or
through subsequent distribution of unclaimed set-aside allowances, and
[[Page 65023]]
thus the provision of these set-asides does not affect the overall
stringency of the program.
In section V.D.5 of this preamble, below, the EPA is proposing that
the size of the RE set-asides may grow over time as certain units shift
out of the program.
We are proposing, as part of the mass-based federal plan and model
rule, that a project is eligible to receive set-aside allowances if it
is RE that meets the eligibility requirements for rate-based ERC
issuance as specified in section IV.C of this preamble and section
VIII.K of the final EGs. This includes, for example, the requirement
that only capacity incremental to 2012 is eligible for the set-aside.
The agency requests comment on an additional potential condition that
would limit eligibility to project providers that are also the owners
or operators of affected EGUs. This approach has precedent in the
eligibility requirements for the ARP set-aside, and would limit the
entities eligible to receive set-aside allowances to those that are
subject to the federal plan.
The EPA is proposing that eligible RE capacity must meet the
following conditions regarding geographic eligibility for both the
federal plan and model rule. Eligible RE projects must be located in
the mass-based state for which the set-aside has been designated. The
agency invites comment on whether capacity outside the state should be
recognized, and how that could be implemented. The EPA also proposes
that the generation for which an entity receives allowances from the
set-aside would not be eligible for ERC issuance in rate-based states.
As specified in section IV.C of this preamble, the EPA is proposing
that the same RE measures are eligible to receive set-aside allowances
under a mass-based federal plan as would be eligible for ERC issuance
under a rate-based federal plan and the model rule. Specifically, the
following RE measures are eligible: On-shore wind, solar, geothermal
power, and hydropower. The RE measure must also have the capacity to
provide data quantified by a revenue-quality meter, a requirement that
is further discussed in section IV.D.8 of this preamble. New nuclear
units and capacity uprates at existing nuclear units are not proposed
to be eligible to receive set-aside allowances. We do not think a set-
aside used as an incentive for incremental nuclear capacity is a useful
way to address leakage to new sources during the performance period,
due to unique costs and development timelines for incremental nuclear
power. All other proposed aspects of the RE eligible measure types
described in section IV.C of this preamble and the requests for comment
included within that section also apply in the mass-based set-aside
context for both the proposed mass-based federal plan and the proposed
mass-based model rule. For example, we are requesting comment on the
inclusion of other RE measures, incremental nuclear, demand-side EE
measures, CHP and any other emission reduction measures beyond those
mentioned here, as long as they meet the eligibility requirements
outlined in the final EGs for rate-based crediting, as eligible
measures to receive set-aside allowances. We particularly request
comment on how a set-aside to provide an incentive from these
particular measures will serve to address leakage to new sources. We
also request comment on the implications of the inclusion of such
technologies for the streamlined implementation of projection-based
EM&V requirements of the set-aside specified below in a federal plan
context across the applicable jurisdictions, while still maintaining
necessary rigor. We request comment on the appropriateness of the
biomass treatment requirements offered for comment in section IV.C.3 of
this preamble in the context of a mass-based set-aside. We request
comment on requirements for the treatment of CHP and WHP, in the
context of the mass-based set-aside. We also request comment on
appropriate processes through which, after the federal plan is
finalized, the EPA and/or stakeholders could make a demonstration of
the appropriateness of new measure types and the EPA could evaluate and
approve the demonstration so that a new measure type can be considered
eligible for the set-aside.
To demonstrate that an RE project meets the requirements proposed
above, in the context of a mass-based federal plan, it is proposed that
the project proponent must provide the following: Documentation of the
nature of the project and that it meets eligibility requirements,
documentation that it will be located within the state in question, and
a projection of expected annual MWh generation for an RE project. The
EPA must approve the documentation of eligibility and the projection of
MWh before the project becomes eligible for a distribution of the set-
aside allowances. In addition, the proponent must register for a
general account in the EPA tracking system where the allowances would
be recorded. See 40 CFR 62.16320 for the requirements to establish a
general account. While the EPA is proposing to allow eligible resources
to use a general account to receive any allowances allocated under this
section, the EPA requests comment on extending the designated
representative provisions in 40 CFR 62.16290 to eligible resources
instead of the general account provisions. Requiring eligible resources
to submit information similar to that collected in the certificate of
representation in 40 CFR 62.16305 and to appoint a designated
representative to act on behalf of all owners/operators for all
projects requesting allowances may improve the EM&V process by making
the eligible resources more accountable. The EPA requests comment on
what documentation would be required if other measure types were
considered eligible to receive set-aside allowances. We propose that
the same process for approval of projects be applied in a model rule,
with the state taking the approving role instead of EPA.
The EM&V requirements for the mass-based set-aside differ from
those for rate-based ERC issuance, particularly because it is based
upon projections provided prior to generation rather than metered data
provided after the generation occurs (though we are proposing that the
projections will be checked against ex-post metered data). The
projection method enables the distribution of set-aside allowances
prior to the year during which the generation occurs. The EPA feels
this still provides sufficient rigor because the set-aside does not
directly affect program stringency. The reason that stringency is not
affected is because of key differences between issuance of credits and
distribution of set-aside allowances. Under rate-based implementation,
each decision to issue an ERC based on a quantification of RE
generation affects the ultimate amount of allowable CO2
emissions, because the number of ERCs is determined by the amount of
MWhs approved as eligible for ERC issuance and the ERC does not exist
until the issuance decision is made. Thus the amount of ERCs that are
issued can affect the stringency of the rule. As a result, the EPA has
laid out specific requirements (including EM&V procedures) in the final
Clean Power Plan, and in this proposed federal plan and model rule, to
assure the environmental reliability of measures qualifying for ERC
recognition under rate-based implementation. In contrast, any decision
to recognize RE with set-aside allowance allocations under a mass-based
approach does not affect the validity of the allowance itself and does
not affect the CO2 emissions outcome because the ultimate
amount of
[[Page 65024]]
allowable CO2 emissions is determined by the total number of
allowances initially created (regardless of how they are distributed).
As a result, while the EPA believes it is reasonable to consider a
minimum set of qualifications for recognizing RE through these
allowance set-asides to assure that the RE generation that is incented
is actually produced, the EPA does not believe the overall integrity of
mass-based implementation is significantly affected by the robustness
of whatever eligibility requirements the EPA ultimately sets for RE
recognition through allocation from these set-asides. This being said,
the agency is proposing to require robust demonstrations of the
eligibility and EM&V projections for RE generation submitted for the
set-aside, demonstrations that are based on the best practices of
existing programs. This is necessary to assure the delivery of RE as a
result of the set-aside.
The EPA proposes that the projections of MWh provided will be the
basis of the distribution of set-aside allowances. A satisfactory
demonstration of the future RE generation from an eligible project must
use technically sound quantification methods that are reliable,
replicable, and accompanied by underlying analytical assumptions and
verifiable data sources used to demonstrate future performance. These
methods, assumptions and data sources must be specified in
documentation accompanying the projections. These projections and
supporting documentation should all be provided in the set-aside
project application, and that application must be approved by a third-
party verifier. The EPA invites comment on these proposed requirements
for projections. We also request comment on whether set-asides should
be distributed proportional to actual MWh provided by the installation
in a prior year or compliance period, or another form of historical
generation data. This type of allocation method could also be similar
to the structure proposed for the output-based allocation set-aside. We
propose that the same projection-based distribution basis be applied in
a model rule, with the state taking the approving role instead of EPA.
The EPA is proposing the following process for distribution of RE
set-aside allowances. Starting prior to the compliance period, and
going forward through the compliance period, RE providers in each state
will have an opportunity to apply to the EPA or a designated agent to
be approved as eligible to receive set-aside allowances in their state.
This application must include all the requirements outlined above,
including projections of expected MWh of generation. The EPA is
proposing to accept RE set-aside project applications up to a deadline
of June 1 in the year prior to the year during which the RE generation
occurs (the ``generation year''). The EPA or its agent will review and
approve the project as eligible and it will be entered into the pool of
projects that will receive set-asides in any compliance period. If
approved, the number of projected MWh in each generation year will be
the basis of the number of allowances the provider will receive, as an
input to the methodology specified below. The providers will have an
opportunity to update projections for future generation years, these
projections must be received by June 1 of the year prior to the
generation year in question.
On December 1 of the year prior to each year of the compliance
period in question, the EPA is proposing to distribute allowances from
the set-aside to approved providers. The agency is proposing to
distribute set-aside allowances to approved RE providers pro-rata, with
the number of allowances distributed to each provider according to the
percentage of total approved RE MWh for that state that the approved
MWhs from their project represent. This method is proposed because it
treats all eligible RE projects equally in the distribution of set-
aside allowance. It also inherently provides a more significant
incentive in states with less eligible RE generation, but will become
less significant as RE generation increases. We also request comment on
whether to restrict projects to a maximum number of allowances they can
receive per MWh of generation, such as 1 allowance per MWh.
After each generation year, RE providers receiving allowances will
have to provide an M&V report with the MWhs of RE generation actually
produced, to assure that they have met the projected level of
generation. These M&V reports need to document that the generation was
by an approved project, and the report should be approved by a third
party verifier. As discussed in section IV.D.8 of this preamble (EM&V
section for the rate-based approach), these data should be readily
available from existing metering. The EPA requests comment on the
process for submitting M&V reports with actual generation.
If the project or program does not reach the MWhs projected in a
particular generation year, the unfulfilled MWhs will be subtracted
from that RE provider's MWhs eligible for the set-aside in the next
generation year, or multiple years if the deficit exceeds the MWhs
projected for the upcoming year. If this deficit is greater than 10
percent in a particular year, the provider will need to provide an
explanation of the deficit and will be required to reevaluate their
projections for future years. If such deficits continue through all
years of the relevant compliance period, the provider will be
disqualified from receiving future set-asides for the following
compliance period. We also request comment on whether a provider with
continuing deficits should also be disqualified from receiving ERCs for
the generation in question from states with rate-based plans. The
agency requests comment on all of the specified aspects of this
distribution process.
The EPA is proposing that once allowances have been distributed to
all approved providers, any remaining allowances in the set-aside, such
as set-aside allowances designated for projects that no longer exist,
will be redistributed to affected EGUs in the state in a pro rata
fashion on the same distribution basis as their initial allocations
were made. It is proposed that this will occur immediately after the
distribution of set-aside allowances to eligible RE providers on
December 1 of the year prior to the generation year in question. The
EPA requests comment on this approach.
We propose that the same distribution process as outlined above be
applied in a model rule, with the state taking the approving role
instead of the EPA.
The EPA is also seeking comment, in the context of the proposed
rate-based federal plan and model rule, on whether a portion of this
set-aside should be targeted to RE projects that benefit low-income
communities. This benefit could be in the form of MWh provided to the
low-income community, financial proceeds from the project primarily
benefiting the low-income community, or the project lowering utility
costs of low-income rate-payers. The EPA seeks comment on how a low-
income community should be defined as eligible under this set-aside. We
seek comment on how much of the set-aside should be designated as
targeted at low-income communities. We also request comment on whether
the methods of approval and distribution of allowances to projects that
benefit low-income communities should differ from the methods that are
proposed to apply to other RE projects.
The EPA seeks comment, in the context of the proposed rate-based
federal plan and model rule, on all aspects of this proposed RE
allowance set-aside program, including whether it should be included as
part of a mass-
[[Page 65025]]
based federal plan, the structure of the set-aside reserve, eligibility
requirements for receiving set-aside allowances, demonstration of
eligibility, and the process for distribution of allowances.
4. Provisions To Encourage Early Action
For purposes of the proposed mass-based federal plan, the EPA
proposes to implement the Clean Energy Incentive Program (CEIP) on
behalf of a state by issuing early action allowances for eligible
actions located in or benefitting the state. Eligible projects must
commence construction in the case of RE or commence operations in the
case of low-income EE after September 6, 2018, and will receive
incentives based on the zero-emitting MWh they generate, or the energy
savings they achieve, during 2020 and/or 2021.\109\ These early action
allowances would be drawn from a third set-aside of allowances from the
general distribution methodology. The EPA believes it is reasonable to
establish the total amount of the early action set-aside in an amount
equal to the pool of matching allowances. Thus, the EPA proposes that
the total early action set-aside would be of an amount equal to the
pool of matching allowances: No more than 300 million CO2
allowances, depending on how many states are subject to a federal plan.
---------------------------------------------------------------------------
\109\ As discussed in section VIII.B.2 of the final emission
guidelines, in the case of a state that submits a final state plan
including requirements for the state's participation in the CEIP,
eligible RE projects may commence construction, and eligible EE
projects may commence implementation, following the date of
submission of a final state plan to the EPA. These projects must be
implemented in or benefit the state that submitted the final state
plan to the EPA, and may receive awards for the zero-emitting MWh
they generate or the end-use energy savings they achieve during 2020
and/or 2021.
---------------------------------------------------------------------------
The EPA proposes to distribute the 300 million early action set-
aside allowances among the states based upon the amount of the
reductions from 2012 levels each state must achieve relative to that of
the other participating states. The EPA proposes to calculate these
values as each state's proportional share of the total difference
between the 2012 baseline and the 2030 mass goals.\110\ See Table 10 of
this preamble for the proposed set-asides for each state under the
mass-based federal plan. The agency proposes to set aside 100 million
early action allowances from each of the 3 years in the first
compliance period (2022, 2023, and 2024) for a total of 300 million
allowances to be set aside. While the table shows set-asides for every
state, the EPA proposes to implement this set-aside, according to the
amounts listed in Table 10, only for those states for whom the EPA is
implementing the mass-based federal plan. The EPA also requests comment
on other approaches for determining the size of this set-aside in the
mass-based federal plan.
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\110\ The 2012 baseline is from the CO2 Emission
Performance Rate and Goal Computation TSD for the Clean Power Plan
Final Rule. Where a state's relative share of the reductions from
2012 levels would yield a set-aside of less than zero, the EPA
proposes to assign such a state a set-aside equal to one percent of
the state's 2030 mass goal and adjust the remaining state set-asides
accordingly.
---------------------------------------------------------------------------
For the purposes of the mass-based federal plan, the EPA is
proposing to award early action allowances to two types of eligible
projects that are located in or benefit the state for which the EPA is
implementing a federal plan:
RE investments that generate metered MWh from any type of
wind or solar resources; and
Demand-side EE programs and measures implemented in low-
income communities that result in quantified and verified electricity
savings (MWh).
Eligible RE projects must commence construction, and eligible EE
projects must commence implementation, after September 6, 2018 for
those states on whose behalf the EPA is implementing the federal plan.
These projects will receive incentives for the MWh they generate or the
end-use energy demand reductions they achieve during 2020 and/or 2021.
The EPA proposes the following framework to implement the CEIP in
the mass-based federal plan. First, the EPA proposes to create a set-
aside of early action allowances for all federal plan states, as
described above. Second, the agency proposes to create an account of
``matching'' allowances for each state participating in the CEIP--
regardless of whether a state is implementing a state plan or the
agency is implementing a federal plan on its behalf. This distribution
would reflect each state's pro rata share of a federal pool of
additional allowances--based on the amount of the reductions from 2012
levels the affected EGUs in the state are required to achieve relative
to those in the other participating states \111\--which would be
limited to the equivalent of 300 million short tons of CO2
emissions. Thus, states whose EGUs have greater reduction obligations
will be eligible to secure a larger proportion of the federal
allocation upon demonstration of quantified and verified MWh of RE
generation or demand side-EE savings from eligible projects realized in
2020 and/or 2021. The EPA intends that a portion of these matching
allowances would be reserved for eligible wind and solar projects, and
a portion would be reserved for eligible EE projects implemented in
low-income communities. The agency recognizes that there have been
historical economic, logistical and information barriers to
implementing EE programs in these communities, and therefore believes
it is appropriate to reserve a portion of the federal pool to
incentivize investment in these programs. The EPA requests comment on
the size of reserve of matching allowances for eligible low-income EE
programs as well as for eligible wind and solar projects. The EPA is
proposing that unused allowances in either reserve would be
redistributed among participating states. This redistribution could be
executed according to the pro-rata method discussed above.
Alternatively, unused matching EE or RE allowances could be swept back
into a federal pool and distributed to project providers on a first-
come, first served basis. The EPA requests comment on these ideas as
well as alternative proposals regarding the method for redistributing
matching allowances, as well as the appropriate timing for such a
redistribution.
---------------------------------------------------------------------------
\111\ This is the same distribution method proposed above for
the allocation of early action set-aside allowances to mass-based
federal plan states.
---------------------------------------------------------------------------
Following the effective date of a federal plan for a state, the
agency will create an account of matching allowances for the state that
reflects the pro rata share of the 300 million short ton CO2
emissions-equivalent matching pool that the state is eligible to
receive. Any matching allowances that remain undistributed after
September 6, 2018 \112\ will be distributed to those states with
approved state plans that include requirements for CEIP participation,
as well as to those states on whose behalf the EPA is implementing a
federal plan. These allowances will be distributed according to the pro
rata method outlined above. Unused matching allowances that remain in
the accounts of states participating in the CEIP on January 1, 2023,
will be retired by the EPA. The EPA seeks comment on whether the number
of matching allowances available to a state under the mass-based
federal plan should be limited to a number equal to the number of early
action allowances included in each federal plan state's early action
set-aside.
---------------------------------------------------------------------------
\112\ This may occur because not all states may elect to include
requirements for CEIP participation in their state plans.
---------------------------------------------------------------------------
Third, for any state subject to a federal plan, the EPA proposes to
award early action allowances and matching allowances to eligible
projects as
[[Page 65026]]
follows, based upon the quantified and verified MWh of generation or
savings achieved by the projects in 2020 and/or 2021:
For RE projects that generate metered MWh from any type of
wind or solar resources: For every two MWh generated, the project will
receive a number of allowances equivalent to one MWh from the state
early action allowance set-aside, and a number of matching allowances
equivalent to one MWh from the EPA.
For EE projects implemented in low-income communities: For
every two MWh in end-use demand savings achieved, the project will
receive a number of allowances equivalent to two MWh from the state
early action allowance set-aside, and a number of matching allowances
equivalent to two MWh from the EPA.
The EPA will address implementation details of the CEIP in a
subsequent action. Allowances awarded by the EPA pursuant to the CEIP
may be used for compliance by an affected EGU with its emission
standards in any compliance period and are fully transferrable prior to
such use. The EPA proposes to distribute any remaining early action
set-aside allowances in a state--after distribution to all eligible
projects in the state--to the affected EGUs in the state on a pro-rata
basis in proportion to the initial allocations made to those EGUs under
the mass-based federal plan.
As discussed in section V.E of this preamble, the EPA proposes to
allow any state where a federal plan is being implemented to take
responsibility for distributing allowances. This will allow a state to
tailor its allowance-distribution approach to the characteristics and
preferences of the state. The EPA proposes that a state that chooses to
replace the federal plan allocations with a state-determined approach
must include a CEIP set-aside, as authorized in section VIII.B.2 of the
final EGs. The EPA intends that such a state would have the same
flexibilities as a state implementing a full state plan with respect to
implementation of the CEIP. That is, the state would not be required to
implement a set-aside of the same size as proposed in Table 10 of this
preamble, but rather could choose how many of its allowances to set-
aside for the CEIP.
The EPA requests comment on all aspects of implementing the CEIP
under a mass-based federal plan approach, including (1) The size of the
early action allowance set-aside; (2) the approach for distributing the
early action allowance set-aside among states; (3) the timing of
distribution of set-aside and matching allowances; (4) the amount of
allowances awarded per eligible MWh generated or avoided; (5) the
criteria for eligible projects, including criteria for awards to EE
projects implemented in low-income communities; (6) the mechanism for
reviewing project submittals and issuing early action allowances; (7)
EM&V requirements for eligible projects; and, (8) the number of early
action and matching allowances that should be awarded for each ton of
emissions reduced from eligible generation or low-income efficiency
projects to ensure a robust response to the program. The EPA also seeks
comment on how states, tribes and territories for whom goals have not
yet been established in the final EGs may be able to participate in the
CEIP in the future.
The EPA also requests comment on the proposed approach of requiring
states to implement this program as a condition of a state choosing to
determine its own allocation approach via a partial state plan or a
delegation of the federal plan.
Table 10--Proposed Clean Energy Incentive Program Early Action Allowance
Set-Aside in the Mass-Based Federal Plan
[Short tons]
------------------------------------------------------------------------
Set-aside 2022
State through 2024
------------------------------------------------------------------------
Alabama................................................. 3,122,306
Arizona................................................. 1,719,618
Arkansas................................................ 2,187,230
California.............................................. 218,846
Colorado................................................ 2,223,192
Connecticut............................................. 69,415
Delaware................................................ 138,392
Florida................................................. 3,230,248
Georgia................................................. 2,755,623
Idaho................................................... 14,929
Illinois................................................ 5,968,721
Indiana................................................. 5,754,076
Iowa.................................................... 2,191,183
Kansas.................................................. 2,115,630
Kentucky................................................ 4,952,862
Lands of the Fort Mojave Tribe.......................... 5,885
Lands of the Navajo Nation.............................. 1,623,066
Lands of the Uintah and Ouray Reservation............... 175,509
Louisiana............................................... 1,497,428
Maine................................................... 20,739
Maryland................................................ 972,775
Massachusetts........................................... 170,471
Michigan................................................ 3,727,861
Minnesota............................................... 2,002,903
Mississippi............................................. 357,307
Missouri................................................ 3,771,322
Montana................................................. 1,310,344
Nebraska................................................ 1,481,695
Nevada.................................................. 336,288
New Hampshire........................................... 107,798
New Jersey.............................................. 446,005
New Mexico.............................................. 823,049
New York................................................ 557,771
North Carolina.......................................... 2,674,590
North Dakota............................................ 2,150,635
Ohio.................................................... 4,788,372
Oklahoma................................................ 2,067,006
Oregon.................................................. 154,353
Pennsylvania............................................ 5,039,346
Rhode Island............................................ 35,674
South Carolina.......................................... 1,652,802
South Dakota............................................ 264,207
Tennessee............................................... 2,178,084
Texas................................................... 10,400,192
Utah.................................................... 1,401,189
Virginia................................................ 1,386,546
Washington.............................................. 751,434
West Virginia........................................... 3,506,890
Wisconsin............................................... 2,393,870
Wyoming................................................. 3,104,324
------------------------------------------------------------------------
5. Allocations to Units That Change Status
Units that retire. The EPA proposes that, if an affected EGU does
not operate for 2 consecutive calendar years, the unit would continue
to receive allocations for a limited number of years after it ceases
operation, after which the allowances that would otherwise have been
allocated to that unit would be allocated to the RE set-aside for the
state in which the retired unit is located.\113\ Continuing allocations
to non-operating units for a period of time reduces the incentive to
keep a unit operating simply to avoid losing the allowance allocations
for that unit (e.g., a unit that would otherwise be retired due to age
and inefficiency). On the other hand, non-operating units are no longer
emitting and so do not need allowances. The EPA believes that the
proposed approach of allocating allowances for a specified, but
limited, period after a unit ceases operating is a reasonable middle
ground approach. The proposed approach also allows the RE set-asides to
grow over time.
---------------------------------------------------------------------------
\113\ This is similar to the approach taken in CSAPR of
continuing allocations to retired units for four years and then
allocating the allowances to a set-aside; in CSAPR the set-aside is
for new units.
---------------------------------------------------------------------------
The EPA proposes to record allowances for each year of a multi-year
compliance period at once, 7 months prior to the start of each
compliance period, as discussed above. The agency proposes that, if an
affected EGU does not operate for 2 full calendar years, then starting
with the next compliance
[[Page 65027]]
period for which allowances have not yet been recorded, the allowances
that would otherwise have been allocated to the unit would be allocated
to the RE set-aside. As a result, the number of years of non-operation
for which a retired unit would receive allocations would vary depending
on when a unit retires. For example, if an affected EGU does not
operate for the first two calendar years of a 3-year compliance period,
then starting with the next compliance period the allowances that would
otherwise have been allocated to that unit would be allocated to the RE
set-aside--in other words the unit would receive allocations for 3
years of non-operation. As a further example, if an affected EGU does
not operate for both calendar years of a 2-year compliance period, then
starting with the compliance period after the next compliance period
the allowances would be allocated to the RE set-aside--in other words
the unit would receive allocations for 4 years of non-operation.
The agency requests comment on this approach for treatment of
allocations to affected EGUs that retire, including on the number of
years of non-operation for which a unit would continue to receive
allocations. The EPA also requests comment on an alternative of
distributing such allowances to the set-aside for output-based
allocations, or to the remaining affected EGUs in the state in a pro-
rata fashion (on the same distribution basis as the initial allocations
were made), instead of allocating such allowances to the state's RE
set-aside. The agency requests comment on a further alternative
approach, which would be to continue allocations to the retired units.
The EPA also requests comment on treatment of allocations to units that
are in long-term cold storage.
Units that are modified or reconstructed. Similar to the approach
for an affected EGU that retires, the EPA proposes that, if a unit is
modified or reconstructed such that it is no longer an affected EGU,
then starting with the next compliance period for which allowances have
not yet been recorded, the allowances that would otherwise have been
allocated to the unit would be allocated to the RE set-aside. The EPA
requests comment on this proposed approach, including on the number of
years for which a unit would continue to receive allocations. The
agency also requests comment on an alternative of distributing such
allowances to the set-aside for output-based allocations, or to the
remaining affected EGUs in the state in a pro-rata fashion (on the same
distribution basis as the initial allocations were made), instead of
allocating such allowances to the state's RE set-aside. The agency
requests comment on a further alternative approach, which would be to
continue allocations to the modified or reconstructed units.
E. State-Determined Allowance Distribution
The EPA proposes to allow any state to replace the EPA-determined
federal plan allowance-distribution provisions in the mass-based
trading program with state-developed allowance-distribution provisions.
In this way, a state could choose how to distribute initial allowance
allocations among its affected EGUs (and other entities).
The EPA believes that this option may offer significant appeal,
because it will allow a state to tailor its allocation approach to the
characteristics and preferences of the state. A state would be able to
design its allocation approach to address its particular state
priorities, whether they are protecting low-income consumers,
supporting local industries, or other goals. The EPA anticipates that a
state would have great flexibility in its allowance distribution
approach and could take advantage of allocation options discussed in
this proposal as well as other allocation options a state might prefer.
States could auction allowances and rebate the revenue to consumers, or
allocate all allowances to load-serving entities, while mandating that
the value be passed through to vulnerable consumers. The EPA believes
that the state-determined allocation approach offers significant
advantages and solicits comment on how to ease its application by
states. This is similar to the approach taken in CSAPR and CAIR where
the EPA adopted rules allowing states to submit SIPs with provisions
replacing the allowance-distribution provisions in the CSAPR or CAIR
FIPs, respectively, while remaining in the trading programs under those
FIPs (76 FR 48208; August 8, 2011, 71 FR 25328; April 28, 2006). In
both CSAPR and CAIR, some states have chosen to determine their own
allocations under the FIPs. This form of SIP that can replace the
allowance-distribution provisions in CSAPR or CAIR is termed an
``abbreviated SIP revision.'' In this proposed mass-based trading
federal plan, the EPA proposes that a state may choose to submit a
``state allowance-distribution methodology'' (analogous to an
abbreviated SIP revision) to replace the federal plan allowance-
distribution provisions with allowance-distribution provisions of its
choosing.
The mechanism the agency envisions is in the nature of a partial
state plan or (for any future changes in a state's allocation
methodology) a partial state plan revision. (We request comment below
on the advantages and disadvantages of allowing a state to handle
allocations via a delegation of federal plan authority.) In general,
under the proposed approach, the procedural requirements states and the
agency must follow, including public notice requirements, for the
submission and approval of state plans, would be required here.
The EPA intends to provide the states with substantial flexibility
in choosing approaches to distribute their allowances in a state
allowance-distribution methodology. The EPA proposes that a state may
choose any approach, including auctions or other methods the EPA is not
proposing here, provided the state's approach addresses leakage and
also implements the Clean Energy Incentive Program. The EPA is also
requesting comment on any other appropriate constraints to impose on
state allowance-distribution methodologies.
The Clean Power Plan EGs require mass-based state plans to include
a demonstration that they have addressed the risk of leakage, and the
EGs provide several options for doing so (see sections VII.D and VIII.J
of the final EGs). One of the options provided in the EGs is to address
leakage through an allowance distribution approach that provides
incentive to counteract leakage. In the mass-based trading federal
plan, the EPA's proposed approach to allocate allowances would address
leakage using two allowance set-asides, one for output based allocation
and one for RE projects, as detailed in section V.D.3 of this preamble.
The EPA believes that a state allowance-distribution methodology, which
would replace the federal plan allocation provisions, must also address
leakage. The EPA proposes that a state allowance-distribution
methodology must address leakage by providing incentive to counteract
leakage, e.g., by including allowance set-asides like the output-based
allocation and RE set-asides detailed in section V.D.3 of this
preamble, or other allocation approaches designed to counteract
leakage. The EPA requests comment on this proposed approach for
addressing leakage in a state allowance-distribution methodology and on
any other approaches for doing so. The EGs provide an additional option
for state plans to address leakage, where a state would provide a
demonstration that leakage will not occur (without implementing any of
the strategies specified in the EGs) due to specified
[[Page 65028]]
characteristics of the state (section VIII.J of the final EGs). In this
federal plan proposal, the EPA requests comment on an alternative
option where a state that chooses to submit a state allowance-
distribution methodology could provide a demonstration that leakage
will not occur (without implementing the allocation strategies
specified here) due to specific characteristics of the state; the EPA
proposes that such demonstration must meet the requirements in the
final EGs, including support by credible analysis, for such a
demonstration (see final EGs section VII.D). The EPA notes that a
state's allowance-distribution methodology may also include other set-
aside approaches that are not designed to counteract leakage.
The Clean Power Plan EGs established a Clean Energy Incentive
Program (section VIII of the final EGs). The EPA proposes that a state
allowance-distribution methodology, which would replace the federal
plan allocation provisions, must also include a Clean Energy Incentive
Program, as detailed in section V.D.4 of this preamble.
Under the proposed approach of providing for states to determine
their allowance distribution approaches in the federal plan mass-based
trading program, the affected EGUs in a state that submitted a state
allowance-distribution methodology, which the EPA approved, would
participate in the federal plan mass-based trading program, but with
allowance distribution determined by the state instead of by the EPA.
The EPA proposes that a state must submit to the Administrator
tables specifying the unit-level allowances in an electronic format
specified by the Administrator and by the specified deadlines
applicable to each compliance period (see Table 11 of this preamble for
proposed submission deadlines).
The EPA proposes that a state may submit a state allocation
methodology for any compliance period, including the first compliance
period, which would comprise the years 2022, 2023, and 2024. The EPA
proposes that a state submitting a state allowance-distribution
methodology to modify the federal plan allowance-distribution
provisions must do so for all years within a compliance period (e.g.,
for all 3 years in a 3-year compliance period).
The EPA proposes that, if the state's allowance-distribution
provisions meet certain requirements and the state allowance-
distribution methodology does not change any other provisions in the
proposed mass-based trading program, then the agency would likely
approve the state allowance-distribution methodology. In the state
allowance-distribution methodology, the state could distribute
allowances to affected EGUs or other entities (such as RE facilities)
or could auction some or all of the allowances. The agency proposes
that for EPA approval, the state allowance-distribution methodology
provisions would have to meet the following requirements. The
provisions would have to address leakage as discussed above. The
provisions would have to provide that, for each year for which the
state allowance-distribution provisions would apply, the total amount
of allowances distributed could not exceed the applicable mass goal for
that state for that year. A state's methodology under this proposed
approach could provide that the total amount of allowances distributed
is less than the applicable mass goal.\114\ The EPA proposes that a
state's allowance-distribution provisions would replace the EPA's
allocation provisions completely--a state would not have the option of
implementing only a portion of its allocations (e.g., only set-asides)
and having the EPA implement the remainder of its allocations.
Additionally, the EPA proposes that a state allowance-distribution
methodology must provide for allowances to be issued in short tons.
---------------------------------------------------------------------------
\114\ A state allowance-distribution methodology under this
proposed approach, which is analogous to an abbreviated SIP
revision, could provide that the total amount of allowances
distributed is less than the applicable mass goal, pursuant to the
reserved authority to states to set emission standards more
stringent than federal standards under CAA section 116.
---------------------------------------------------------------------------
The allocation (or auction) of allowances would be final and could
not be subject to modification. Additionally, the state's provisions
could not change any other provisions of the proposed mass-based
trading program with regard to the allowances (e.g., the deadlines for
allocation recordation, or requirements for transfer or use of
allowances) or any other aspect of such trading programs.
In order for a state allowance-distribution methodology's
provisions to replace the EPA's allowance-distribution provisions for a
given compliance period, a state would have to submit the state
allowance-distribution methodology by a deadline that would provide the
agency sufficient time to review and approve it, and to submit the
allowance table meeting the specified electronic format by a deadline
that would provide sufficient time to record the unit-by-unit
allowances in source accounts. The EPA believes that about 12 months--
starting from the date of receipt of a state allowance-distribution
methodology--is sufficient to complete the agency's review and approval
process, which would have to provide an opportunity for public comment
on the approval (or disapproval) action. Thus, the EPA proposes the
following deadlines, in Table 11 of this preamble, for submission to
the agency of state allowance-distribution methodologies and unit-level
allowances, and for the EPA's recordation of allowances, for each
compliance period. The EPA would review and approve state allowance-
distribution methodologies in the 12 months between the proposed
deadline for states to submit their methodologies and the proposed
deadline for states to submit unit-level allowance tables. The proposed
deadline for submission of allowance tables is 3 months before the
proposed deadline for the agency to record allowances in source
accounts. The EPA proposes to record allowances in source accounts by
the recordation deadlines.
Table 11--Proposed Deadlines for Submission of State Allowance-Distribution Methodologies and Unit-Level
Allowances and for Recordation
----------------------------------------------------------------------------------------------------------------
Deadline for submittal
First compliance period for which of state allowance- Deadline for submittal Deadline for the EPA to
allowances would be distributed distribution of unit-level record allowances
methodologies allowance table
----------------------------------------------------------------------------------------------------------------
2022, 2023, 2024................... March 1, 2020......... March 1, 2021......... June 1, 2021.
2025, 2026, 2027................... March 1, 2023......... March 1, 2024......... June 1, 2024.
2028, 2029......................... March 1, 2026......... March 1, 2027......... June 1, 2027.
2030, 2031 *....................... March 1, 2028 *....... March 1, 2029.*....... June 1, 2029 *
----------------------------------------------------------------------------------------------------------------
* This pattern of deadlines would hold for successive 2-year compliance periods.
[[Page 65029]]
The proposed deadlines for submission of state allowance-
distribution methodologies are later than the state plan submission
deadlines promulgated in the Clean Power Plan EGs. The agency
anticipates that it can complete the approval process relatively
quickly for a state allowance-distribution methodology due to its
narrow scope.
The agency proposes to record the EPA-determined federal plan
allocations only in the absence of an approved state plan or approved
state allowance-distribution methodology. The EPA proposes to record in
source accounts allowances that are determined by any state as soon as
feasible after approval of a state allowance-distribution methodology
and submission of the unit-level allowance table, and not to wait until
the allowance recordation deadline to do so.
In section V.D.2 of this preamble, the EPA proposes that the
allowance recordation deadline be 7 months prior to the start of the
compliance period (i.e., June 1 of the prior year) and also requests
comment on a recordation deadline 13 months prior to the start of the
compliance period (i.e., December 1 of the year, 2 years before the
compliance period starts). If the EPA adopted the earlier recordation
deadline on which it requests comment or any other deadline, then we
would adjust the deadlines for submission of state allowance-
distribution methodologies and submission of unit-level allowance
tables accordingly.
The EPA proposes that a state may not replace EPA-determined
allocations for a compliance period for which federal plan allocations
have already been recorded, for the same reasons that the agency
proposes that a state may not replace a mass-based trading federal plan
with a state plan for a future compliance period for which allowances
have already been recorded, as discussed below in section V.F of this
preamble.
The agency requests comment on the proposed approach to allow
states to determine allocations via state allowance-distribution
methodologies and replace the federal plan allowance-distribution
provisions. The EPA requests comment on the proposed schedule for
submitting state allowance distribution methodologies to the agency,
for submitting the resulting unit-level allowance tables to the agency,
and for the agency to record allowances. The EPA requests comment on
its proposed approach of not replacing EPA-determined allocations for a
compliance period for which allowances have already been recorded. The
agency also requests comment on an alternative approach where a state
could notify the EPA of its intent to submit a state allowance-
distribution methodology in advance, in which case the agency would
hold off on recording EPA-determined allocations to allow more time for
state-determined allowances to be recorded, similar to the alternative
timing approach discussed in section V.F of this preamble.
The EPA is also requesting comment on an alternative approach to
provide the opportunity for a state to determine its allowance-
distribution provisions in the federal plan mass-based trading program.
The alternative approach on which the agency requests comment is to
provide for a partial delegation of the federal plan--limited to the
allowance-distribution provisions--to a state that wishes to determine
its allowance-distribution provisions. The EPA requests comment on the
relative efficiency and ease of implementation of the two approaches
(the state allowance-distribution methodology described above, or the
partial delegation). The agency requests comment on whether the partial
delegation approach would provide sufficient flexibility for a state to
choose any method to distribute its allowances including approaches
that the EPA is not proposing here. See further discussion of
delegations in section VI of this preamble.
F. Treatment of States Entering or Exiting the Trading Program
If the EPA implements a mass-based trading program federal plan for
any state, the agency will work with a state that wishes to replace the
federal plan with an approved state plan to provide a smooth
transition. The EPA proposes that a mass-based trading federal plan
could only be replaced by a state plan for a future compliance period
for which allowances have not yet been recorded. For example, if a 3-
year compliance period comprises 2022, 2023, and 2024, the EPA would
record allowances in source accounts for 2022, 2023, and 2024 prior to
2022. Once 2022, 2023, and 2024 allowances had been recorded, the first
compliance period for which a state could replace the federal plan with
its own plan would be for the period commencing in 2025. The EPA is
proposing this stipulation for the timing of replacing a federal plan
with a state plan due to the need to avoid disruption to sources
already subject to the mass-based trading federal plan. Without this
stipulation, a state might withdraw from the mass-based trading program
in the middle of a compliance period even though allowances that
authorize emissions throughout that entire compliance period would
already be in circulation. In that circumstance, the EPA would then
need to address whether and how to remove those allowances from
circulation to prevent inflation of the allowable emissions at affected
EGUs in the remaining states subject to the federal plans beyond the
levels specified in the Clean Power Plan EGs. The EPA believes it is
more reasonable to avoid this potential disruption by requiring that
the replacement of a federal plan with a state plan be scheduled to
coincide with the conclusion of the last compliance period for which
allowances under the federal plan have already been recorded for that
state. The EPA requests comment on other approaches to provide a smooth
transition from federal plan implementation to implementation by state
plans, and on its proposed approach of not replacing a federal plan for
any compliance period for which allowances were already recorded.
The agency requests comment on an alternative of providing for a
state to give notice to the EPA of its intent to submit a state plan to
replace the federal plan (or a state allowance-distribution methodology
to replace federal plan allocations), and for the agency to delay
recording federal plan allocations for sources in that state until a
later date than proposed. The EPA requests comment on whether this
alternative would help smooth the transition from federal plan
implementation to state plan implementation, and on the trade-off
between recording allowances in a timely way and providing this
increased timing flexibility.
G. Allowance Tracking, Compliance Operations, and Penalties
The EPA proposes that the mass-based trading program use an ATCS
operated essentially the same way as the existing systems that are
currently in use for CSAPR and the ARP under Title IV. Under the
proposed mass-based trading program, the CO2 program would
be a separate trading program maintained in the EPA's existing data
system. ATCS would be used to track the trading of CO2
allowances held by covered affected EGUs in facility level compliance
accounts, as well as such allowances held by other entities or
individuals. Specifically, ATCS would track the allocation of all
CO2 allowances, holdings of CO2 allowances in
compliance accounts (i.e., a facility level account for all affected
EGUs at the facility) and general accounts (i.e., accounts for other
entities such as companies and brokers), deduction of CO2
allowances for compliance
[[Page 65030]]
purposes, and transfers of allowances between accounts. The primary
role of ATCS is to provide an efficient, automated means for affected
EGUs to comply, and for the EPA to determine whether affected EGUs are
complying, with the emissions limitations and any other requirements of
the mass-based trading program. ATCS would also provide data to the
allowance market and the public, including a record of ownership of
allowances, dates of allowance allocations, allowance transfers, buyer
and seller information, serial numbers of allowances transferred,
emissions, and compliance information. This information would be
publicly available on the EPA's Web site and in annual progress
reports.
1. Designated Representatives and Alternate Designated Representatives
The EPA proposes to establish procedures for certifying and
authorizing the designated representative, and alternate designated
representative, of the owners and operators of an affected EGU and for
changing the designated representative and alternate designated
representative. The proposed provisions 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 are patterned after the provisions
concerning designated representatives and alternates in prior EPA-
administered trading programs.
Under the proposed provisions, the designated representative would
be the individual authorized to represent the owners and operators of
each affected EGU in matters pertaining to the mass-based trading
program. One alternate designated representative could also 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 affected EGU and for
the designated representative and alternate; the name of every owner
and operator of the affected EGU; and certification language and
signatures of the designated representative and alternate. All
submissions (e.g., monitoring plans, monitoring system certifications,
and allowance transfers) for an affected EGU 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 ATCS for each facility with an affected EGU 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
affected EGU 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 and
alternate to delegate authority to make electronic submissions on his
or her behalf. The designated representative and 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 mass-based trading program, while
ensuring accountability by owners and operators and simplifying the
administration of the proposed mass-based trading program.
2. Allowance Tracking and Compliance System
The proposed mass-based trading program rules include procedures
and requirements for using and operating the ATCS (which is the
electronic data system through which the Administrator would handle
allowance allocation, holding, transfer, and deduction), and for
determining compliance with the allowance-holding requirements in an
efficient and transparent manner. Under the proposed rules, the ATCS
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 programs, allowance price
information would not be included in the ATCS. The 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
the 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.
3. Compliance and General Accounts
The proposed provisions addressing compliance and general accounts
describe two types of ATCS accounts: Compliance accounts, one of which
the Administrator would establish for each facility with an affected
EGU upon receipt of the certificate of representation for the facility;
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
an affected EGU for compliance with the emissions limitations would
have to be held. The designated representative and alternate for the
affected EGU would also be the authorized account representative and
alternate for the compliance account. Using facility-level, rather than
EGU-level accounts, would provide owners and operators more flexibility
in managing their allowances for compliance, without jeopardizing the
environmental goals of the mass-based trading program, because the
facility-level approach would avoid situations where an EGU would hold
insufficient allowances and would be in violation of allowance-holding
requirements even though EGUs at the same facility had more than enough
allowances to meet these requirements for the entire facility.
Facility-level compliance would also be consistent with other EPA-
administered mass-based trading programs.
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 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
[[Page 65031]]
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 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.
4. Recordation of Allowance Allocations and Transfers
The EPA proposes to establish the following schedule and procedures
for recordation of allowance allocations and transfers. By June 1,
2021, the Administrator would record allowance allocations for EGUs for
2022 through 2024. Then, by June 1 of the year prior to the beginning
of each compliance period, the Administrator would record the allowance
allocations for the proposed mass-based trading program for each year
within that next compliance period, e.g., for 2025, 2026, and 2027 by
June 1, 2024. Recording these allowance allocations 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.
Under the proposed provisions, the process for transferring
allowances from one account to another would be quite simple.
Allowances could be transferred by submitting a transfer form
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 a 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.
5. Compliance With Emissions Limitations
The EPA proposes to include the following provisions regarding
compliance with emission limitations. Under the proposed provisions,
once the compliance period has ended (e.g., at midnight on December 31,
2024 for the first compliance period), facilities with affected EGUs
would have a window of opportunity following the compliance period to
evaluate their reported emissions and obtain any allowances that they
might need to cover their emissions during the compliance period. For
example, the allowance transfer deadline for the first compliance
period would be midnight on May 1, 2025 (the EPA is also requesting
comment on earlier or later allowance transfer deadlines). Each
allowance issued in the proposed mass-based trading program would
authorize emission of one ton of CO2 and so would be usable
for compliance, for the compliance period that includes the year for
which the allowance was allocated or a later compliance period.
Consequently, each affected EGU would need, as of the allowance
transfer deadline, to have in its facility compliance account, or to
have a properly submitted transfer that would move into its compliance
account, enough allowances usable for compliance to authorize its total
emissions for the compliance 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. Deducting allowances may have tax and accounting implications,
so having a default deduction method provides the representatives with
certainty regarding which allowances will be deducted for compliance.
Allowances that are deducted for compliance will remain in the system
in an EPA account, which ensures they will not be used again. If a
facility were to fail to hold sufficient allowances for compliance by
all affected EGUs at the facility, then the owners and operators of the
facility and each affected EGU at the facility would have to provide,
for deduction by the Administrator, two allowances allocated for the
compliance period in the next year for every allowance that the owners
and operators failed to hold as required to cover emissions. This
submittal of two times the allowances required for the prior period is
an ongoing obligation until compliance is achieved, and there is an
ongoing obligation to comply in the current period. In addition, these
owners and operators would be subject to civil penalties for each
violation in accordance with the CAA, with each ton of unauthorized
emissions and each day of the compliance period involved constituting a
violation of the CAA.
The 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 automatic deduction of another allowance per
allowance that the owners and operators failed to hold that could not
be avoided, regardless of any explanation provided by the owners and
operators for their failure, would 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. Such automatic deductions have been successfully used in
prior programs including the CAIR, achieving compliance rates close to
100 percent.
6. Other Allowance Tracking and Compliance Operations Provisions
The proposed provisions regarding allowance tracking and compliance
also 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 ATCS. In addition, the Administrator could
review any submission under the mass-based trading program, make
adjustments to the information in the submission, and deduct or
transfer allowances based on such adjusted information. These
provisions are a standard part of other trading programs administered
by the EPA including the ARP and Cross State Air Pollution Rule (see 40
CFR 72.96, 73.37, 97.427, and 97.428).
H. Emissions Monitoring and Reporting Requirements
The EPA proposes that units subject to the mass-based federal plan
trading program would monitor and report CO2 mass emissions
in accordance with 40 CFR part 75.
The EPA is proposing to require affected EGUs in all states covered
by the mass-based federal plan trading program to monitor and report
CO2 emissions and output data by January 1, 2022. Quarterly
reporting would be
[[Page 65032]]
required, with each quarterly report due to the Administrator 30 days
after the last day in the quarter. The reporting would be in accordance
with 40 CFR 75.60. The use of 40 CFR part 75 certified monitoring
methodologies would be required. Many EGUs that might be covered by the
proposed federal plans will generally have no changes to their
monitoring and reporting requirements and will continue to monitor and
submit reports under 40 CFR part 75 as they have under existing
programs. The EPA anticipates fewer than 50 affected EGUs that would
not otherwise be subject to the ARP will have to purchase and install
additional CEMS and data handling systems or upgrade existing equipment
in order to meet the monitoring and reporting requirements of this
program (the EPA anticipates approximately 10 coal fired units and
approximately 40 gas and oil fired units will qualify for an excepted
monitoring methodology). Several of the units not otherwise subject to
the ARP are subject to the MATS program and, therefore, will have
already installed stack flow rate and/or CO2 monitors
necessary to comply with this rule in order to comply with the MATS.
The CEMS used to comply and report data for MATS will be used for this
rule to generate and report CO2 emissions data without
having to install duplicative monitors. The same CO2 and
stack gas flow rate monitored data used in conjunction with mercury and
other CEMS to calculate a toxic pollutant emission rate may be used to
calculate a CO2 mass or CO2 emission rate for
this program. RGGI, ARP, MATS and this rule all refer to CEMS installed
and certified in accordance with 40 CFR part 75. RGGI and ARP currently
require the reporting of CO2 mass emissions on an hourly
basis and cumulative totals at the end of each calendar quarter. The
same monitors and data collected may be used for multiple purposes for
RGGI, ARP, MATS and this rule. Relying on the same monitors that are
certified and quality ensured in accordance with 40 CFR part 75 ensures
cost efficient, consistent, and accurate data that may be used for
different purposes for multiple regulatory programs.
The majority of the units covered by this rule are already affected
by the Acid Rain and/or RGGI programs and will have minimal additional
monitoring and reporting requirements.
The EPA also requests comment on requiring monitoring and reporting
of CO2 mass and net generation for the year before the
initial compliance period begins, i.e., to commence January 1, 2021.
Only the monitoring and reporting would be required in 2021--compliance
with the requirement to hold allowances would commence on the
compliance period schedule that is detailed in section V.C of this
preamble.
VI. Implementation of the Federal Plan and Delegation
Under section 111(d) of the CAA, the EPA adopts EGs that are then
implemented when the EPA approves a state or tribal \115\ plan or
promulgates a federal plan that implements and enforces the EGs for
affected EGUs in states or areas of Indian country \116\ without an
approved state or tribal plan. Congress has determined that the primary
responsibility for air pollution prevention and control rests with
state and local agencies, while also recognizing that federal
leadership is essential for the development of cooperative federal,
state, regional, and local programs to prevent and control air
pollution. See CAA section 101(a)(3) and (4). Congress has also
provided for Indian Tribes meeting specified eligibility criteria to
implement the CAA within the exterior boundaries of their reservations
or other areas within the tribe's jurisdiction. See CAA section
301(d)(1) and (2). Even in the event that it becomes necessary for the
EPA to directly regulate affected EGUs under CAA section 111(d), states
and eligible tribes may still seek a delegation of authority from the
EPA to implement a federal plan, similar to the ability to take
delegated authority under other CAA programs. The EPA encourages states
and eligible tribes that do not submit approvable plans to request
delegation of the federal plan if they wish to have primary
responsibility for implementing the EGs. Approved and effective state
or tribal plans or delegation of the federal plan is the EPA's
preferred outcome in many circumstances where the EPA believes that
state and local, or tribal, agencies have practical knowledge and
enforcement resources critical to achieving the highest rate of
compliance. Delegation of a standard or requirement generally means
that obligations a source may have to the EPA under a federally
promulgated standard become obligations to a state or tribe in the
first instance (except for functions that the EPA retains for itself)
upon delegation.117 118
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\115\ As discussed in section VI.D of this preamble, tribes with
affected EGUs in their areas of Indian country can apply for TAS for
the purpose of developing and seeking EPA approval of a tribal
implementation plan (TIP) implementing the EG, but are not required
to do so.
\116\ As discussed in section VI.D of this preamble, in adopting
a federal plan implementing the EGs in areas of Indian country
containing affected EGUs, the EPA must determine that such a plan is
``necessary or appropriate'' to protect air quality. See 40 CFR
49.11(a).
\117\ If the Administrator chooses to retain certain authorities
under a standard, those authorities cannot be delegated, e.g., the
authority to allow alternative methods of demonstrating compliance.
\118\ We note that issuance of a title V permit is not
equivalent to the approval of a state plan or delegation of a
federal plan. This has been discussed in prior rulemakings, see,
e.g., Proposed Federal Plan for Commercial Industrial Solid Waste
Incinerators (CISWI) (67 FR 70640, 70652; November 25, 2002); Final
Federal Plan for CISWI (68 FR 57518, 57535; October 3, 2003).
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A. Delegation of the Federal Plan and Retained Authorities
If a state or tribe \119\ intends to take delegation of the federal
plan, the state or tribe should submit to the appropriate EPA Regional
Office a written request for delegation of authority. The state or
tribe should explain how it meets the criteria for delegation. These
criteria are explainedgenerally in the ``Good Practices Manual for
Delegation of NSPS and NESHAP'' (EPA, February 1983). The letter
requesting delegation of authority to implement the federal plan
should: (1) Demonstrate that the state or tribe has adequate resources,
as well as the legal and enforcement authority to administer and
enforce the program; (2) include an inventory of affected EGUs, which
includes those that have ceased operation but have not been dismantled,
an inventory of the affected units' air emissions, and a provision for
state or tribal progress reports to the EPA; (3) certify that a public
hearing has been held on the state or tribal delegation request; and
(4) include a memorandum of agreement between the state or tribe and
the EPA that sets forth the terms and conditions of the delegation, the
effective date of the agreement and the mechanism to transfer
authority. Upon signature of the agreement, the appropriate EPA
Regional Office would publish an approval documentin the Federal
Register, thereby incorporating the delegation of authority into the
appropriate subpart of 40 CFR part 62. See also EPA's Delegations
Manual, Delegation 7-139, ``Implementation and Enforcement of 111(d)(2)
and 111(d)(2)/129(b)(3) federal plans.'' (A copy of this delegation has
been placed in the docket for this action.)
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\119\ A tribe interested in taking delegation of the federal
plan must also apply, and be approved by the EPA, for TAS
eligibility for that purpose. See 40 CFR part 49.
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If authority is not delegated to a state or tribe, the EPA will
implement the federal plan. Also, if a state or tribe fails to properly
implement a delegated portion of the federal plan, the EPA will assume
direct implementation and
[[Page 65033]]
enforcement of that portion. The EPA will continue to hold inspection,
information gathering, enforcement, and other parallel authorities
along with the state or tribe even when a state or tribe has received
delegation of the federal plan. In all cases where the federal plan is
delegated, the EPA may retain and not transfer authority to a state or
tribe to approve certain items promulgated in the 2015 CAA section
111(d) Clean Power Plan.
This proposed federal plan also specifies that EGU owners or
operators who wish to petition the agency for any alternative
requirement should submit a request to the Regional Administrator with
a copy sent to the appropriate state.
B. Mechanisms for Transferring Authority
There are two mechanisms for transferring implementation authority
to state and local agencies and tribes: (1) EPA approval of a state or
tribal plan after the federal plan is in effect; and (2) if a state or
tribe does not submit or obtain approval of its own plan, EPA
delegation to a state or tribe of the authority to implement certain
portions of this federal plan to the extent appropriate and if allowed
by state or tribal law. Both of these options are described in more
detail below.
1. Federal Plan Becomes Effective Prior To Approval of a State or
Tribal Plan
After EGUs in a state or area of Indian country become subject to
the federal plan, the state or local agency or tribe may still adopt
and submit a plan to the EPA. If the EPA determines that the state or
tribal plan is satisfactory and approvable pursuant to the EGs, the EPA
will approve the state or tribal plan. If the EPA, on review of the
submitted state or tribal plan, determines that this is not the case,
the EPA will disapprove the plan and the EGUs covered in the state or
tribal plan would remain subject to the federal plan until a state or
tribal plan covering those EGUs is approved and effective. Prior to
disapproval, the EPA will work with states and eligible tribes to
attempt to reconcile areas of the plan that are unapprovable.
Upon the effective date of an approved state or tribal plan, the
federal plan would no longer apply to EGUs covered by such a plan and
the state or local agency, or the tribe, would implement and enforce
the state or tribal plan in lieu of the federal plan. The timing of
effectiveness of an approved state or tribal plan in this circumstance
may depend in part on the need to ensure a smooth transition and
maintain regulatory certainty. Thus, for example, under a mass-based
federal plan, we propose to handle these transitions so that they
coincide with the compliance periods. The approval of a state or tribal
plan would also involve a public comment process, which would give
interested stakeholders including any affected EGUs, the opportunity to
comment. This will assist in ensuring that compliance, program
integrity, electric reliability, and other critical factors are
maintained. When an EPA Regional Office approves a state or tribal
plan, it will amend the appropriate subpart of 40 CFR part 62 or 40 CFR
part 49, respectively, to indicate such approval, as well as the timing
of its effectiveness.
As discussed elsewhere in this document, the EPA may also in
certain circumstances approve a partial state or tribal plan (sometimes
called an ``abbreviated state plan'') that may modify certain limited
provisions in the federal plan trading program. For example, this could
occur if a state or tribe wishes to handle the initial allocation of
allowances in a mass-based trading program, as discussed in section V.E
of this preamble. The partial state or tribal plan would allow for the
state or tribe to assume direct authority for administering and
implementing this aspect of the trading program, while the remainder of
the federal plan remains in place. The procedural and submission
requirements set forth in the framework regulations of 40 CFR part 60,
subpart B and the EGs would generally apply to a partial state or
tribal plan, just as they would a full state or tribal plan. The scope
of the requirement, however, would be commensurate with the scope of
the partial plan. For instance, if a state or tribe seeks approval of a
partial plan solely to handle allowance allocations, then the required
statement of legal authority would be limited to those legal
authorities the state or tribe must have to implement and enforce this
component of the trading program.
2. State or Tribe Takes Delegation of the Federal Plan
The EPA, in its discretion, may delegate to state or tribal air
agencies the authority to implement this federal plan. As discussed
above, the EPA believes that it is advantageous and the best use of
resources for state or local agencies or tribes to agree to undertake,
on the EPA's behalf, administrative and substantive roles in
implementing the federal plan to the extent appropriate and where
authorized by state or tribal law. If a state or tribe requests
delegation, the EPA will generally delegate the entire federal plan to
the state or tribal agency, thereby providing authority to the state or
tribe for things such as administration and oversight of compliance
reporting and recordkeeping requirements, inspections of its affected
EGUs, and enforcement. The EPA will continue to hold inspection,
information gathering, enforcement, and other authorities along with
the state or tribe even when a state or tribe has received delegation
of the federal plan. The delegation will not include any authorities
retained by the EPA.
C. Implementing Authority
The EPA Regional Administrators have been delegated the authority
for implementing the federal plan. All reports required by the federal
plan should be submitted to the appropriate Regional Administrator.
Section II.B of this preamble includes Table 2 that lists names and
addresses of the EPA Regional Office contacts and the states they
cover.
With respect to the administration of a federal trading program in
any final federal plan for a state or tribe, group of states or
combined group of states and tribes, the Office of Air and Radiation
within the Headquarters of the EPA is proposed to be the primary office
within the agency with delegated CAA section 111(d)(2) authority. See
Delegation 7-139, section 3(c).
D. Necessary or Appropriate Finding for Affected EGUs in Indian Country
Indian Tribes may, but are not required to, submit tribal plans to
implement the EGs. Section 301(d) of the CAA and 40 CFR part 49
authorize the Administrator to treat an Indian Tribe in the same manner
as a state (i.e., TAS) for purposes of developing and implementing a
tribal plan implementing the EGs. See 40 CFR 49.3; see also ``Indian
Tribes: Air Quality Planning and Management,'' hereafter ``Tribal
Authority Rule,'' (63 FR 7254, February 12, 1998). We invite tribes
with EGU in their area of Indian country to comment on the level of
their interest, if any, in developing their own plans.
The EPA is proposing in this action to find that it is necessary or
appropriate to regulate affected EGUs in each of the three areas of
Indian country that have affected EGUs under the proposed federal plan.
The EPA is authorized to directly implement the EGs in Indian country
when it finds, consistent with the authority of CAA section 301 which
the EPA has exercised in 40 CFR 49.11, that it is necessary or
appropriate to do so. In the final EGs, the EPA establishes emission
performance rates for the four EGUs located in Indian country and
[[Page 65034]]
mass- and rate-based emission goals for each of the three affected
areas of Indian country. These areas include lands of the Navajo
Nation's reservation, lands of the Ute Tribe of the Uintah and Ouray
Reservation, and lands of the Fort Mojave Tribe's reservation. The EPA
proposed carbon pollution EGs for EGUs in these areas and U.S.
Territories in a Supplemental Notice of Proposed Rulemaking. See 79 FR
65482 (November 4, 2014). The four facilities with affected EGUs
located in Indian country that the EPA identified in the Supplemental
Notice are: The South Point Energy Center, on the Fort Mojave
Reservation geographically located within Arizona; the Navajo
Generating Station, on the Navajo Indian Reservation geographically
located within Arizona; the Four Corners Power Plant, on the Navajo
Indian Reservation geographically located within New Mexico; and the
Bonanza Power Plant, on the Uintah and Ouray Indian Reservation
geographically located within Utah. The emission performance targets
for these areas were finalized along with those for EGUs located in the
rest of the country in the final EGs.
In this action, we are proposing to find that it is necessary or
appropriate, in each of the three areas of Indian country that have
affected EGUs, to establish a federal plan that applies to the four
power plants located on the Navajo Nation, the Fort Mojave Indian
Reservation, and the Uintah and Ouray Reservation of the Ute Tribe. The
affected EGUs located on the Navajo Nation are in an area of Indian
country located within the continental United States, are
interconnected with the western electricity grid, and are owned and
operated by entities that generate and provide electricity to customers
in several states. The affected EGU located on the Uintah and Ouray
Reservation of the Ute Tribe is in an area of Indian country located
within the continental United States, is interconnected with the
western electricity grid, and is owned and operated by an entity that
generates and provides electricity to customers in several states. The
affected EGU located on the Fort Mojave Indian Reservation is in an
area of Indian country located within the continental United States, is
interconnected with the western electricity grid, and is owned and
operated by an entity that generates and provides electricity to
customers in several states. To date, none of the three tribes on whose
areas of Indian country the four power plants are located have
expressed a clear intent to develop and seek approval of a tribal
implementation plan. Thus, absent a federal plan, the significant
emissions from these four power plants could go unregulated by the
Clean Power Plan.
Because the agency has finalized emission performance targets for
these power plants in the EGs, there is, in our view, little benefit to
be had by not proposing to include them in a federal plan now and a
potentially significant downside to not doing so; the reductions the
EPA has determined are achievable in the EGs would become more
difficult and costly for these power plants to achieve if they are
delayed in entering into the trading program the agency intends to
establish. In order to meet the performance targets, we are
anticipating that the affected EGUs may need to secure allowances or
ERCs (depending on the approach ultimately finalized) during the
compliance periods. They may also be able to generate and sell
compliance instruments by participating in the trading program. Thus,
proposing a finding that it is necessary or appropriate to establish
one or more federal plans providing the ability to participate in a
rate- or mass-based trading program is in the interest of these four
power plants located in areas of Indian country. We believe that this
together with the facts that, as indicated above, all four EGU are
interconnected with the western electricity grid and are owned and
operated by an entity that generates and provides electricity to
customers in several states thereby making it potentially disruptive
and inequitable not to include them in one or more federal plans on the
same schedule as other affected EGU strongly supports proposing to find
that it is necessary or appropriate to establish one or more applicable
federal plans at this time.
We recognize that the governments of these tribes may still choose
to seek TAS to develop a tribal plan, and this proposed determination
does not preclude the tribes from taking such actions. We also note
that this proposed determination does not preclude these tribes from
seeking TAS and receiving delegation to administer aspects of any
applicable federal plan that is ultimately promulgated. In the event a
federal plan is needed, proposing a necessary or appropriate finding at
this time will allow the EPA to expeditiously promulgate a final
federal plan for one or all of these power plants in the future to
allow trading to occur. We will continue to consult with the
governments of the Navajo Nation, Fort Mojave Indian Tribe, and the Ute
Tribe of the Uintah and Ouray Reservation during the comment period for
this proposal, and prior to taking any action to finalize a necessary
or appropriate finding and/or a federal plan. Comments on the
appropriateness of the proposed finding should be submitted within the
comment period specified in the DATES section of this preamble.
VII. Amendments To Process for Submittal and Approval of State Plans
and EPA Actions
As indicated in the final rulemaking action for the CAA section
111(d) guideline, ``Carbon Pollution Emission Guidelines for Existing
Stationary Sources: Electric Utility Generating Units,'' in this
action, in addition to the proposed federal plans and model trading
rules, the EPA is also proposing to amend the framework regulations and
update the process for acting on CAA section 111(d) state plans under
40 CFR part 60, subpart B. These changes would be applicable to any
future CAA section 111(d) rules going forward, not just the Clean Power
Plan EGs. The EPA proposes six changes to the CAA section 111(d)
process in the framework regulations to include: (1) Partial approval/
disapproval mechanisms similar to CAA section 110(k)(3); (2) a
conditional approval mechanism similar to CAA section 110(k)(4); (3) a
mechanism for the EPA to make calls for plan revisions similar to the
``SIP-call'' provisions of CAA section 110(k)(5); (4) an error
correction mechanism similar to CAA section 110(k)(6); (5) completeness
criteria and a process for determining completeness of state plans and
submittals similar to CAA section 110(k)(1) and (2); and (6) updates to
the deadlines for the EPA action. In addition, in this section, the
agency is proposing an interpretation regarding the effect under
section 111 if an existing facility subject to CAA section 111(d)
modifies or reconstructs. We believe these changes will significantly
streamline the state plan review and approval process, be more
respectful of state processes, and generally enhance the administration
of the CAA section 111(d) program.
CAA section 111(d)(1) provides that the EPA ``shall establish a
procedure similar to that provided by CAA section [110] of this title
under which each state shall submit to the Administrator a [111(d)]
plan. . . .'' 42 U.S.C. 7411(d)(1). Thus, the CAA directs the EPA to
look to the structure of the SIP program when designing the procedures
the states and agency will use to develop CAA section 111(d) plans.
Notably, the CAA does not require the CAA section 111(d) procedures to
be identical to those the EPA uses under
[[Page 65035]]
CAA section 110 for SIPs.\120\ Therefore, the EPA interprets CAA
section 111(d) to provide the EPA flexibility in designing procedures
that reflect the structure of those used under CAA section 110 for
implementation plans, without requiring the EPA to exactly track SIP
procedures when acting on section 111(d) plans.
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\120\ See Webster's II New Riverside University Dictionary
(Riverside 1988) (defining ``similar'' to mean ``resembling though
not completely identical'').
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As a general matter these proposed changes would simply update the
CAA section 111(d) framework regulations to include several new, more
flexible procedural tools that Congress introduced into section 110 in
the 1990 CAA Amendments. The basic procedures in the CAA section 111(d)
framework regulations were promulgated in 1975 based on the structure
of CAA section 110 as Congress designed it in the 1970 CAA. See 40 FR
53340-49 (November 17, 1975). Over the years since 1970, the EPA and
the states learned a great deal about the procedural limitations of the
original SIP review process. The 1970 CAA only allowed the EPA two
choices--to approve or disapprove SIP submittals. The agency struggled
to deal responsively to situations where the EPA wanted to work with
states to get state programs approved to the extent possible, while
maintaining consistency with CAA requirements. Congress responded in
1990 and enhanced the procedural mechanisms the EPA has to act on SIPs.
The EPA is proposing correspondingly to update the CAA section 111(d)
regulations in a similar fashion. Currently, the EPA's framework
regulations for submittal and adoption of CAA section 111(d) state
plans do not explicitly provide for the EPA to use some of the same
procedures for approving or disapproving state plans Congress
introduced into the SIP program in the 1990 CAA Amendments. The EPA is
proposing to amend the procedures for approval or disapproval of CAA
section 111(d) state plans to reflect the enhancements Congress
included in CAA section 110 for agency actions on SIPs. These proposed
amendments are discussed in more detail below.
A. Partial Approvals/Disapprovals
First, the EPA proposes to add authority similar to that under CAA
section 110(k)(3) to partially approve or disapprove a plan.\121\ This
is a particularly useful function when much of a state plan is
approvable and the EPA and the state cannot reach resolution on only a
small, severable portion of the state plan. In this case, the EPA
prefers not to be in a position where it must disapprove the full plan,
but rather to allow the state to move forward with those portions of
the plan that are approvable. This approach would also address those
situations where the state wishes to take over a discrete part of a
federal plan. For instance, in this proposal, states will be able to
seek approval of a partial state plan that will give them the ability
to handle the allocation of allowances under a mass-based federal plan.
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\121\ We recognize that the regulations appear to already
contemplate partial approval/disapprovals to some extent. See 40 CFR
60.27(a) (``The Administrator may . . . extend the period for
submission of any plan . . . or portion thereof.'') (emphasis
added). We note that this language only allows for extensions of
time with respect to portions of state plan submissions and may not
sufficiently authorize a permanent partial approval. The proposed
enhancement will resolve any ambiguity that partial approvals/
disapprovals are an acceptable mechanism under CAA section 111(d).
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In cases where elements of a plan are functionally severable from
each other, and one element is approvable while another is not, this
provision will authorize the EPA to approve one part of a plan and
disapprove the other. It will also authorize the EPA to accept and
review a state plan that is only partial in nature, if identified by
the state as such, so long as the other applicable submission
requirements are met (such as demonstration of legal authority and
completion of the public process). When the state submits what it
intends to be a full state plan (rather than just a partial plan), the
EPA proposes that the approvable portion of a plan must be functionally
severable from the rest of the plan. This will be the case when the
following conditions are met. First, the approvable portion of the plan
must not depend on the rest of the plan. In other words, the
disapproval of the remaining portion of the plan must not affect the
portion that is approved. Second, approval of the approvable portion
must not alter the function of the submittal in a way that is contrary
to the state's intent.
The partial disapproval would be a disapproval for the purposes of
CAA section 111(d)(2)(A) and would trigger the EPA's authority to issue
a federal plan for the state, at least for that part of the plan that
was disapproved. Incorporating this mechanism under the framework
regulations for CAA section 111(d) will enable the EPA to approve a
state to implement as much of its program as is consistent with a CAA
section 111(d) guideline and may reduce the scope of any federal plan
that would be necessary.
B. Conditional Approvals
The second mechanism is the authority under CAA section 110(k)(4)
to conditionally approve a plan. Where a state has submitted a plan
that substantially meets the requirements of a CAA section 111(d)
emission guideline, but requires some specific amendments to make it
fully approvable, this provision authorizes the EPA to conditionally
approve the plan. The Governor or his/her designee must submit to the
EPA a commitment that specifies the amendments to be adopted and
submitted to the EPA by no later than 1 year from the effective date of
the conditional approval. If the state fails to meet its commitment,
the conditional approval is treated as a disapproval. Incorporating
this mechanism under the framework regulations for CAA section 111(d)
will enable the EPA to approve a state to begin to administer a
substantially complete program that requires only specific changes to
be fully approvable. This provision is designed to authorize a state
with a substantially complete and approvable program to begin
implementing it, while promptly amending the program to ensure it fully
complies with CAA section 111(d).
C. Calls for Plan Revisions
CAA section 110(k)(5) authorizes the EPA to find that a SIP does
not comply with the requirements of the CAA. To date, the EPA has not
considered using a similar procedure pursuant to the authority under
CAA section 111(d). We now propose to do so. The ability to call for
plan revisions is fundamental to a program that will be implemented
over many years or multiple decades. Under the Clean Power Plan EGs,
states have more than a decade to fully implement emissions standards
or state measures in order to ensure affected EGUs achieve the emission
goals of the EGs. Throughout this period, the EPA and the states will
be monitoring their programs to ensure they are achieving the intended
results. It is possible that design assumptions about the effect of
control measures the states incorporate into their plans could prove
inaccurate in retrospect and could result over time in the plan not
meeting the emission reductions required by the EGs. In that case,
having a procedural mechanism available under CAA section 111(d)
similar to the so-called ``SIP call'' mechanism in CAA section
110(k)(5) will allow the agency to initiate a process with the state to
make necessary
[[Page 65036]]
revisions to ensure the plan functions properly.
Accordingly, the EPA is proposing to amend the framework
regulations to include a provision similar to CAA section 110(k)(5)
under which the EPA may find that a state's CAA section 111(d) plan is
substantially inadequate to comply with the requirements of the CAA and
require the state to revise the plan as necessary to correct such
inadequacies. Consistent with CAA section 110(k)(5), the EPA shall
notify the state of any inadequacies and establish a reasonable
deadline for the state to submit required plan revisions. That deadline
will not exceed 18 months after the date of the action. The EPA will
make its finding and notice to the state available to the public.\122\
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\122\ Consistent with the agency's practice under CAA section
110(k)(5), the EPA anticipates that a call for plan revisions under
CAA section 111(d) will be done via notice and comment rulemaking.
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The effect of such a finding is that either the state submits the
program corrections by the date the EPA sets in the document, or
pursuant to CAA section 111(d)(2)(A), the EPA has authority to issue a
federal plan for a state that misses its deadline to correct its plan.
In effect, the finding of plan inadequacy establishes a plan submittal
deadline subject to the provisions of CAA section 111(d)(2)(A). A
finding of failure to meet that new deadline triggers the EPA's
authority to issue a federal plan for the state. The EPA may promulgate
a federal plan at any time following the state's failure to timely
submit an adequate plan that addresses the EPA's finding.
While these authorities are important, the intention of having a
mechanism to call for plan revisions is to have a way to initiate an
orderly process to improve plans when they are not meeting program
objectives. It is the EPA's hope that a call for plan revision leads to
a constructive dialogue with a state or states, and ultimately, an
improved and more effective CAA section 111(d) plan.
The EPA is also proposing that the agency can call for a plan
revision in circumstances where a state is not implementing its
approved state plan and, therefore, the state plan is substantially
inadequate to provide for the implementation of CAA section 111(d)
standards of performance. As discussed above, the CAA directs the EPA
to develop a procedure for state plans under CAA section 111(d) similar
to CAA section 110 SIP procedures. Calling a plan that is substantially
inadequate to provide for implementation of standards of performance
(i.e., there is a failure to implement a state plan) is one area where
the EPA proposes it is appropriate to adapt the procedural mechanisms
available in the SIP program to provide a similar process that assures
effective state plan implementation under CAA section 111(d). Under CAA
section 110(k)(5), the EPA may call for a revision of a state plan
``[w]henever the Administrator finds that the . . . plan . . . is
substantially inadequate to . . . comply with any requirement of [the
Act].'' If the state does not submit a plan revision in response to the
call to cure the failure to provide for implementation, the EPA would
have the authority to promulgate the federal plan being proposed.
One critical requirement of CAA section 111(d)(1)(B) is that a
state must submit a plan that ``provides for the implementation and
enforcement of such standards of performance'' (emphasis added). If,
after the EPA has approved a plan, a state fails to implement that
plan, the plan has become substantially inadequate to comply with this
requirement of the CAA. Under this proposal, the EPA's remedy would be
to find the plan is substantially inadequate, which triggers the
state's obligation to cure, and failing that, the EPA's authority to
promulgate the federal plan.
In the alternative, the EPA proposes that this authority to call a
plan for failure to implement is anchored in the authority provided
under CAA section 110(k)(5) to call a SIP when the agency finds that it
is ``substantially inadequate to attain or maintain the relevant
national ambient air quality standard.'' In the context of CAA section
111, this authority translates into the EPA calling a state plan when
the agency finds that it is substantially inadequate to achieve the
emission reductions required under the EGs. If a state has failed to
implement its plan, and that failure is pervasive enough to render the
requirements of the plan ineffective, it is reasonable for the EPA to
find that the state plan is substantially inadequate to achieve the
emission reductions required under the EGs. The state's failure to
implement has revised the effect of the plan so that it is no longer
adequate to meet the CAA's requirements.
D. Error Corrections
The fourth mechanism is the error correction authority under CAA
section 110(k)(6). Where the EPA concludes that it has erroneously
approved, disapproved, or promulgated a plan or plan revision (or part
thereof), this section authorizes the agency to revise its action, in
the same manner as the original action, without requiring any further
submission from the state. Prior to the 1990 CAA Amendments, there was
some question whether the EPA could unilaterally correct a previous
action on a SIP submittal without the state having to submit a new SIP.
This limitation imposed unnecessary burdens on states to fix even
obvious errors, because CAA section 110(a)(2) requires the state to
provide notice and a public hearing on each new SIP submittal.
Incorporating this mechanism into the CAA section 111(d) framework
regulations will allow the EPA to fix errors in its prior actions on
state plans without imposing on the states the corresponding burden of
providing notice and a public hearing as required under the CAA section
111(d) framework regulations. See 40 CFR 60.23.
E. Completeness Criteria
Completeness criteria provide the agency with a means to determine
whether a submission by a state includes the minimum elements that must
be met before the EPA is required to act on such submission. When
submittals do not contain the necessary minimum elements, then the EPA
may, without further action, find that a state has failed to submit a
plan. This determination is ministerial in nature and requires no
exercise of discretion or judgment on the agency's part, nor does it
reflect a judgment on the sufficiency or adequacy of the submitted
portions of a state plan. The task is accomplished by simply comparing
the materials provided by the state as its submittal against the
required criteria to determine whether the plan is complete or not. In
the case of SIPs under CAA section 110(k)(1), the EPA promulgated
completeness criteria in 1990 at Appendix V to 40 CFR part 51 (55 FR
5830; February 16, 1990). The EPA proposes to adopt criteria similar to
the criteria set out at section 2.0 of Appendix V for determining the
completeness of submissions under CAA section 111(d). The completeness
criteria can be grouped into: (1) Administrative materials; and (2)
technical support. The EPA proposes that both groups would apply to all
CAA section 111(d) rules going forward. The agency notes that the
addition of completeness criteria in the framework regulations does not
alter any of the submission requirements states already have under the
EGs.
For administrative materials, the EPA is proposing completeness
criteria that mirror the existing administrative criteria for SIP
submittals because the two programs have similar
[[Page 65037]]
administrative processes. The EPA proposes that a complete final state
plan submittal under CAA section 111(d) must include: (1) A formal
letter of submittal from the Governor or his/her designee requesting
EPA approval of the plan or revision thereof; (2) evidence that the
state has adopted the plan in the state code or body of regulations
(That evidence must include the date of adoption or final issuance as
well as the effective date of the plan, if different from the adoption/
issuance date.); (3) evidence that the state has the necessary legal
authority under state law to adopt and implement the plan; (4) a copy
of the actual regulation, or document submitted for approval and
incorporation by reference into the plan. The submittal must be a copy
of the official state regulation/document signed, stamped and dated by
the appropriate state official indicating that it is fully enforceable
by the state (The effective date of the regulation/document must,
whenever possible, be indicated in the document itself. The state's
electronic copy must be an exact duplicate of the hard copy. For
revisions to the approved plan, the submittal must indicate the changes
made (for example, by redline/strikethrough) to the approved plan.);
(5) evidence that the state followed all of the procedural requirements
of the state's laws and constitution in conducting and completing the
adoption/issuance of the plan; (6) evidence that public notice was
given of the proposed change with procedures consistent with the
requirements of 40 CFR 60.23, including the date of publication of such
notice; (7) certification that public hearing(s) were held in
accordance with the information provided in the public notice and the
state's laws and constitution, if applicable and consistent with the
public hearing requirements in 40 CFR 60.23; and (8) compilation of
public comments and the state's response thereto.
These criteria, as proposed, are intended to be generic to all CAA
section 111(d) plans going forward, with the proviso that specific EGs
may provide otherwise. The technical support completeness criteria that
the EPA proposes will also be generic to all CAA section 111(d) rules,
with the same proviso. The EPA proposes that the technical support
required for all plans must include each of the following: (1)
Description of the plan approach and geographic scope; (2)
identification of each designated facility, identification of emission
standards for each designated facility, and monitoring, recordkeeping,
and reporting requirements that will determine compliance by each
designated facility; (3) identification of compliance schedules and/or
increments of progress; (4) demonstration that the state plan submittal
is projected to achieve emissions performance under the applicable EGs;
(5) documentation of state recordkeeping and reporting requirements to
determine the performance of the plan as a whole; and (6) demonstration
that each emission standard is quantifiable, non-duplicative,
permanent, verifiable, and enforceable.
The EPA proposes a process similar, though not identical, to that
set forth in 40 CFR 51.103 and Appendix V to 40 CFR part 51 to make
completeness determinations. Similar to CAA section 110(k)(1)(C), under
this proposal, where the EPA determines that a state submission
required under CAA section 111(d) does not meet the minimum
completeness criteria we are proposing to establish, the state will be
considered to have not made the submission. The EPA further proposes
that, similar to CAA section 110(k)(1)(B), within 60 days of the EPA's
receipt of a state submission, but no later than 6 months after the
date, if any, by which a state is required to submit the plan or
revision, the Administrator shall determine whether the minimum
criteria have been met. Any plan or plan revision that a state submits
to the EPA, and that has not been determined by the EPA by the date 6
months after receipt of the submission to have failed to meet the
minimum criteria, shall on that date be deemed by operation of law to
meet such minimum criteria. In cases where a state does not submit
anything to the agency, however, the Administrator must make a finding
of failure to submit no later than 6 months after the date, if any, by
which a state is required to submit the plan or revision. (In other
words, ``completeness by operation of law'' is only available where the
state has actually submitted a plan to the agency.)
As with the completeness determination process for SIP submissions,
the EPA's determination that a submittal is complete is not a finding
that the submittal meets the substantive requirements of CAA section
111(d) or the guideline. That must be done via the process for approval
or disapproval of a state plan, which would be done through notice and
comment rulemaking. In the completeness process, the EPA will confirm
that a state's submittal appears to have addressed the criteria for a
complete submittal and, therefore, the submittal is sufficient to
trigger the EPA's obligation to act on it. But in the completeness
process the agency will not assess the content of those submissions to
determine if they are approvable. Accordingly, even when the EPA
affirmatively determines that a submittal is complete, it does not
prevent the agency from later finding that the state plan does not meet
the requirements of the EGs, including finding that the submittal
failed to address a required element and must be disapproved.
Similarly, when a submittal is determined to be complete by
operation of law after 6 months without the EPA's affirmative
determination of completeness, the only legal consequence is that the
EPA now has an obligation to act on that submittal. Completeness by
operation of law means that the submittal is deemed complete and
requires the EPA's review, whether or not the state has actually
addressed all the required elements. Accordingly, if the agency
determines that a state has failed to address a required element in its
submittal once the EPA begins review of the state plan that is complete
by operation of law, the agency must go through the process of
disapproving (or partially disapproving or conditionally approving, as
discussed below) that plan, unless the state and the EPA work together
to cure the deficiency. In other words, the EPA cannot simply find the
plan incomplete and return it to the state at that point. But the
finding of completeness by operation of law in no way prevents the EPA
from subsequently concluding that the state's submission is missing a
required element of the program and making that finding as part of a
disapproval of the plan.
As described in the final rulemaking action for the CAA section
111(d) EGs, a state will submit all CAA section 111(d) plans
electronically. If the EPA determines that any submission fails to meet
the completeness criteria, the agency may return the plan to the state
and request corrections, identifying the components that are absent or
insufficient to allow the EPA to perform a review of the plan. The
state will not have met its obligation to submit a final plan until it
resubmits a revised state plan or supporting materials addressing the
corrections the EPA identified in its incompleteness determination.
The EPA is also proposing to include an exception to the criteria
for complete administrative materials in cases where a state and the
EPA are ``parallel processing'' the final plan. Parallel processing
allows a state to submit the plan prior to final adoption by the state
and provides an opportunity for the
[[Page 65038]]
state to consider the EPA's comments prior to submission of a final
plan for final review and action. The EPA would propose to take action
on a state plan based on a proposed state regulation. The EPA would
only finalize the action if the state adopts a final plan that is
legally effective under state law. The EPA would only approve the plan
if the state addressed any corrections that the EPA identified in its
proposed action on the state plan without any other material change to
the plan. Note that a plan submitted for parallel processing must still
meet all the criteria for technical completeness so that the EPA and
the public have a sufficient basis on which to evaluate and comment on
the EPA's proposed action.
F. Update to Deadlines for EPA Actions
The EPA proposes to update the deadlines for acting on state
submittals and promulgating a federal plan under 40 CFR 60.27(b), (c),
and (d) to more closely track the current versions of CAA sections
110(c) and 110(k) adopted in 1990. The framework regulations for CAA
section 111(d) state plans currently are parallel to the prior version
of CAA section 110. They require the EPA to act on a state plan or plan
revision submittal within 4 months after the date required for
submission of a plan or plan revision. See 40 CFR 60.27(b). The
regulations then require the EPA to issue a proposed federal plan in
certain circumstances after consideration of any state hearing record,
see 40 CFR 60.27(c), and require the EPA to promulgate the proposed
federal plan within 6 months after the date required for plan
submissions, see 40 CFR 60.27(d).
The final CO2 EGs for affected EGUs have already
adjusted the deadline in 40 CFR 60.27(b) to require the EPA to act on a
state plan under those EGs within 12 months (rather than 4 months)
after the date required for submission of a plan. See 40 CFR 60.5715.
However, the Clean Power Plan EGs did not modify the 6-month deadline
for a federal plan in 40 CFR 60.27(d).
The EPA is proposing to amend 40 CFR 60.27(b) to allow the EPA 12
months to approve or disapprove submittals of all plans or plan
revisions under CAA section 111(d), not just those related to the Clean
Power Plan under 40 CFR 60.5715. This change would provide the EPA with
sufficient time for the steps required to approve or disapprove the
submittal, which include proposing the EPA's approval or disapproval of
the plan or plan revision, a public comment period on the EPA's
proposal, time for the EPA to review and respond to public comments,
and the issuance of a final rule approving or disapproving the plan or
plan revision.
The EPA is also proposing to amend 40 CFR 60.27(b) to specify that
the deadline for the EPA to act on a plan or plan revision is 12 months
after receipt of a complete plan or plan revision, rather than 12
months after the deadline for submittal of a plan or plan revision.
This amendment will allow the EPA to have the full 12 months to act on
submittals of complete plans or plan revisions.
The EPA also proposes slight modifications to the provision related
to issuing a proposed federal plan in 40 CFR 60.27(c); changing the 6-
month deadline for issuing a final federal plan in 40 CFR 60.27(d) to 1
year; \123\ and, similar to the change in timing for 40 CFR 60.27(b)
above, setting the deadline for promulgation of a federal plan to run
from the date of the EPA's action on a state submittal, rather than
from the original deadline for a state submittal.
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\123\ As under CAA section 110, the EPA believes that, should it
fail for whatever reason to meet a deadline by which it was to take
action, such as issue a federal plan, under CAA section 111(d), that
failure does not thereby obviate or in any way remove the EPA's
authority or obligation to take that action. See Oklahoma v. U.S.
EPA, 723 F.3d 1201, 1224 (10th Cir. 2013) (``Although the statute
undoubtedly requires that the EPA promulgate a FIP within two years,
it does not stand to reason that it loses its ability to do so after
this two-year period expires. Rather, the appropriate remedy when
the EPA violates the statute is an order compelling agency
action.'').
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The EPA believes it is appropriate to modify these timing
requirements for several reasons. First, the EPA notes that under CAA
section 111(d)(2), Congress gave the EPA the ``same'' authority to
prescribe a federal plan under CAA section 111(d) as it would have
under CAA section 110(c) in the case of a state failure to submit a
SIP. The term ``same'' stands in contrast to the term ``similar'' in
CAA section 111(d)(1) (discussed above). As with the use of the term
``similar,'' the EPA believes it is authorized by this language to
follow the timing provisions of CAA section 110(c) as currently
enacted. Second, as a general matter, the timing requirements of
current 40 CFR 60.27(c) and (d), which effectively require the EPA to
propose and finalize a federal plan within 6 months of the deadline for
state submittals, may be outdated and unrealistic with respect to the
timelines for review of state plans and the time periods for action,
particularly as informed by the agency's experience with CAA section
110 SIPs (which led to the extension of the timelines and other changes
to CAA section 110 in the 1990 Amendments discussed above). Third, in
the Clean Power Plan EGs, the EPA has finalized a timing requirement
that gives the agency a year to approve or disapprove a state plan or
revision. The existing requirement in 40 CFR 60.27(d) that the EPA must
promulgate a federal plan within 6 months of the initial deadline for
state plans is therefore inconsistent with this provision. Fourth,
existing 40 CFR 60.27(c) tracks the prior version of CAA section 110(c)
with respect to the issuance of a proposed federal plan. This
relatively prescriptive language is no longer present in CAA section
110(c). The procedural requirements for rulemakings under both CAA
section 110 and 111(d) are set out in section 307(d) of the CAA, and
the EPA believes those provisions are appropriate and adequate to guide
its rulemaking process for CAA section 111(d) federal plans.
The EPA invites comment on all of these proposed changes to the
framework regulations. The EPA notes that the addition of these
mechanisms to the framework regulations will make them available for
all CAA section 111(d) regulations, not just those under the Clean
Power Plan at 40 CFR part 60, subpart UUUU.
G. Proposed Interpretation Regarding Existing Sources That Modify or
Reconstruct
In the proposed rulemaking for the Clean Power Plan, the EPA
proposed the interpretation that if an existing source is subject to a
CAA section 111(d) state plan, and then undertakes a modification or
reconstruction, the source remains subject to the state plan, while
also becoming subject to the modification or reconstruction
requirements. See 79 FR 34830, 34903-4 (June 18, 2014). The EPA did not
finalize a position on this issue in the final EGs rule, but indicated
that it would re-propose and request comment on this issue through this
federal plan rulemaking. The EPA also stated deferral of action on this
issue does not impact states' and affected EGUs' pending obligations
under the final Emission Guidelines relating to plan submission
deadlines, as this issue concerns potential obligations or impacts
after an existing source has already become subject to the requirements
of a state plan. The EPA intends to finalize its position on this issue
through this rulemaking, which will be well in advance of the plan
performance period beginning in 2022, at which point state plan
obligations on existing sources are effectuated.
We noted in the Clean Power Plan proposal that CAA section 111(d)
is arguably silent as to this issue. Thus, we
[[Page 65039]]
took this to grant the agency the authority to provide a reasonable
interpretation to fill in the gaps where the statute is silent. In the
proposal for the Clean Power Plan, we proposed to disallow existing
sources to leave the CAA section 111(d) program through modification or
reconstruction. We did this for two reasons. First, if a source did so,
that could prove disruptive to the state plan. Second, allowing sources
to do so could provide them an incentive that would be contrary to the
purposes of CAA section 111(d). We then asked for comment on ``whether
this interpretation is supported by the statutory text and whether this
interpretation is sensible policy and will further the goals of the
statute.''
We received many comments disagreeing with this approach. After
reviewing these comments, the agency believes an alternative
interpretation is more appropriate in the particular context here. In
order to give the public an opportunity to comment on this, we are
proposing this interpretation here. That is, when CAA section 111(d)
EGs are initially promulgated for existing stationary sources in
response to corresponding CAA section 111(b) standards of performance
for the same pollutant, the statute prevents new, modified, or
reconstructed sources (including under those particular CAA section
111(b) standards of performance and as those terms are applied in the
relevant new source performance standards (NSPS)) from simultaneously
being subject to state plans under those particular CAA section 111(d)
EGs. This interpretation gives meaning to the definition of ``existing
source'' in CAA section 111(a)(6) and is consistent with the definition
of ``new source'' in CAA section 111(a)(2). Further, it is consistent
with the historical treatment of modified and reconstructed sources in
the CAA section 111 program.
The EPA notes the concerns it noted in the proposal supporting why
the originally proposed interpretation was reasonable are being
addressed in other ways in the final EGs, and in the proposed federal
plan. In other words, there will be other ways to minimize disruption
to state plans if such a modification or reconstruction were to take
place. We invite comment on the agency's proposed interpretation that
when an existing source modifies or reconstructs in such a way that it
meets the definition of a new source, for purposes of a particular NSPS
and emission guideline, it becomes a new source under the statute and
is no longer subject to the CAA section 111(d) program
H. Separate Finalization of These Changes
The agency intends to finalize these procedural changes and
interpretation sooner than it finalizes the rest of this proposed
action. The EPA believes these changes generally enhance and improve
the framework regulations in a way that will be of benefit to the
states, the EPA, and other stakeholders, and will improve the overall
efficacy of the program. We believe it is important to finalize these
changes to the framework regulations relatively quickly in order to
provide states and other stakeholders predictability in how the EPA
intends to process state plans and submissions under CAA section
111(d). If the EPA does finalize these changes sooner than the model
trading rules or the federal plan, it will do so after the close of the
comment period, and after consideration and response to any comments on
these changes.
VIII. Impacts of This Action
A. Endangered Species Act
Consistent with the requirements of section 7(a)(2) of the
Endangered Species Act (ESA), the EPA has considered the effects of
this proposed rule and has reviewed applicable ESA regulations, case
law, and guidance to determine what, if any, impact there may be to
listed endangered or threatened species or designated critical habitat.
Section 7(a)(2) of the ESA requires federal agencies, in consultation
with the U.S. Fish and Wildlife Service (FWS) and/or the National
Marine Fisheries Service, to ensure that actions they authorize, fund,
or carry out are not likely to jeopardize the continued existence of
federally listed endangered or threatened species or result in the
destruction or adverse modification of designated critical habitat of
such species. See 16 U.S.C. 1536(a)(2). Under relevant implementing
regulations, ESA section 7(a)(2) applies only to actions where there is
discretionary federal involvement or control. See 50 CFR 402.03.
Further, under the regulations consultation is required only for
actions that ``may affect'' listed species or designated critical
habitat. See 50 CFR 402.14. Consultation is not required where the
action has no effect on such species or habitat. Under this standard,
it is the federal agency taking the action that evaluates the action
and determines whether consultation is required. See 51 FR 19926, 19949
(June 3, 1986). Effects of an action include both the direct and
indirect effects that will be added to the environmental baseline. See
50 CFR 402.02. Direct effects are the direct or immediate effects of an
action on a listed species or its habitat.\124\ Indirect effects are
those that are caused by the action, later in time, and are reasonably
certain to occur. Id. To trigger a consultation requirement, there must
thus be a causal connection between the federal action, the effect in
question, and if the effect is indirect, it must be reasonably certain
to occur.
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\124\ See Endangered Species Consultation Handbook, U.S. Fish &
Wildlife Service and National Marine Fisheries Service at 4-25
(March 1998) (providing examples of direct effects: e.g., driving an
off road vehicle through the nesting habitat of a listed species of
bird and destroying a ground nest; building a housing unit and
destroying the habitat of a listed species).
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The EPA has considered the effects of this proposed rule and has
reviewed applicable ESA regulations, case law, and guidance to
determine what, if any, impact there may be to listed species or
designated critical habitat for purposes of ESA section 7(a)(2)
consultation. The EPA notes that the projected environmental effects of
this proposal are, like the EGs that it implements, positive:
Reductions in overall GHG emissions, and reductions in PM and ozone-
precursor emissions (sulfur oxides and NOX), for EGUs that
will be covered by the federal plan. However, the EPA's assessment that
the rule will have an overall net positive environmental effect by
virtue of reducing emissions of certain air pollutants does not address
whether the rule may affect any listed species or designated critical
habitat for ESA section 7(a)(2) purposes and does not constitute any
finding of effects for that purpose. The fact that the rule will have
overall positive effects on the national and global environment does
not mean that the rule may affect any listed species in its habitat or
the designated critical habitat of such species within the meaning of
ESA section 7(a)(2) or the implementing regulations or require ESA
consultation. The EPA has considered various types of potential effects
in considering whether ESA consultation is required for this rule.
With respect to the projected GHG emission reductions, the EPA does
not believe that such reductions trigger ESA consultation requirements
under ESA section 7(a)(2). In reaching this conclusion, the EPA is
mindful of significant legal and technical analysis undertaken by FWS
and the U.S. Department of the Interior (DOI) in the context of listing
the polar bear as a threatened species under the ESA. In that context,
in 2008, FWS and DOI expressed the view that the best scientific data
available were insufficient to draw a causal connection
[[Page 65040]]
between GHG emissions and effects on the species in its habitat.\125\
The DOI Solicitor concluded that where the effect at issue is climate
change, proposed actions involving GHG emissions cannot pass the ``may
affect'' test of the ESA section 7 regulations and, thus, are not
subject to ESA consultation.
---------------------------------------------------------------------------
\125\ See, e.g., 73 FR 28212, 28300 (May 15, 2008); Memorandum
from David Longly Bernhardt, Solicitor, U.S. Department of the
Interior re: ``Guidance on the Applicability of the Endangered
Species Act's Consultation Requirements to Proposed Actions
Involving the Emission of Greenhouse Gases'' (October 3, 2008).
---------------------------------------------------------------------------
The EPA has also previously considered issues relating to GHG
emissions in connection with the requirements of ESA section 7(a)(2).
In the final EGs, the agency noted that, although the GHG emission
reductions projected for the EGs are large (estimated reductions of
about 415 million short tons of CO2 in 2030 relative to the
base case), the EPA evaluated larger reductions in assessing this same
issue in the context of the light duty vehicle GHG emission standards
for model years 2012-2016 and 2017-2025. There the agency projected
emission reductions over the lifetimes of the model years in
question,\126\ which are roughly five to six times those projected
above and, based on air quality modeling of potential environmental
effects, concluded that ``EPA knows of no modeling tool which can link
these small, time-attenuated changes in global metrics to particular
effects on listed species in particular areas. Extrapolating from
global metric to local effect with such small numbers, and accounting
for further links in a causative chain, remain beyond current modeling
capabilities.'' EPA, Light Duty Vehicle Greenhouse Gas Standards and
Corporate Average Fuel Economy Standards, Response to Comment Document
for Joint Rulemaking at 4-102 (Docket EPA-OAR-HQ-2009-4782). The EPA
reached this conclusion after evaluating issues relating to potential
improvements from the fuel efficiency rule relevant to both temperature
and oceanographic pH outputs. The EPA's ultimate finding was that ``any
potential for a specific impact [of the specific federal action] on
listed species in their habitats associated with these very small
changes in average global temperature and ocean pH is too remote to
trigger the threshold for ESA section 7(a)(2).'' Id. See also, e.g.,
Ground Zero Center for Non-Violent Action v. U.S. Dept. of Navy, 383 F.
3d 1082, 1091-92 (9th Cir. 2004). The EPA similarly proposes to
determine that the likelihood of jeopardy to a species from this
proposed action is extremely remote, and ESA does not require
consultation. The EPA's proposed conclusion is entirely consistent with
DOI's analysis regarding ESA requirements in the context of federal
actions involving GHG emissions.
---------------------------------------------------------------------------
\126\ See 75 FR 25438 Table I.C 2-4 (May 7, 2010); 77 FR at
62894 Table III-68 (October 15, 2012).
---------------------------------------------------------------------------
With regard to non-GHG air emissions, the EPA is also projecting
substantial reductions of SO2 and NOX as a
collateral consequence of this proposal (which will be, as stated
above, only a subset of the total reductions from the EGs). However,
CAA section 111(d) cannot directly control emissions of criteria
pollutants. And furthermore, a federal plan under CAA section 111(d)(2)
does no more than prescribe emissions standards of the same stringency
as the corresponding EGs. See 40 CFR 60.27(e)(1). Consequently, CAA
section 111(d) provides no discretion to set a standard in a federal
plan based on potential impacts to endangered species of reduced
criteria pollutant emissions. ESA section 7(a)(2) consultation is not
required with respect to the projected reductions of criteria pollutant
emissions. See 50 CFR 402.03; see also WildEarth Guardians v. U.S.
Envt'l Protection Agency, 759 F.3d 1196, 1207-10 (10th Cir. 2014) (the
EPA has no duty to consult under section 7 of the ESA regarding HAP
controls that it did not require--and likely lacked authority to
require--in a FIP for regional haze controls under section 169A of the
CAA.).
Finally, the EPA has also considered other potential effects of the
rule (beyond reductions in air pollutants) and whether any such effects
are ``caused by'' the rule and ``reasonably certain to occur'' within
the meaning of the ESA regulatory definition of the effects of an
action. See 50 CFR 402.02. The EPA recognizes, for instance, that
questions may exist whether decisions such as increased utilization of
solar or wind power could have effects on listed species. The EPA
received comments on the EGs asserting that because potential increased
reliance on wind or solar power may be an element of Building Block 3,
and because wind and solar facilities may in some cases have effects on
listed species, the EPA must consult under the ESA on this aspect of
the rule.
The EPA has carefully considered the comments and the
correspondence from Congress as well as the case law and other
materials cited in those documents. The EPA does not believe that the
effects of potential future changes in the energy sector--including
increased reliance on wind or solar power as a result of future
potential actions by states or other implementing entities--or any
potential alterations in the operations of any particular facility
would, at the time of promulgation of a federal plan, be sufficiently
certain to occur so as to require ESA consultation on the rule. The EPA
appreciates that the ESA regulations call for consultation where
actions authorized, funded, or carried out by federal agencies may have
indirect effects on listed species or designated critical habitat.
However, as noted above, indirect effects must be caused by the action
at issue and must be reasonably certain to occur.
Under a federal plan, it is the EPA that would implement a CAA
section 111(d) plan. The EPA believes that even with this proposed
federal plan, any effects on listed species or designated habitat are
too uncertain to require consultation under ESA section 7. This is so
for at least two reasons: (1) The EPA cannot know with any certainty at
this stage which states will actually become subject to a finally
promulgated federal plan. Which affected EGUs, in which states, will be
covered by this plan can only be known after states have failed to
submit a plan, or have had their plans disapproved by the EPA; and (2)
the federal plan as proposed will be implemented through some form of
emissions trading. Emissions trading inherently provides maximum
flexibility to individual affected EGUs to choose their method of
compliance, including continuing to emit the relevant pollutant at
historical rates so long as the affected EGU holds sufficient credits
or allowances. At this point, the EPA has no meaningful information to
express in any more than the broadest terms how any particular affected
EGU may choose to comply with the federal plan, should it be
promulgated for them based on their location in an area not covered by
an approved state plan. The Services have explained that ESA section
7(a)(2) was not intended to preclude federal actions based on potential
future speculative effects.\127\
[[Page 65041]]
These are precisely the types of speculative future activities and
effects currently at issue here. The EPA requests comment on its
proposed conclusion that ESA section 7 consultation is not required for
this action. The EPA will continue to evaluate the scope and potential
effects of federal planning activities for this source category to the
extent federal plans are needed and implemented in specific areas and
over specific sources.
---------------------------------------------------------------------------
\127\ See 51 FR 19933 (describing effects that are ``reasonably
certain to occur'' in the context of consideration of cumulative
effects and distinguishing broader consideration that may be
appropriate in applying a procedural statute such as the National
Environmental Policy Act, as opposed to a substantive provision such
as ESA section 7(a)(2) that may prohibit certain federal actions);
Endangered Species Consultation Handbook, U.S. Fish & Wildlife
Service and National Marine Fisheries Service at 4-30 (March 1998)
(in the same context, describing indicators that an activity is
reasonably certain to occur as including governmental approvals of
the action or indications that such approval is imminent, project
sponsors' assurance that the action will proceed, obligation of
venture capital, or initiation of contracts; and noting that the
more governmental administrative discretion remains to be exercised,
the less there is reasonable certainty the action will proceed).
---------------------------------------------------------------------------
B. What are the air impacts?
The EPA anticipates significant emission reductions under this
proposed action for the utility power sector. Specifically, the EPA is
proposing approaches in the form of mass- and rate-based trading
options that provide flexibility in implementing emission standards for
a state's affected EGUs. Both proposed approaches to the federal plan
would require affected EGUs to meet emission standards set using the
CO2 emission performance rates in the Clean Power Plan EGs.
However, at the time of this proposal, the EPA has no information
on whether any or how many states will require a federal plan or will
adopt a model rule. Because of this lack of information, in the
Regulatory Impact Analysis (RIA) for this proposal, the EPA chose to
examine a scenario where all states of the contiguous United States
will be regulated under a federal plan or will adopt the model rule.
Additionally, we examine two alternative federal plan approach
scenarios. The first federal plan approach assumes all states in the
contiguous United States are regulated under a rate-based federal plan.
The second federal plan approach assumes all contiguous states are
regulated under a mass-based federal plan.\128\
---------------------------------------------------------------------------
\128\ It is important to note that the differences between the
analytical results for the rate-based and mass-based federal plan
approaches presented may not be indicative of likely differences
between the approaches. If one approach performs differently than
the other on a given metric during a given time period, this does
not imply this will apply in all instances.
---------------------------------------------------------------------------
Under the rate-based approach, when compared to 2005,
CO2 emissions are projected to be reduced by approximately
22 percent in 2020, 28 percent in 2025, and 32 percent in 2030. Under
the mass-based approach, when compared to 2005, CO2
emissions are projected to be reduced by approximately 23 percent in
2020, 29 percent in 2025, and 32 percent in 2030. The proposal is
projected to result in substantial co-benefits through reductions of
SO2, NOX, and PM2.5 that will have
direct public health benefits by lowering ambient levels of these
pollutants and ozone. Table 12 and Table 13 of this preamble show
expected CO2 and other air pollutant emissions in the base
case and reductions under the proposal for 2020, 2025, and 2030 for
both rate-based and mass-based approaches.
Table 12--Summary of CO2 and Other Air Pollutant Emission Reductions From the Base Case Under Rate-Based Federal
Plan Approach
----------------------------------------------------------------------------------------------------------------
CO2 (million SO2 (thousand NOX (thousand
short tons) short tons) short tons)
----------------------------------------------------------------------------------------------------------------
2020
----------------------------------------------------------------------------------------------------------------
Base Case....................................................... 2,155 1,311 1,333
Rate-based Federal Plan Approach................................ 2,085 1,297 1,282
Emission Reductions............................................. 69 14 50
----------------------------------------------------------------------------------------------------------------
2025
----------------------------------------------------------------------------------------------------------------
Base Case....................................................... 2,165 1,275 1,302
Rate-based Federal Plan Approach................................ 1,933 1,097 1,138
Emission Reductions............................................. 232 178 165
----------------------------------------------------------------------------------------------------------------
2030
----------------------------------------------------------------------------------------------------------------
Base Case....................................................... 2,227 1,314 1,293
Rate-based Federal Plan Approach................................ 1,812 996 1,011
Emission Reductions............................................. 415 318 282
----------------------------------------------------------------------------------------------------------------
Source: Integrated Planning Model, 2015.
Note: Emissions may not sum due to rounding.
Table 13--Summary of CO2 and Other Air Pollutant Emission Reductions From the Base Case Under Mass-Based Federal
Plan Approach
----------------------------------------------------------------------------------------------------------------
CO2 (million SO2 (thousand NOX (thousand
short tons) short tons) short tons)
----------------------------------------------------------------------------------------------------------------
2020
----------------------------------------------------------------------------------------------------------------
Base Case....................................................... 2,155 1,311 1,333
Mass-based Federal Plan Approach................................ 2,073 1,257 1,272
Emission Reductions............................................. 81 54 60
----------------------------------------------------------------------------------------------------------------
2025
----------------------------------------------------------------------------------------------------------------
Base Case....................................................... 2,165 1,275 1,302
Mass-based Federal Plan Approach................................ 1,901 1,090 1,100
[[Page 65042]]
Emission Reductions............................................. 265 185 203
----------------------------------------------------------------------------------------------------------------
2030
----------------------------------------------------------------------------------------------------------------
Base Case....................................................... 2,227 1,314 1,293
Mass-based Federal Plan Approach................................ 1,814 1,034 1,015
Emission Reductions............................................. 413 280 278
----------------------------------------------------------------------------------------------------------------
Source: Integrated Planning Model, 2015.
Note: Emissions may not sum due to rounding.
The reductions in Tables 12 and 13 of this preamble do not account
for reductions in HAP that may occur as a result of this rule. For
instance, the fine particulate reductions presented above do not
reflect all of the reductions in many heavy metal particulates.
C. What are the energy impacts?
The proposed action may have important energy market implications.
Table 14 of this preamble presents a variety of important energy market
impacts for 2020, 2025, and 2030 under both the rate-based and mass-
based federal plan approaches described in section VIII.B of this
preamble and presented in the RIA for this proposal.
Table 14--Summary Table of Important Energy Market Impacts for Rate-Based and Mass-Based Federal Plan Approaches
[Percent change from base case]
----------------------------------------------------------------------------------------------------------------
Rate-Based Mass-Based
-----------------------------------------------------
2020 2025 2030 2020 2025 2030
----------------------------------------------------------------------------------------------------------------
Retail electricity prices................................. 3% 1% 1% 3% 2% 0%
Average electricity bills................................. 3 -4 -7 2 -3 -8
Price of coal at minemouth................................ -1 -5 -4 -1 -5 -3
Coal production for power sector use...................... -5 -14 -25 -7 -17 -24
Price of natural gas delivered to power sector............ 5 -8 2 4 -3 -2
Natural gas use for electricity generation................ 3 -1 -1 5 0 -4
----------------------------------------------------------------------------------------------------------------
These figures reflect the EPA's modeling that presumes policies
that lead to generation shifts and growing use of DS-EE and renewable
electricity generation out to 2029. If different implementation choices
are made than those modeled, impacts could be different.
D. What are the compliance costs?
The compliance costs of this proposed action are represented in
this analysis as the change in electric power generation costs between
the base case and modeled federal plan approaches described in section
VIII.B of this preamble and presented in the RIA for this proposal. The
incremental cost is the projected additional cost of complying with the
proposed action in the year analyzed and includes the amortized cost of
capital investment, needed new capacity, shifts between or among
various fuels, deployment of DS-EE programs, and other actions
associated with compliance. These important dynamics are discussed in
more detail in the RIA in the rulemaking docket.
The EPA estimates the annual incremental compliance cost for the
rate-based federal plan approach to be $2.5 billion in 2020, $1.0
billion in 2025 and $8.4 billion in 2030. The EPA estimates the annual
incremental compliance cost for the mass-based federal plan approach to
be $1.4 billion in 2020, $3.0 billion in 2025, and $5.1 billion in
2030. More detailed cost estimates are available in the RIA in the
rulemaking docket.
E. What are the economic and employment impacts?
Based on the analysis presented in the RIA, the proposed action is
projected to result in certain changes to power system operation as a
compliance approach with the standards. See Table 14 of this preamble
for a variety of important energy market impacts for 2020, 2025, and
2030 under both the rate-based and mass-based federal plan approaches
described in Section VIII.B of this preamble and presented in the RIA
for this proposal.
Changes in price or demand for electricity, natural gas, and coal
can impact markets for goods and services produced by sectors that use
these energy inputs in the production process or supply those sectors.
Changes in the cost of production may result in changes in prices,
quantities produced, and profitability of affected firms. The EPA
recognizes that the EGs provide significant flexibilities and states
implementing the EGs may choose to mitigate impacts to some markets
outside the utility power sector. Similarly, demand for new generation
or DS-EE as a result of states implementing the guidelines can result
in shifts in production and profitability for firms that supply those
goods and services.
Executive Order 13563 directs federal agencies to consider the
effect of regulations on job creation and employment. According to the
Executive Order, ``our regulatory system must protect public health,
welfare, safety, and our environment while promoting economic growth,
[[Page 65043]]
innovation, competitiveness, and job creation. It must be based on the
best available science.'' (Executive Order 13563, 2011). Although
standard benefit-cost analyses have not typically included a separate
analysis of regulation-induced employment impacts, we typically conduct
employment analyses. While the economy continues to move toward full
employment, employment impacts are of particular concern and questions
may arise about their existence and magnitude.
The EPA's employment analysis includes projected employment impacts
associated with modeled federal plan approaches for the electric power
industry, coal and natural gas production, and DS-EE activities. These
projections are derived, in part, from a detailed model of the utility
power sector used for this regulatory analysis, and U.S. government
data on employment and labor productivity. In the electricity, coal,
and natural gas sectors, the EPA estimates that the proposed action
could result in a net decrease of approximately 25,000 job-years in
2025 under the rate-based federal plan approach and approximately
26,000 job-years in 2025 under the mass-based approach. For 2030, the
estimates of the net decrease in job-years are 31,000 under the rate-
based approach and 34,000 under the mass-based approach. The agency is
also offering an illustrative calculation of potential employment
effects due to DS-EE programs. Employment impacts from DS-EE programs
in 2030 could range from approximately 52,000 to 83,000 jobs under the
proposal.
By its nature, DS-EE reduces overall demand for electric power. The
EPA recognizes as more efficiency is built into the U.S. power system
over time, lower fuel requirements may lead to fewer jobs in the coal
and natural gas extraction sectors, as well as in fossil fuel-fired EGU
construction and operation than would otherwise have been expected. The
EPA also recognizes the fact that, in many cases, employment gains and
losses that might be attributable to this rule would be expected to
affect different sets of people. Moreover, workers who lose jobs in
these sectors may find employment elsewhere just as workers employed in
new jobs in these sectors may have been previously employed elsewhere.
Therefore, the employment estimates reported in these sectors may
include workers previously employed elsewhere. This analysis also does
not capture potential economy-wide impacts due to changes in prices (of
fuel, electricity, or labor, for example) or other factors such as
improved labor productivity and reduced health care expenditures
resulting from cleaner air. For these reasons, the numbers reported
here should not be interpreted as a net national employment impact.
F. What are the benefits of the proposed action?
Implementing the proposed action will generate benefits by reducing
emissions of CO2 and criteria pollutant precursors,
including SO2, NOX, and directly emitted
particles. SO2 and NOX are precursors to
PM2.5 (particles smaller than 2.5 microns), and
NOX is a precursor to ozone. The estimated benefits
associated with these emission reductions are beyond those achieved by
previous EPA rulemakings including the Mercury and Air Toxics Standards
rule. The health and welfare benefits from reducing air pollution are
considered co-benefits for this proposal. For this rulemaking, we were
only able to quantify the climate benefits from reduced emissions of
CO2 and the health co-benefits associated with reduced
exposure to PM2.5 and ozone. There are many additional
benefits which we are not able to quantify, leading to an underestimate
of monetized benefits. In summary, we estimate the total combined
climate benefits and health co-benefits for the rate-based federal plan
approach to be $3.5 to $4.6 billion in 2020, $18 to $28 billion in
2025, and $34 to $54 billion in 2030 (3 percent discount rate, 2011$).
Total combined climate benefits and health co-benefits for the mass-
based federal plan approach are estimated to be $5.3 to $8.1 billion in
2020, $19 to $29 billion in 2025, and $32 to $48 billion in 2030 (3
percent discount rate, 2011$). A summary of the emission reductions and
monetized benefits estimated for this rule at all discount rates is
provided in Tables 15 through 17 of this preamble.
Table 15--Summary of the Monetized Global Climate Benefits for the Proposal
[Billions of 2011$] \a\
----------------------------------------------------------------------------------------------------------------
Monetized climate benefits
Year Discount rate -----------------------------------------------
(statistic) 2020 2025 2030
----------------------------------------------------------------------------------------------------------------
Rate-based Federal Plan Approach
----------------------------------------------------------------------------------------------------------------
CO2 Reductions (million short tons)... ........................ 69 232 415
5 percent (average SC- $0.80 $3.1 $6.4
CO2).
3 percent (average SC- 2.8 10 20
CO2).
2.5 percent (average SC- 4.1 15 29
CO2).
3 percent (95th 8.2 31 61
percentile SC-CO2).
----------------------------------------------------------------------------------------------------------------
Mass-based Federal Plan Approach
----------------------------------------------------------------------------------------------------------------
CO2 Reductions (million short tons)... ........................ 81 265 413
5 percent (average SC- $0.94 $3.6 $6.4
CO2).
3 percent (average SC- 3.3 12 20
CO2).
2.5 percent (average SC- 4.9 17 29
CO2).
3 percent (95th 9.7 35 60
percentile SC-CO2).
----------------------------------------------------------------------------------------------------------------
\a\ Climate benefit estimates reflect impacts from CO2 emission changes in the analysis years presented in the
table and do not account for changes in non-CO2 GHG emissions. These estimates are based on the global social
cost of carbon (SC-CO2) estimates for the analysis years and are rounded to two significant figures.
[[Page 65044]]
Table 16--Summary of the Monetized Health Co-Benefits in the U.S. for the Proposal, Rate-Based Federal Plan
Approach
[Billions of 2011$] \a\
----------------------------------------------------------------------------------------------------------------
National Monetized Monetized
emission health co- health co-
Pollutant reductions benefits (3 benefits (7
(thousands of percent percent
short tons) discount) discount)
----------------------------------------------------------------------------------------------------------------
Rate-Based Federal Plan Approach, 2020
----------------------------------------------------------------------------------------------------------------
PM2.5 precursors \b\
----------------------------------------------------------------------------------------------------------------
SO2............................................................. 14 $0.44 to $0.99 $0.39 to $0.89
NOX............................................................. 50 $0.14 to $0.33 $0.13 to $0.30
----------------------------------------------------------------------------------------------------------------
Ozone precursor \c\
----------------------------------------------------------------------------------------------------------------
NOX (ozone season only)......................................... 19 $0.12 to $0.52 $0.12 to $0.52
---------------------------------------------------------------------------------
Total Monetized Health Co-benefits $0.70 to $1.8 $0.64 to $1.7
Total Monetized Health Co-benefits combined with Monetized Climate Benefits \d\ $3.5 to $4.6 $3.5 to $4.5
----------------------------------------------------------------------------------------------------------------
Rate-Based Federal Plan Approach, 2025
----------------------------------------------------------------------------------------------------------------
PM2.5 precursors \ b\
----------------------------------------------------------------------------------------------------------------
SO2............................................................. 178 $6.4 to $14 $5.7 to $13
NOX............................................................. 165 $0.56 to $1.3 $0.50 to $1.1
----------------------------------------------------------------------------------------------------------------
Ozone precursor \c\
----------------------------------------------------------------------------------------------------------------
NOX (ozone season only)......................................... 70 $0.49 to $2.1 $0.49 to $2.1
---------------------------------------------------------------------------------
Total Monetized Health Co-benefits $7.4 to $18 $6.7 to $16
Total Monetized Health Co-benefits combined with Monetized Climate Benefits \d\ $18 to $28 $17 to $26
----------------------------------------------------------------------------------------------------------------
Rate-Based Federal Plan Approach, 2030
----------------------------------------------------------------------------------------------------------------
PM2.5 precursors \b\
----------------------------------------------------------------------------------------------------------------
SO2............................................................. 318 $12 to $28 $11 to $25
NOX............................................................. 282 $1.0 to $2.3 $0.93 to $2.1
----------------------------------------------------------------------------------------------------------------
Ozone precursor \c\
----------------------------------------------------------------------------------------------------------------
NOX (ozone season only)......................................... 118 $0.86 to $3.7 $0.86 to $3.7
---------------------------------------------------------------------------------
Total Monetized Health Co-benefits $14 to $34 $13 to $31
Total Monetized Health Co-benefits combined with Monetized Climate Benefits \d\ $34 to $54 $33 to $51
----------------------------------------------------------------------------------------------------------------
\a\ All estimates are rounded to two significant figures, so estimates may not sum. It is important to note that
the monetized co-benefits do not include reduced health effects from direct exposure to SO2, direct exposure
to NO2, exposure to mercury, ecosystem effects, or visibility impairment. Air pollution health co-benefits are
estimated using regional benefit-per-ton estimates for the contiguous United States.
\b\ The monetized PM2.5 co-benefits reflect the human health benefits associated with reducing exposure to PM2.5
through reductions of PM2.5 precursors, such as SO2 and NOX. The co-benefits do not include the benefits of
reductions in directly emitted PM2.5. These additional benefits would increase overall benefits by a few
percent based on the analyses conducted for the proposed Clean Power Plan EGs. PM co-benefits are shown as a
range reflecting the use of two concentration-response functions, with the lower end of the range based on a
function from Krewski et al. (2009) and the upper end based on a function from Lepeule et al. (2012). These
models assume that all fine particles, regardless of their chemical composition, are equally potent in causing
premature mortality because the scientific evidence is not yet sufficient to allow differentiation of effect
estimates by particle type.
\c\ The monetized ozone co-benefits reflect the human health benefits associated with reducing exposure to ozone
through reductions of NOX during the ozone season. Ozone co-benefits are shown as a range reflecting the use
of several different concentration-response functions, with the lower end of the range based on a function
from Bell, et al. (2004) and the upper end based on a function from Levy, et al. (2005). Ozone co-benefits
occur in the analysis year, so they are the same for all discount rates.
\d\ We estimate climate benefits associated with four different values of a one ton CO2 reduction (model average
at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent). Referred to as the
social cost of carbon, each value increases over time. For the purposes of this table, we show the benefits
associated with the model average at 3 percent discount rate, however we emphasize the importance and value of
considering the full range of social cost of carbon values. We provide combined climate and health estimates
based on additional discount rates in the RIA.
[[Page 65045]]
Table 17--Summary of the Monetized Health Co-Benefits in the U.S. for the Proposal, Mass-Based Federal Plan
Approach
[Billions of 2011$] \a\
----------------------------------------------------------------------------------------------------------------
National Monetized Monetized
emission health co- health co-
Pollutant reductions benefits (3 benefits (7
(thousands of percent percent
short tons) discount) discount)
----------------------------------------------------------------------------------------------------------------
Mass-Based Federal Plan Approach, 2020
----------------------------------------------------------------------------------------------------------------
PM2.5 precursors \b\
----------------------------------------------------------------------------------------------------------------
SO2............................................................. 54 $1.7 to $3.8 $1.5 to $3.4
NOX............................................................. 60 $0.17 to $0.39 $0.16 to $0.36
----------------------------------------------------------------------------------------------------------------
Ozone precursor \c\
----------------------------------------------------------------------------------------------------------------
NOX (ozone season only)......................................... 23 $0.14 to $0.61 $0.14 to $0.61
---------------------------------------------------------------------------------
Total Monetized Health Co-benefits $2.0 to $4.8 $1.8 to $4.4
Total Monetized Health Co-benefits combined with Monetized Climate Benefits \d\ $5.3 to $8.1 $5.1 to $7.7
----------------------------------------------------------------------------------------------------------------
Mass-Based Federal Plan Approach, 2025
----------------------------------------------------------------------------------------------------------------
PM2.5 precursors \b\
----------------------------------------------------------------------------------------------------------------
SO2............................................................. 185 $6.0 to $13 $5.4 to $12
NOX............................................................. 203 $0.58 to $1.3 $0.52 to $1.2
----------------------------------------------------------------------------------------------------------------
Ozone precursor \c\
----------------------------------------------------------------------------------------------------------------
NOX (ozone season only)......................................... 88 $0.56 to $2.4 $0.56 to $2.4
---------------------------------------------------------------------------------
Total Monetized Health Co-benefits $7.1 to $17 $6.5 to $16
Total Monetized Health Co-benefits combined with Monetized Climate Benefits \d\ $19 to $29 $18 to $27
----------------------------------------------------------------------------------------------------------------
Mass-Based Federal Plan Approach, 2030
----------------------------------------------------------------------------------------------------------------
PM2.5 precursors \b\
----------------------------------------------------------------------------------------------------------------
SO2............................................................. 280 $10 to $23 $9.0 to $20
NOX............................................................. 278 $0.87 to $2.0 $0.79 to $1.8
----------------------------------------------------------------------------------------------------------------
Ozone precursor \c\
----------------------------------------------------------------------------------------------------------------
NOX (ozone season only)......................................... 121 $0.82 to $3.5 $0.82 to $3.5
---------------------------------------------------------------------------------
Total Monetized Health Co-benefits $12 to $28 $11 to $26
Total Monetized Health Co-benefits combined with Monetized Climate Benefits \d\ $32 to $48 $31 to $46
----------------------------------------------------------------------------------------------------------------
\a\ All estimates are rounded to two significant figures, so estimates may not sum. It is important to note that
the monetized co-benefits do not include reduced health effects from direct exposure to SO2, direct exposure
to NO2, exposure to mercury, ecosystem effects, or visibility impairment. Air pollution health co-benefits are
estimated using regional benefit-per-ton estimates for the contiguous United States.
\b\ The monetized PM2.5 co-benefits reflect the human health benefits associated with reducing exposure to PM2.5
through reductions of PM2.5 precursors, such as SO2 and NOX. The co-benefits do not include the benefits of
reductions in directly emitted PM2.5. These additional benefits would increase overall benefits by a few
percent based on the analyses conducted for the proposed Clean Power Plan EGs. PM co-benefits are shown as a
range reflecting the use of two concentration-response functions, with the lower end of the range based on a
function from Krewski et al. (2009) and the upper end based on a function from Lepeule et al. (2012). These
models assume that all fine particles, regardless of their chemical composition, are equally potent in causing
premature mortality because the scientific evidence is not yet sufficient to allow differentiation of effect
estimates by particle type.
\c\ The monetized ozone co-benefits reflect the human health benefits associated with reducing exposure to ozone
through reductions of NOX during the ozone season. Ozone co-benefits are shown as a range reflecting the use
of several different concentration-response functions, with the lower end of the range based on a function
from Bell, et al. (2004) and the upper end based on a function from Levy, et al. (2005). Ozone co-benefits
occur in the analysis year, so they are the same for all discount rates.
\d\ We estimate climate benefits associated with four different values of a one ton CO2 reduction (model average
at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent). Referred to as the
social cost of carbon, each value increases over time. For the purposes of this table, we show the benefits
associated with the model average at 3 percent discount rate, however we emphasize the importance and value of
considering the full range of social cost of carbon values. We provide combined climate and health estimates
based on additional discount rates in the RIA.
The EPA has used the social cost of carbon (SC-CO2)
estimates presented in the Technical Support Document: Technical Update
of the Social Cost of Carbon for Regulatory Impact Analysis Under
Executive Order 12866 (May 2013, Revised July 2015) (``current TSD'')
to analyze CO2 climate impacts of this rulemaking.\129\ We
refer to these
[[Page 65046]]
estimates, which were developed by the U.S. government, as ``SC-
CO2 estimates.'' The SC-CO2 is a metric that
estimates the monetary value of impacts associated with marginal
changes in CO2 emissions in a given year. It includes a wide
range of anticipated climate impacts, such as net changes in
agricultural productivity and human health, property damage from
increased flood risk, and changes in energy system costs, such as
reduced costs for heating and increased costs for air conditioning. It
is typically used to assess the avoided damages as a result of
regulatory actions (i.e., benefits of rulemakings that lead to an
incremental reduction in cumulative global CO2 emissions).
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\129\ Docket ID EPA-HQ-OAR-2013-0495, Technical Support
Document: Technical Update of the Social Cost of Carbon for
Regulatory Impact Analysis Under Executive Order 12866, Interagency
Working Group on Social Cost of Carbon, with participation by
Council of Economic Advisers, Council on Environmental Quality,
Department of Agriculture, Department of Commerce, DOE, Department
of Transportation, Domestic Policy Council, Environmental Protection
Agency, National Economic Council, Office of Management and Budget,
Office of Science and Technology Policy, and Department of Treasury
(May 2013, Revised July 2015). Available at: http://www.whitehouse.gov/sites/default/files/omb/inforeg/scc-tsd-final-july-2015.pdf.
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The SC-CO2 estimates used in this analysis were
developed over many years, using the best science available, and with
input from the public. Specifically, an interagency working group (IWG)
that included the EPA and other executive branch agencies and offices
used three integrated assessment models (IAMs) to develop the SC-
CO2 estimates and recommended four global values for use in
regulatory analyses. The SC-CO2 estimates were first
released in February 2010 and updated in 2013 using new versions of
each IAM. The 2010 SC-CO2 Technical Support Document (2010
TSD) \130\ provides a complete discussion of the methods used to
develop these estimates and the current TSD presents and discusses the
2013 update (including two recent minor corrections to the
estimates).\131\
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\130\ Docket ID EPA-HQ-OAR-2009-0472-114577, Technical Support
Document: Social Cost of Carbon for Regulatory Impact Analysis Under
Executive Order 12866, Interagency Working Group on Social Cost of
Carbon, with participation by the Council of Economic Advisers,
Council on Environmental Quality, Department of Agriculture,
Department of Commerce, Department of Energy, Department of
Transportation, Environmental Protection Agency, National Economic
Council, Office of Energy and Climate Change, Office of Management
and Budget, Office of Science and Technology Policy, and Department
of Treasury (February 2010). Also available at: http://www.whitehouse.gov/sites/default/files/omb/inforeg/for-agencies/Social-Cost-of-Carbon-for-RIA.pdf.
\131\ The current version of the TSD is available at: https://www.whitehouse.gov/sites/default/files/omb/inforeg/scc-tsd-final-july-2015.pdf, Docket ID EPA-HQ-OAR-2013-0495, Technical Support
Document: Technical Update of the Social Cost of Carbon for
Regulatory Impact Analysis Under Executive Order 12866, Interagency
Working Group on Social Cost of Carbon, with participation by
Council of Economic Advisers, Council on Environmental Quality,
Department of Agriculture, Department of Commerce, Department of
Energy, Department of Transportation, Domestic Policy Council,
Environmental Protection Agency, National Economic Council, Office
of Management and Budget, Office of Science and Technology Policy,
and Department of Treasury (May 2013, Revised July 2015).
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OMB's Office of Information and Regulatory Affairs received
comments in response to a request for public comment on the approach
used to develop the estimates. After careful evaluation of the full
range of comments submitted to OMB, the IWG continues to recommend the
use of the SC-CO2 estimates in RIA.\132\ With the release of
the response to comments, the IWG announced plans to obtain expert
independent advice from the National Academies of Sciences,
Engineering, and Medicine (Academies) to ensure that the SC-
CO2 estimates continue to reflect the best available
scientific and economic information on climate change. The Academies
review will be informed by the public comments received and focus on
the technical merits and challenges of potential approaches to
improving the SC-CO2 estimates in future updates. See the
EPA Response to Comments document for the complete response to comments
received on SC-CO2 as part of this rulemaking.
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\132\ See https://www.whitehouse.gov/omb/oira/social-cost-of-carbon for additional details, including the OMB Response to
Comments and the SC-CO2 TSDs.
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Concurrent with OMB's publication of the response to comments on
SC-CO2 and announcement of the Academies process, OMB posted
a revised TSD that includes two minor technical corrections to the
current estimates. One technical correction addressed an inadvertent
omission of climate change damages in the last year of analysis (2300)
in one model and the second addressed a minor indexing error in another
model. On average the revised SC-CO2 estimates are one
dollar less than the mean SC-CO2 estimates reported in the
November 2013 revision to the May 2013 TSD. The change in the estimates
associated with the 95th percentile estimates when using a 3 percent
discount rate is slightly larger, as those estimates are heavily
influenced by the results from the model that was affected by the
indexing error.
The EPA, as a member of the IWG on the SC-CO2, has
carefully examined and evaluated the minor technical corrections in the
revised TSD and the public comments submitted to OMB's SC-
CO2 comment process. The EPA concurs with the IWG's
conclusion that it is reasonable, and scientifically appropriate, to
use the current SC-CO2 estimates for purposes of RIA,
including for this proceeding.
The four SC-CO2 estimates are as follows: $12, $40, $60,
and $120 per short ton of CO2 emissions in the year 2020
(2011$).\133\ The first three values are based on the average SC-
CO2 from the three IAMs, at discount rates of 5, 3, and 2.5
percent, respectively. The SC-CO2 value at several discount
rates are included because the literature shows that the SC-
CO2 is quite sensitive to assumptions about the discount
rate, and because no consensus exists on the appropriate rate to use in
an intergenerational context (where costs and benefits are incurred by
different generations). The fourth value is the 95th percentile of the
SC-CO2 from all three models at a 3 percent discount rate.
It is included to represent higher-than-expected impacts from
temperature change further out in the tails of the SC-CO2
distribution (representing less likely, but potentially catastrophic,
outcomes).
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\133\ The current version of the TSD is available at: https://www.whitehouse.gov/sites/default/files/omb/inforeg/scc-tsd-final-july-2015.pdf. The 2010 and 2013 TSDs present SC-CO2 in
2007$ per metric ton. The estimates were adjusted to (1) Short tons
for using conversion factor 0.90718474 and (2) 2011$ using Gross
Domestic Product and Related Price Measures: Indexes and Percent
Changes, http://www.gpo.gov/fdsys/pkg/ECONI-2013-02/pdf/ECONI-2013-02-Pg3.pdf.
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There are limitations in the estimates of the benefits from this
proposal, including the omission of climate and other CO2
related benefits that could not be monetized. The 2010 TSD discusses a
number of limitations to the SC-CO2 analysis, including the
incomplete way in which the IAMs capture catastrophic and non-
catastrophic impacts, their incomplete treatment of adaptation and
technological change, uncertainty in the extrapolation of damages to
high temperatures, and assumptions regarding risk aversion. Currently,
IAMs do not assign value to all of the important impacts of
CO2 recognized in the literature, such as ocean
acidification or potential tipping points, for various reasons,
including the inherent difficulties in valuing non-market impacts and
the fact that the science incorporated into these models understandably
lags behind the most recent research. Nonetheless, these estimates and
the discussion of their limitations represent the best available
information about the social benefits of CO2 emission
reductions to inform the benefit-cost analysis. As previously noted,
the IWG plans to seek
[[Page 65047]]
independent expert advice on technical opportunities to improve the SC-
CO2 estimates from the Academies. The Academies' process
will help to ensure that the SC-CO2 estimates used by the
federal government continue to reflect the best available science and
methodologies. Additional details are provided in the TSDs.
The health co-benefits estimates represent the total monetized
human health benefits for populations exposed to reduced
PM2.5 and ozone resulting from emission reductions from the
federal plan approaches examined in the RIA for this proposal. Unlike
the global SC-CO2 estimates, the air pollution health co-
benefits are estimated for the contiguous United States only. We used a
``benefit-per-ton'' approach to estimate the benefits of this
rulemaking. To create the PM2.5 benefit-per-ton estimates,
we conducted air quality modeling for an illustrative scenario
reflecting the proposed Clean Power Plan EGs to convert precursor
emissions into changes in ambient PM2.5 and ozone
concentrations. We then used these air quality modeling results in
BenMAP \134\ to calculate average regional benefit-per-ton estimates
using the health impact assumptions used in the PM NAAQS RIA \135\ and
Ozone NAAQS RIAs.136 137 The three regions were the Eastern
United States, Western United States, and California. To calculate the
co-benefits for this proposal, we multiplied the regional benefit-per-
ton estimates generated from modeling of the proposed Clean Power Plan
EGs standards by the corresponding regional emission reductions for
this proposal.\138\ All benefit-per-ton estimates reflect the
geographic distribution of the modeled emissions for the proposed Clean
Power Plan EGs, which may not exactly match the emission reductions in
this proposed rulemaking, and thus they may not reflect the local
variability in population density, meteorology, exposure, baseline
health incidence rates, or other local factors for any specific
location. More information regarding the derivation of the benefit-per-
ton estimates is available in the Clean Power Plan Final Rule RIA.
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\134\ http://www.epa.gov/airquality/benmap/index.html.
\135\ U.S. Environmental Protection Agency (U.S. EPA). 2012.
Regulatory Impact Analysis for the Final Revisions to the National
Ambient Air Quality Standards for Particulate Matter. Research
Triangle Park, NC: Office of Air Quality Planning and Standards,
Health and Environmental Impacts Division. (EPA document number EPA-
452/R-12-003, December 2012). Available at: http://www.epa.gov/ttnecas1/regdata/RIAs/finalria.pdf.
\136\ U.S. Environmental Protection Agency (U.S. EPA). 2008b.
Final Ozone NAAQS Regulatory Impact Analysis. Research Triangle
Park, NC: Office of Air Quality Planning and Standards, Health and
Environmental Impacts Division, Air Benefit and Cost Group Research.
(EPA document number EPA-452/R-08-003, March 2008). Available at:
http://www.epa.gov/ttnecas1/regdata/RIAs/452_R_08_003.pdf.
\137\ U.S. Environmental Protection Agency (U.S. EPA). 2010.
Section 3: Re-analysis of the Benefits of Attaining Alternative
Ozone Standards to Incorporate Current Methods. Available at: http://www.epa.gov/ttnecas1/regdata/RIAs/s3-supplemental_analysis-updated_benefits11-5.09.pdf.
\138\ U.S. Environmental Protection Agency. 2013. Technical
support document: Estimating the Benefit per Ton of Reducing
PM2.5 Precursors from 17 Sectors. Research Triangle Park,
NC: Office of Air and Radiation, Office of Air Quality Planning and
Standards, January. Available at: http://www.epa.gov/airquality/benmap/models/Source_Apportionment_BPT_TSD_1_31_13.pdf.
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PM benefit-per-ton values are generated using two concentration-
response functions, Krewski et al. (2009) \139\ and Lepeule et al.
(2012).\140\ These models assume that all fine particles, regardless of
their chemical composition, are equally potent in causing premature
mortality because the scientific evidence is not yet sufficient to
allow differentiation of effect estimates by particle type. Even though
we assume that all fine particles have equivalent health effects, the
benefit-per-ton estimates vary between PM2.5 precursors
depending on the location and magnitude of their impact on
PM2.5 concentrations, which drive population exposure.
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\139\ Krewski D.; M. Jerrett; R. T. Burnett; R. Ma; E. Hughes;
Y. Shi, et al. 2009. Extended Follow-up and Spatial Analysis of the
American Cancer Society Study Linking Particulate Air Pollution and
Mortality. Health Effects Institute. (HEI Research Report number
140). Boston, MA: Health Effects Institute.
\140\ Lepeule, J.; F. Laden; D. Dockery; J. Schwartz. 2012.
``Chronic Exposure to Fine Particles and Mortality: An Extended
Follow-Up of the Harvard Six Cities Study from 1974 to 2009.''
Environmental Health Perspective, 120(7), July, pp. 965-970.
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It is important to note that the magnitude of the PM2.5
and ozone co-benefits is largely driven by the concentration response
functions for premature mortality and the value of a statistical life
used to value reductions in premature mortality. For PM2.5,
we use two key empirical studies, one based on the American Cancer
Society cohort study (Krewski et al., 2009) and one based on the
extended Six Cities cohort study (Lepuele et al., 2012). The
PM2.5 co-benefits results are presented as a range based on
benefit-per-ton estimates calculated using the concentration-response
functions from these two epidemiology studies, but this range does not
capture the full range of uncertainty inherent in the co-benefits
estimates. In the RIA for this rule, which is available in the docket,
we also include PM2.5 co-benefits estimates using benefit-
per-ton estimates based on expert judgments of the effect of
PM2.5 on premature mortality (Roman et al., 2008) \141\ as a
characterization of uncertainty regarding the PM2.5-
mortality relationship.
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\141\ Roman, H., et al. 2008. ``Expert Judgment Assessment of
the Mortality Impact of Changes in Ambient Fine Particulate Matter
in the U.S.'' Environmental Science & Technology, Vol. 42, No. 7,
February, pp. 2268-2274.
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For the ozone co-benefits, we present the results as a range
reflecting benefit-per-ton estimates which use several different
concentration-response functions for mortality, with the lower end of
the range based on a benefit-per-ton estimate using the function from
Bell et al. (2004) \142\ and the upper end based on a benefit-per-ton
estimate using the function from Levy et al. (2005).\143\ Similar to
PM2.5, the range of ozone co-benefits does not capture the
full range of inherent uncertainty.
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\142\ 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), pp. 2372-8.
\143\ Levy, J.I., S.M. Chemerynski, and J.A. Sarnat. 2005.
``Ozone Exposure and Mortality: An Empiric Bayes Metaregression
Analysis.'' Epidemiology. 16(4): p. 458-68.
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In this analysis, in estimating the benefits-per-ton for
PM2.5 precursors, the EPA assumes that the health impact
function for fine particles is without a threshold. This is based on
the conclusions of the EPA's Integrated Science Assessment for
Particulate Matter,\144\ which evaluated the substantial body of
published scientific literature, reflecting thousands of epidemiology,
toxicology, and clinical studies, that documents the association
between elevated PM2.5 concentrations and adverse health
effects, including increased premature mortality. This assessment,
which was twice reviewed by the EPA's independent Science Advisory
Board, concluded that the scientific literature consistently finds that
a no-threshold model most adequately portrays the PM-mortality
concentration-response relationship.
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\144\ U.S. Environmental Protection Agency. 2009. Integrated
Science Assessment for Particulate Matter (Final Report). Research
Triangle Park, NC: National Center for Environmental Assessment, RTP
Division. (EPA document number EPA-600-R-08-139F, December 2009).
Available at: http://cfpub.epa.gov/si/si_public_record_Report.cfm?dirEntryId=216546.
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In general, we are more confident in the magnitude of the risks we
estimate from simulated PM2.5 concentrations that coincide
with the bulk of the observed PM concentrations in the epidemiological
studies that are used to estimate the benefits. Likewise, we are less
confident in the risk we estimate from simulated PM2.5
concentrations
[[Page 65048]]
that fall below the bulk of the observed data in these studies.
For this analysis, policy-specific air quality data are not
available,\145\ and thus, we are unable to estimate the percentage of
premature mortality associated with this specific rule that is above
the lowest measured PM2.5 levels (LML) for the two
PM2.5 mortality epidemiology studies that form the basis for
our analysis. As a surrogate measure of mortality impacts above the
LML, we provide the percentage of the population exposed above the LML
in each of the two studies, using the estimates of baseline projected
PM2.5 from the air quality modeling for the proposed
guidelines used to calculate the benefit-per-ton estimates for the EGU
sector. Using the Krewski et al. (2009) study, 88 percent of the
population is exposed to annual mean PM2.5 levels at or
above the LML of 5.8 micrograms per cubic meter ([mu]g/m\3\). Using the
Lepeule et al. (2012) study, 46 percent of the population is exposed
above the LML of 8 [mu]g/m\3\. It is important to note that baseline
exposure is only one parameter in the health impact function, along
with baseline incidence rates, population, and change in air quality.
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\145\ In addition, site-specific emission reductions will depend
upon how states implement the guidelines.
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Every benefit analysis examining the potential effects of a change
in environmental protection requirements is limited, to some extent, by
data gaps, model capabilities (such as geographic coverage), and
uncertainties in the underlying scientific and economic studies used to
configure the benefit and cost models. Despite these uncertainties, we
believe the air quality co-benefit analysis for this rule provides a
reasonable indication of the expected health benefits of the air
pollution emission reductions for the illustrative analysis of this
proposed action under a set of reasonable assumptions. This analysis
does not include the type of detailed uncertainty assessment found in
the 2012 PM2.5 NAAQS RIA (U.S. EPA, 2012) because we lack
the necessary air quality input and monitoring data to conduct a
complete benefits assessment. In addition, using a benefit-per-ton
approach adds another important source of uncertainty to the benefits
estimates. The 2012 PM2.5 NAAQS benefits analysis provides
an indication of the sensitivity of our results to various assumptions.
We note that the monetized co-benefits estimates shown here do not
include several important benefit categories, including exposure to
SO2, NOX, and HAP (e.g., mercury and hydrogen
chloride), as well as ecosystem effects and visibility impairment.
Although we do not have sufficient information or modeling available to
provide monetized estimates for this rule, a qualitative assessment of
these unquantified benefits is included in the RIA for this proposal.
In addition, in the RIA for this proposal, we did not estimate changes
in emissions of directly emitted particles. As a result, quantified
PM2.5 related benefits are underestimated by a relatively
small amount. In the RIA for the proposed Clean Power Plan EGs, the
benefits from reductions in directly emitted PM2.5 were less
than 10 percent of total monetized health co-benefits across all
scenarios and years.
For more information on the benefits analysis, please refer to the
RIA for this rule, which is available in the rulemaking docket.
IX. Community and Environmental Justice Considerations
In this section we provide an overview of the actions that the
agency is taking to help ensure that vulnerable communities are not
disproportionately impacted by this rulemaking.
As described in the Executive Summary, climate change is an EJ
issue. Low-income communities and communities of color already
overburdened with pollution are likely to be disproportionately
affected by, and less resilient to, the impacts of climate change. This
rulemaking will provide broad benefit to communities across the nation,
as its purpose is to reduce GHGs, the most significant driver of
climate change. While addressing climate change will provide broad
benefits, it is particularly beneficial to low-income populations and
some communities of color (in particular, populations defined jointly
by ethnic/racial characteristics and geographic location) where people
are most vulnerable to the impacts of climate change (a more robust
discussion of the impacts of climate change on vulnerable communities
is provided in the Executive Order 12898 discussion in section X.J of
this preamble). While climate change is a global phenomenon, the
adverse effects of climate change can be very localized, as impacts
such as storms, flooding, and droughts are experienced in individual
communities.
Vulnerable communities also often receive more than their fair
share of conventional air pollution, with the attendant adverse health
impacts.
The changes in electricity generation that will result from this
rule will further benefit communities by reducing existing air
pollution that directly contributes to adverse localized health
effects. These air quality improvements will be achieved through this
rule because the EGUs that emit the most GHGs also have the highest
emissions of conventional pollutants, such as SO2,
NOX, fine particles, and HAP. These pollutants are known to
contribute to adverse health outcomes, including the development of
heart and lung diseases, such as asthma and bronchitis, increased
susceptibility to respiratory and cardiac symptoms, greater numbers of
emergency room visits and hospital admissions, and premature
deaths.\146\ The EPA expects that the reductions in utilization of
higher-emitting units likely to occur during the implementation of
federal plans will produce significant reductions in emissions of
conventional pollutants, particularly in those communities already
overburdened by pollution, which are often low-income communities,
communities of color, and indigenous communities. These reductions will
have beneficial effects on air quality and public health, both locally
and regionally. Further, this rulemaking complements other actions
already taken by the EPA to reduce conventional pollutant emissions and
improve health outcomes for overburdened communities.
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\146\ Six Common Air Pollutants. http://www.epa.gov/oaqps001/urbanair/.
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By reducing millions of tons of CO2 emissions that are
contributing to global GHG levels and providing strong leadership to
encourage meaningful reductions by countries across the globe, this
rule is a significant step to address health and economic impacts of
climate change that will fall disproportionately on vulnerable
communities. By reducing millions of tons of conventional air
pollutants, this proposed rule will lead to better air quality and
improved health in those communities. In the comment period for the
Clean Power Plan, we heard from many commenters who recognize and
welcome those benefits.
There are other ways in which the actions that result from this
rulemaking may affect overburdened communities in positive or
potentially adverse ways and we also heard about these from commenters
on the EGs.
While the agency expects overall emission decreases as a result of
this rulemaking, we recognize that some EGUs may operate more
frequently. To the extent that we project increases in utilization as a
result of this rulemaking, we expect these increases to occur generally
in lower-emitting NGCC units,
[[Page 65049]]
which have minimal or no emissions of SO2 and HAP, lower
emissions of particulate matter, and much lower emissions of
NOX compared to higher-emitting steam units. We acknowledge
the concerns that have been raised on this point, but also the
difficulty in anticipating prior to plan implementation where those
impacts might occur. As described below, the EPA intends to conduct an
assessment of whether and where emission increases may result from plan
implementation and mitigate adverse impacts, if any, in overburdened
communities.
In addition to the many positive anticipated health benefits of
this rulemaking, it also will increase the use of clean energy and will
encourage EE. These changes in the electricity generation system, which
are already occurring, but may be accelerated by this program, are
expected to have other positive benefits for communities. The
electricity sector is, and will continue to be, investing more in RE
and EE. The construction of renewable generation and the implementation
of EE programs such as residential weatherization will bring investment
and employment opportunities to the communities where they take place.
It is important to ensure that all communities share in these benefits.
And while we estimate that the benefits of this program will greatly
exceed its costs (as noted in the RIA for this rulemaking), it is also
important to ensure that to the extent there are increases in
electricity costs, that those do not fall disproportionately on those
least able to afford them.
The EPA has engaged with community groups throughout this
rulemaking and we received many comments on the issues outlined above
from community groups, EJ organizations, faith-based organizations,
public health organizations, and others. This input has informed this
proposed rulemaking and prompted the EPA to consider other steps that
the agency can take in the short and long term to consider EJ and
impacts to communities in federal plan development and implementation.
It has also prompted us to work with our federal partners to make
sure that communities have information on federal resources available
to assist them. We describe these resources below, as well as resources
that the EPA will be providing to assist communities in accessing EE/RE
and financial assistance programs.
Finally, and importantly, we recognize that communities must be
able to participate meaningfully in the development of this rulemaking.
In this section, we discuss the steps that the EPA will take to assist
communities in engaging with the agency throughout the comment period
of this rulemaking.
A. Proximity Analysis
The EPA is committed to ensuring that there is no disproportionate,
adverse impact on overburdened communities as a result of this proposed
rulemaking. To provide information fundamental to beginning that
process, the EPA has conducted a proximity analysis for this proposed
rulemaking that summarizes demographic data on the communities located
near power plants.\147\ The EPA understands that, in order to prevent
disproportionately high and adverse human health or environmental
effects on these communities, both the agency and communities must have
information on the communities living near facilities, including
demographic data, and that accessing and using census data files
requires expertise that some community groups may lack. Therefore, the
EPA used census data from the American Community Survey (ACS) 2008-2012
to conduct a proximity analysis that can be used by communities as they
engage with the agency throughout the comment period of this
rulemaking. The analysis and its results are presented in the EJ
Screening Report for the Clean Power Plan, which is located in the
docket for this rulemaking at EPA-HQ-OAR-2015-0199.
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\147\ The proximity analysis was conducted using the EPA's
environmental justice mapping and screening tool, EJSCREEN.
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The proximity analysis provides detailed demographic information on
the communities located within a 3-mile radius of each affected power
plant in the United States. Included in the analysis is the breakdown
by percentage of community characteristics such as income and minority
status. The analysis shows a higher percentage of communities of color
and low-income communities living near power plants than national
averages. It is important to note that the impacts of power plant
emissions are not limited to a 3-mile radius and the impacts of both
potential increases and decreases in power plant emissions can be felt
many miles away. Still, being aware of the characteristics of
communities closest to power plants is a starting point in
understanding how changes in the plant's air emissions may affect the
air quality experienced by some of those already experiencing
environmental burdens.
Although overall there is a higher fraction of communities of color
and low-income populations living near power plants than national
averages, there are differences between rural and urban power plants.
There are many rural power plants that are located near small
communities with high percentages of low-income populations and lower
percentages of communities of color. In urban areas, nearby communities
tend to be both low-income communities and communities of color. In
light of this difference between rural and urban communities proximate
to power plants and in order to adequately capture both the low-income
and minority aspects central to environmental justice (EJ)
considerations, we use the terms ``vulnerable'' or ``overburdened''
when referring to these communities. Our intent is for these terms to
be understood in an expansive sense, in order to capture the full scope
of communities, including indigenous communities most often located in
rural areas, that are central to our EJ and community considerations.
As stated in the Executive Order 12898 discussion located in
section X.J of this preamble, the EPA believes that all communities
will benefit from this proposed rulemaking because this action directly
addresses the impacts of climate change by limiting GHG emissions
through the establishment of CO2 emission standards for
existing affected fossil fuel-fired power plants. The EPA also believes
that the information provided in the proximity analysis will promote
engagement between vulnerable communities and the agency throughout the
rulemaking process. In addition to providing the proximity analysis in
the docket of this rulemaking, the EPA will make it publicly available
on its Clean Power Plan Communities Portal that will be linked to this
rulemaking's Web site (http://www.epa.gov/cleanpowerplan). Furthermore,
the EPA has also created an interactive mapping tool that illustrates
where power plants are located and provides information on a state
level. This tool is available at: http://cleanpowerplanmaps.epa.gov/CleanPowerPlan/.
B. Community Engagement in This Rulemaking Process
The EPA has heard from vulnerable communities throughout the
outreach process for the Clean Power Plan that it is imperative for
communities to have an understanding of how rulemakings that target
climate change work. They expressed a desire to know how these programs
may benefit their communities and what the potential adverse impacts of
the rules may be on their communities. We intend to provide
[[Page 65050]]
communities with the information that they need to engage with the
agency throughout the comment period.
We have received feedback from communities that public hearings,
webinars, and in-person meetings are the most effective ways to engage
with them and to provide them with the information they need to
understand the rulemaking process. Therefore, for this rulemaking, in
addition to conducting public hearings for all members of the American
public, the agency will hold a national webinar for communities in the
early stages of the comment period. The goal of this webinar will be to
walk communities through the highlights of the preamble, so they have
an understanding of how the rulemaking may potentially affect their
communities and they will have the contextual information they need to
actively engage with the agency throughout the comment period.
Additionally, because we received positive feedback on the
effectiveness of the face-to-face meetings conducted on the regional
level, each region will be offering an outreach meeting(s) for
communities. The goal of these meetings is to build a level of
understanding on this rulemaking to enable vulnerable communities to
actively engage with the agency throughout the comment period.
Furthermore, we will follow up on common issues raised during the
outreach meetings with national conference calls, specifically targeted
for vulnerable communities.
C. Providing Communities With Access to Additional Resources
In section V.D of this preamble, we outline that we are seeking
comment on whether a portion of this set-aside should be targeted to RE
projects that benefit low-income communities. Furthermore, the EPA is
seeking comment on how a low-income community should be defined as
eligible under this set-aside. We also seek comment on how much of the
set-aside should be designated as targeted at over-burdened
communities. We also request comment on whether the methods of approval
and distribution of allowances to projects that benefit low-income
communities should differ, and if so, in what manner, from the methods
that are proposed to apply to other RE projects.
As discussed below, there are also many federal programs that can
help low-income populations access the benefits of RE and EE, and the
economic benefits of a cleaner energy economy.
In the coming months, the EPA will continue to provide information
and resources for low-income communities on existing federal, state,
local, and other financial assistance programs to encourage EE/RE
opportunities that are already available to communities. For example,
the EPA will provide a catalog of current or recent state and local
programs that have successfully helped communities adopt EE/RE
measures. The goal of these resources is to help vulnerable communities
gain the benefits of this rulemaking. The use of these RE/EE tools can
also help low-income households reduce their electricity consumption
and bills.
Additionally, as part of the resources that we will be providing
low-income communities, the EPA will provide information on the
Administration's Partnerships for Opportunity and Workforce and
Economic Revitalization (POWER) Initative and other programs that
specifically target economic development assistance to communities
affected by changes in the coal industry and the utility power
sector.\148\
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\148\ http://www.eda.gov/power/.
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D. Federal Programs and Resources Available to Communities
Federal agencies have a history of bringing EE and RE to low-income
communities. Earlier this summer, the Administration announced a new
initiative to scale up access to solar energy and cut energy bills for
all Americans, in particular low- and moderate-income communities, and
to create a more inclusive solar workforce. As part of this new
initiative, the U.S. DOE, the U.S. Department of Housing and Urban
Development, U.S. Department of Agriculture, and the EPA launched a
National Community Solar Partnership to unlock access to solar energy
for the nearly 50 percent of households and businesses that are renters
or do not have adequate roof space to install solar systems, with a
focus on low- and moderate-income communities. The Administration also
set a goal to install 300 MW of RE in federally subsidized housing by
2020 and plants to provide technical assistance to make it easier to
install solar energy on affordable housing, including clarifying how to
use federal funding for EE and RE. To continue enhancing employment
opportunities in the solar industry for all Americans, AmeriCorps is
providing funding to deploy solar energy and create jobs in underserved
communities, and DOE is working to expand solar energy education and
opportunities for job training.
These recent announcements build on the many existing federal
programs and resources available to improve EE and accelerate the
deployment of RE in vulnerable communities. Some examples of these
resources include: The DOE's Weatherization Assistance Program, Health
and Human Service's Low-Income Home Energy Assistance Program, the
Department of Agriculture's Energy Efficiency and Conservation Loan
Program, High Cost Energy Grant Program, and the Rural Housing
Service's Multi-Family Housing Program.
The U.S. Department of Housing and Urban Development supports EE
improvements and the deployment of RE on affordable housing through its
Energy Efficient Mortgage Program, Multifamily Property Assessed Clean
Energy Pilot with the State of California, PowerSaver Program, and the
use of Section 108 Community Development Block Grants. The Department
of Treasury provides several tax credits to support RE development and
EE in low-income communities, including the New Markets Tax Credit
Program and the Low-Income Housing Tax Credit. The EPA's RE-Powering
America's Land Initiative promotes the reuse of potentially
contaminated lands, landfills and mine sites--many of which are in low-
income communities--for RE through a combination of tailored
redevelopment tools for communities and developers, as well as site-
specific technical support. The EPA's Green Power Partnership is
increasing community use of renewable electricity across the country
and in low-income communities. The EPA partners with EE programs
throughout the country that leverage ENERGY STAR to deliver broad
consumer energy-saving benefits, of particular value to low-income
households who can least afford high energy bills. ENERGY STAR also
works with houses of worship to reduce energy costs--savings that can
then be repurposed to their community mission, including programs and
assistance to residents in low-income communities. The EPA will be
working with these federal partners and others to ensure that states
and vulnerable communities have access to information on these programs
and their resources.
The federal government also has a number of programs to expand
employment opportunities in the energy sector, including for
underserved populations. Examples of these include the U.S. Department
of Housing and Urban Development, DOE, and the Department of
Education's ``STEM, Energy, and Economic Development'' program; DOE's
Diversity in Science and Technology Advances National Clean Energy in
Solar (DISTANCE-
[[Page 65051]]
Solar) Program; Grid Engineering for Accelerated Renewable Energy
Deployment (GEARED); the DOL's Trade Adjustment Assistance Community
College and Career Training (TAACCCT), Apprenticeship USA Advancing
Apprenticeships in the Energy Field, Job Corps Green Training and
Greening of Centers, and YouthBuild; and the EPA's Environmental
Workforce Development and Job Training (EWDJT) program.
E. Assessing Impacts of Federal Plan Implementation
It is important to the EPA that the implementation of federal plans
be assessed in order to identify whether they cause any adverse impacts
on communities already overburdened by disproportionate environmental
harms and risks. The EPA will conduct its own assessment during the
implementation phase of this rulemaking to determine whether the
implementation of federal plans and other air quality rules are, in
fact, reducing emissions and improving air quality in all areas and, or
whether there are localized air quality impacts that need to be
addressed under the Clean other CAA authorities.
The EPA will provide trainings for communities on resources that
they can use to assess localized impacts, especially effects of co-
pollutants, of plans on their communities. This training will include
guidance in accessing the publicly available information that sources
and states currently report that can help with ongoing assessments of
federal plan impacts. For example, unit-specific emissions data and air
quality monitoring data are readily available. This information,
together with the assessment that the EPA will conduct in the
implementation phase of this rulemaking will enable the agency and
communities to monitor any disproportionate emissions that may result
in adverse impacts and address them.
F. Co-Pollutants
Air quality in a given area is affected by emissions from nearby
sources and may be influenced by emissions that travel hundreds of
miles and mix with emissions from other sources.\149\ In the CSAPR the
EPA used its authority to reduce emissions that significantly
contribute to downwind exposures. The RIA for the final CSAPR
anticipates substantial health benefits for the population across a
wide region. Similarly, the EPA believes that, like the CSAPR, this
rulemaking will result in significant health benefits because it will
reduce co-pollutant emissions of SO2 and NOX on a
regional and national basis.\150\ Thus, localized increases in
NOX emissions may well be more than offset by NOX
decreases elsewhere in the region that produce a net improvement in
ozone and particulate concentrations across the area.
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\149\ 76 FR 48348, August 11, 2011.
\150\ See 76 FR 48347, August 11, 2011.
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Another effect of the final CO2 emission standards for
affected existing fossil fuel-fired EGUs may be increased utilization
of other, unmodified EGUs--in particular, high efficiency gas-fired
EGUs--with relatively low GHG emissions per unit of electrical output.
These plants may operate more hours during the year and could emit
pollutants, including pollutants whose environmental effects would be
localized and regional rather than global as is the case with GHG
emissions. Changes in utilization already occur in response to energy
demands and evolving energy sources, but the final CO2
emission standards for affected existing fossil fuel-fired EGUs can be
expected to cause more such changes. Increased utilization of solid
fossil fuel-fired units generally would not increase peak
concentrations of PM2.5, NOX, or ozone around
such EGUs to levels higher than those that are already occurring
because peak hourly or daily emissions generally would not change;
however, increased utilization may make periods of relatively high
concentrations more frequent. It should be noted that the gas-fired
sources likely to be dispatched more frequently have very low emissions
of primary PM, SO2, and HAP per unit of electrical output
and that they must continue to comply with other CAA requirements that
directly address the conventional pollutants, including federal
emission standards, rules included in SIPs, and conditions in title V
operating permits, in addition to the guidelines in the final EGs
rulemaking published elsewhere in this Federal Register. Therefore,
local (or regional) air quality for these pollutants is not likely to
be significantly affected. For natural gas-fired EGUs, the EPA found
that regulation of HAP emissions ``is not appropriate or necessary
because the impacts due to HAP emissions from such units are negligible
based on the results of the study documented in the utility RTC.''
\151\ Because gas-fired EGUs emit essentially no mercury, increased
utilization will not increase methyl mercury concentrations in water
bodies near these affected EGUs. In studies done by DOE/NETL comparing
cost and performance of coal- and NGCC-fired generation, they assumed
SO2, NOX, PM (and Hg) emissions to be
``negligible.'' Their studies predict NOX emissions from a
NGCC unit to be approximately 10 times lower than a subcritical or
supercritical coal-fired boiler.\152\ Many, although not all, NGCC
units are also very well controlled for emissions of NOX
through the application of after combustion controls such as selective
catalytic reduction.
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\151\ 65 FR 79831, December 20, 2000.
\152\ ``Cost and Performance Baseline for Fossil Energy Plants
Volume 1: Bituminous Coal and Natural Gas to Electricity'' Rev 2a,
September 2013 Revision 2, November 2010 DOE/NETL-2010/1397.
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G. The EPA's Continued Engagement
The EPA is committed to helping ensure that this action will not
have disproportionate adverse human health or environmental effects on
vulnerable communities. Throughout the implementation phase of this
rulemaking, the agency will continue to provide trainings and resources
to assist communities and as they engage with the agency. The EPA,
through its outreach efforts during the comment period, will continue
to solicit feedback from communities on what they would like additional
trainings and resources on.
As described above, the EPA will assess the impacts of this
rulemaking during its implementation. The EPA will house this
assessment, along with the proximity analysis and other information
generated throughout the implementation process, on its Clean Power
Plan Communities Portal that will be linked to this rulemaking's Web
site (http://www.epa.gov/cleanpowerplan). In addition, the EPA has
expanded its set of resources that are being developed to help
communities understand the breadth of policy options and programs that
have successfully brought EE/RE to low-income communities. The EPA is
committed to continuing its engagement with communities from the
comment period of this rulemaking through federal plan implementation.
The EPA consulted its May 2015, Guidance on Considering
Environmental Justice During the Development of Regulatory Actions,
when crafting this rulemaking.\153\ A more detailed discussion
concerning the application of Executive Order 12898 in this rulemaking
can be found in section X.J of this preamble. A summary of the EPA's
interactions with communities is
[[Page 65052]]
in the EJ Screening Report for the Clean Power Plan, available in the
docket of this rulemaking. Furthermore, the EPA's responses to public
comments, including comments received from communities, are provided in
the response to comments documents located in the docket for this
rulemaking.
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\153\ Guidance on Considering Environmental Justice During the
Development of Regulatory Actions. http://www.epa.gov/environmentaljustice/resources/policy/considering-ej-in-rulemaking-guide-final.pdf. May 2015.
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In summary, the EPA in this proposed rulemaking has designed an
integrative approach that helps to ensure that vulnerable communities
are not disproportionately impacted by this rule. The proximity
analysis that the agency has conducted is a central component of this
approach. Not only is the proximity analysis a useful tool to help
identify communities that may be impacted by this rulemaking; it will
also help communities as they engage with the EPA throughout the
comment period. It will help the EPA as we help low-income communities
access EE/RE and financial assistance programs. Finally, in order to
continue to ensure that overburdened communities are not
disproportionately impacted by this rule, the EPA will be conducting an
assessment during the implementation phase of the effects of this and
other rules on air quality.
X. Statutory and Executive Order Reviews
Additional information about these statutes and Executive Orders
can be found at http://www2.epa.gov/laws-regulations/laws-and-executive-orders.
A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 13563: Improving Regulation and Regulatory Review
This proposed action is an economically significant regulatory
action that was submitted to the OMB for review. Any changes made in
response to OMB recommendations have been documented in the docket for
this rulemaking. The EPA prepared an analysis of the potential costs
and benefits associated with this action. This analysis, which is
contained in the ``Regulatory Impact Analysis for the Proposed Federal
Plan Requirements for Greenhouse Gas Emissions from Electric Utility
Generating Units Constructed on or Before January 8, 2014; Model
Trading Rules; Amendments to Framework Regulations'' (EPA-452/R-15-006,
July 2015), is available in the docket and is briefly summarized in
section VIII of this preamble.
Consistent with Executive Order 12866 and Executive Order 13563,
the EPA estimated the costs and benefits for two alternative federal
plan approaches to implementing the proposed federal plan and model
trading rules. The proposed action will achieve the same levels of
emissions performance as required of state plans under the CAA section
111(d) EGs for the control of CO2. Actions taken to comply
with the guidelines will also reduce the emissions of directly-emitted
PM2.5, SO2, and NOX. The benefits
associated with these PM2.5, SO2, and
NOX reductions are referred to as co-benefits, as these
reductions are not the primary objective of this rule.
The RIA for this proposal analyzed two implementation scenarios,
which we term the ``rate-based federal plan approach'' and the ``mass-
based federal plan approach.'' It is very important to note that the
differences between the analytical results for the rate-based and mass-
based federal plan approaches presented in the RIA may not be
indicative of likely differences between the approaches. In other
words, if one approach performs differently than the other on a given
metric during a given time period, this does not imply this will apply
in all instances.
It is important to note that the potential regulatory impacts
presented in the Clean Power Plan Final Rule RIA and the RIA for this
proposed rule are not additive. Both RIAs present estimates of the
benefits and costs of achieving the emission performance rates of the
Clean Power Plan EGs. In the case of the Clean Power Plan Final Rule
RIA, the illustrative analysis assumes the performance rates are met
under state plans. In the case of this RIA for the proposed federal
plan and model trading rules, the same performance rates are
accomplished but are assumed to be achieved under the federal plan or
model trading rules.
The EPA has used the social cost of carbon estimates presented in
the Technical Support Document: Technical Update of the Social Cost of
Carbon for Regulatory Impact Analysis Under Executive Order 12866 (May
2013, Revised July 2015) (``current TSD'') to analyze CO2
climate impacts of this rulemaking. We refer to these estimates, which
were developed by the U.S. government, as ``SC-CO2
estimates.'' The SC-CO2 is an estimate of the monetary value
of impacts associated with a marginal change in CO2
emissions in a given year. The four SC-CO2 estimates are
associated with different discount rates (model average at 2.5 percent
discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent),
and each increases over time. In this summary, the EPA provides the
estimate of climate benefits associated with the SC-CO2
value deemed to be central in the current TSD: The model average at 3
percent discount rate.
The EPA estimates that, in 2020, this proposal will yield monetized
climate benefits (in 2011$) of approximately $2.8 billion for the rate-
based approach and $3.3 billion for the mass-based approach (3 percent
model average). For the rate-based approach, the air pollution health
co-benefits in 2020 are estimated to be $0.7 billion to $1.8 billion
(2011$) for a 3 percent discount rate and $0.64 billion to $1.7 billion
(2011$) for a 7 percent discount rate. For the mass-based approach, the
air pollution health co-benefits in 2020 are estimated to be $2.0
billion to $4.8 billion (2011$) for a 3 percent discount rate and $1.8
billion to $4.4 billion (2011$) for a 7 percent discount rate. The
annual compliance costs estimated by IPM and inclusive of DS-EE program
and participant costs and monitoring, reporting, and recordkeeping
costs in 2020, are approximately $2.5 billion for the rate-based
approach and $1.4 billion for the mass-based approach (2011$). The
quantified net benefits (the difference between monetized benefits and
compliance costs) in 2020 are estimated to range from $1.0 billion to
$2.1 billion (2011$) for the rate-based approach and from $3.9 billion
to $6.7 billion (2011$) for the mass-based approach, using a 3 percent
discount rate (model average).
The EPA estimates that, in 2025, the proposal will yield monetized
climate benefits (in 2011$) of approximately $10 billion for the rate-
based approach and $12 billion for the mass-based approach (3 percent
model average). For the rate-based approach, the air pollution health
co-benefits in 2025 are estimated to be $7.4 billion to $18 billion
(2011$) for a 3 percent discount rate and $6.7 billion to $16 billion
(2011$) for a 7 percent discount rate. For the mass-based approach, the
air pollution health co-benefits in 2025 are estimated to be $7.1
billion to $17 billion (2011$) for a 3 percent discount rate and $6.5
billion to $16 billion (2011$) for a 7 percent discount rate. The
annual compliance costs estimated by IPM and inclusive of DS-EE program
and participant costs and MRR costs in 2025, are approximately $1.0
billion for the rate-based approach and $3.0 billion for the mass-based
approach (2011$). The quantified net benefits (the difference between
monetized benefits and compliance costs) in 2025 are estimated to range
from $17 billion to $27 billion (2011$) for the rate-based approach and
$16 billion to $26 billion (2011$) for the mass-based approach, using a
3 percent discount rate (model average).
[[Page 65053]]
The EPA estimates that, in 2030, the proposal will yield monetized
climate benefits (in 2011$) of approximately $20 billion for the rate-
based approach and $20 billion for the mass-based approach (3 percent
model average). For the rate-based approach, the air pollution health
co-benefits in 2030 are estimated to be $14 billion to $34 billion
(2011$) for a 3 percent discount rate and $13 billion to $31 billion
(2011$) for a 7 percent discount rate. For the mass-based approach, the
air pollution health co-benefits in 2030 are estimated to be $12
billion to $28 billion (2011$) for a 3 percent discount rate and $11
billion to $26 billion (2011$) for a 7 percent discount rate. The
annual compliance costs estimated by IPM and inclusive of DS-EE program
and participant costs and monitoring, reporting, and recordkeeping
costs in 2030, are approximately $8.4 billion for the rate-based
approach and $5.1 billion for the mass-based approach (2011$). The
quantified net benefits (the difference between monetized benefits and
compliance costs) in 2030 are estimated to range from $26 billion to
$45 billion (2011$) for the rate-based approach and from $26 billion to
$43 billion (2011$) for the mass-based approach, using a 3 percent
discount rate (model average).
Table 18 and Table 19 of this preamble provide the estimates of the
climate benefits, health co-benefits, compliance costs and net benefits
of the proposal for rate-based and mass-based federal plan approaches,
respectively.
Table 18--Summary of the Monetized Benefits, Compliance Costs, and Net Benefits for the Proposal in 2020, 2025 and 2030 Under the Rate-Based Federal
Plan Approach
[Billions of 2011$] \a\
--------------------------------------------------------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------------------------------------------------------
Rate-Based Approach
-----------------------------------------------------------------------------------------------------------
2020
2025
2030
--------------------------------------------------------------------------------------------------------------------------------------------------------
Climate Benefits \b\
--------------------------------------------------------------------------------------------------------------------------------------------------------
5% discount rate............................ $0.80
$3.1
$6.4
3% discount rate............................ $2.8
$10
$20
2.5% discount rate.......................... $4.1
$15
$29
95th percentile at 3% discount rate......... $8.2
$31
$61
--------------------------------------------------------------------------------------------------------------------------------------------------------
Air Quality Co-Benefits Discount Rate
--------------------------------------------------------------------------------------------------------------------------------------------------------
3% 7% 3% 7% 3% 7%
--------------------------------------------------------------------------------------------------------------------------------------------------------
Air Quality Health Co-benefits \c\.......... $0.70 to $1.8 $0.64 to $1.7 $7.4 to $18 $6.7 to $16 $14 to $34 $13 to $31
--------------------------------------------------------------------------------------------------------------------------------------------------------
Compliance Costs \d\........................ $2.5
$1.0
$8.4
--------------------------------------------------------------------------------------------------------------------------------------------------------
Net Benefits \e\............................ $1.0 to $2.1 $1.0 to $2.0 $17 to $27 $16 to $25 $26 to $45 $25 to $43
--------------------------------------------------------------------------------------------------------------------------------------------------------
Non-Monetized Benefits...................... Non-monetized climate benefits.
Reductions in exposure to ambient NO2 and SO2.
Reductions in mercury deposition.
Ecosystem benefits associated with reductions in emissions of NOX, SO2, PM, and mercury.
Visibility impairment.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ All are rounded to two significant figures, so figures may not sum.
\b\ The climate benefit estimate in this summary table reflects global impacts from CO2 emission changes and does not account for changes in non-CO2 GHG
emissions. Also, different discount rates are applied to SC-CO2 than to the other estimates because CO2 emissions are long-lived and subsequent
damages occur over many years. The benefit estimates in this table are based on the average SC-CO2 estimated for a 3 percent discount rate. However,
we emphasize the importance and value of considering the full range of SC-CO2 values. As shown in the RIA, climate benefits are also estimated using
the other three SC-CO2 estimates (model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent). The SC-CO2
estimates are year-specific and increase over time.
\c\ The air pollution health co-benefits reflect reduced exposure to PM2.5 and ozone associated with emission reductions of SO2 and NOX. The range
reflects the use of concentration-response functions from different epidemiology studies. The co-benefits do not include the benefits of reductions in
directly emitted PM2.5. These additional benefits would increase overall benefits by a few percent based on the analyses conducted for the Clean Power
Plan proposed rule. The reduction in premature fatalities each year accounts for over 98 percent of total monetized co-benefits from PM2.5 and ozone.
These models assume that all fine particles, regardless of their chemical composition, are equally potent in causing premature mortality because the
scientific evidence is not yet sufficient to allow differentiation of effect estimates by particle type.
\d\ Costs are approximated by the compliance costs estimated using the IPM for this proposal and a discount rate of approximately 5 percent. This
estimate includes monitoring, recordkeeping, and reporting costs and DS-EE program and participant costs.
\e\ The estimates of net benefits in this summary table are calculated using the global SC-CO2 at a 3 percent discount rate (model average). The RIA
includes combined climate and health estimates based on additional discount rates.
[[Page 65054]]
Table 19--Summary of the Monetized Benefits, Compliance Costs, and Net Benefits for the Proposal in 2020, 2025 and 2030 Under the Mass-Based Federal
Plan Approach
[Billions of 2011$] \a\
--------------------------------------------------------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------------------------------------------------------
Mass-Based Approach
-----------------------------------------------------------------------------------------------------------
2020
2025
2030
--------------------------------------------------------------------------------------------------------------------------------------------------------
Climate Benefits \b\
--------------------------------------------------------------------------------------------------------------------------------------------------------
5% discount rate............................ $0.9
$3.6
$6.4
3% discount rate............................ $3.3
$12
$20
2.5% discount rate.......................... $4.9
$17
$29
95th percentile at 3% discount rate......... $9.7
$35
$60
--------------------------------------------------------------------------------------------------------------------------------------------------------
Air Quality Co-Benefits Discount Rate
--------------------------------------------------------------------------------------------------------------------------------------------------------
3% 7% 3% 7% 3% 7%
--------------------------------------------------------------------------------------------------------------------------------------------------------
Air Quality Health Co-benefits \c\.......... $2.0 to $4.8 $1.8 to $4.4 $7.1 to $17 $6.5 to $16 $12 to $28 $11 to $26
--------------------------------------------------------------------------------------------------------------------------------------------------------
Compliance Costs \d\........................ $1.4
$3.0
$5.1
--------------------------------------------------------------------------------------------------------------------------------------------------------
Net Benefits \e\............................ $3.9 to $6.7 $3.7 to $6.3 $16 to $26 $15 to $24 $26 to $43 $25 to $40
--------------------------------------------------------------------------------------------------------------------------------------------------------
Non-Monetized Benefits...................... Non-monetized climate benefits.
Reductions in exposure to ambient NO2 and SO2.
Reductions in mercury deposition.
Ecosystem benefits associated with reductions in emissions of NOX, SO2, PM, and mercury.
Visibility improvement.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ All are rounded to two significant figures, so figures may not sum.
\b\ The climate benefit estimate in this summary table reflects global impacts from CO2 emission changes and does not account for changes in non-CO2 GHG
emissions. Also, different discount rates are applied to SC-CO2 than to the other estimates because CO2 emissions are long-lived and subsequent
damages occur over many years. The benefit estimates in this table are based on the average SC-CO2 estimated for a 3 percent discount rate. However,
we emphasize the importance and value of considering the full range of SC-CO2 values. As shown in the RIA, climate benefits are also estimated using
the other three SC-CO2 estimates (model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent). The SC-CO2
estimates are year-specific and increase over time.
\c\ The air pollution health co-benefits reflect reduced exposure to PM2.5 and ozone associated with emission reductions of SO2 and NOX. The co-benefits
do not include the benefits of reductions in directly emitted PM2.5. These additional benefits would increase overall benefits by a few percent based
on the analyses conducted for the Clean Power Plan proposed rule. The range reflects the use of concentration-response functions from different
epidemiology studies. The reduction in premature fatalities each year accounts for over 98 percent of total monetized co-benefits from PM2.5 and
ozone. These models assume that all fine particles, regardless of their chemical composition, are equally potent in causing premature mortality
because the scientific evidence is not yet sufficient to allow differentiation of effect estimates by particle type.
\d\ Costs are approximated by the compliance costs estimated using IPM for this proposal and a discount rate of approximately 5 percent. This estimate
includes monitoring, recordkeeping, and reporting costs and DS-EE program and participant costs.
\e\ The estimates of net benefits in this summary table are calculated using the global SC-CO2 at a 3 percent discount rate (model average). The RIA
includes combined climate and health estimates based on additional discount rates.
There are additional important benefits that the EPA could not
monetize. Due to current data and modeling limitations, our estimates
of the benefits from reducing CO2 emissions do not include
important impacts like ocean acidification or potential tipping points
in natural or managed ecosystems. Unquantified benefits also include
climate benefits from reducing emissions of non-CO2 GHGs
(e.g., nitrous oxide and methane) and co-benefits from reducing direct
exposure to SO2, NOX, and HAP (e.g., mercury), as
well as from reducing ecosystem effects and visibility impairment.
Based upon the foregoing discussion, it remains clear that the benefits
of this proposed action are substantial, and far exceed the costs.
Additional details on benefits, costs, and net benefits estimates are
provided in the RIA for this proposal.
B. Paperwork Reduction Act (PRA)
The information collection requirements in this rule have been
submitted for approval to OMB under the PRA. The Information Collection
Request (ICR) document prepared by the EPA has been assigned EPA ICR
number 2526.01. You can find a copy of the ICR in the docket for this
rule, and it is briefly summarized here. The information collection
requirements are not enforceable until approved by OMB.
This rule does not directly impose specific requirements on state
and U.S. territory governments with affected EGUs. The rule also does
not impose specific requirements on tribal governments that have
affected EGUs located in their area of Indian country. This rule does
impose specific requirements on affected EGUs located in states, U.S.
territories, or areas of Indian country.
The information collection activities in this proposed rule are
consistent with those activities defined under the Carbon Pollution
Emission Guidelines for Existing Stationary Sources: Electric Utility
Generating Units (i.e., the Clean Power Plan) finalized on August 3,
2015. The information collection requirements in this proposed rule
have been submitted for approval to the Office of Management and Budget
(OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The ICR
document prepared by the EPA has been assigned EPA ICR number 2526.01.
You can find a copy of the ICR in the docket for this rule, and it is
briefly summarized here.
Aside from reading and understanding the rule, this proposed action
would impose minimal new
[[Page 65055]]
information collection burden on affected EGUs beyond what those
affected EGUs would already be subject to under the authorities of 40
CFR parts 75 and 98. OMB has previously approved the information
collection requirements contained in the existing part 75 and 98
regulations (40 CFR part 75 and 40 CFR part 98) under the provisions of
the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. and has assigned
OMB control numbers 2060-0626 and 2060-0629, respectively. Apart from
certain reporting costs based on requirements in the NSPS General
Provisions (40 CFR part 60, subpart A), which are mandatory for all
owners/operators subject to CAA section 111 national emission
standards, there are no new information collection costs, as the
information required by this proposed rule is already collected and
reported by other regulatory programs. The recordkeeping and reporting
requirements are specifically authorized by CAA section 114 (42 U.S.C.
7414). All information submitted to the EPA pursuant to the
recordkeeping and reporting requirements for which a claim of
confidentiality is made is safeguarded according to agency policies set
forth in 40 CFR part 2, subpart B.
Although the EPA cannot determine at this time how many affected
EGU respondents will submit information under the federal plan, the EPA
has estimated an ``upper bound'' burden estimate for this ICR that
estimates burden should every affected EGU read and understand the
rule. This is the only potential respondent activity that would be
required under the 3-year period following publication of the final
federal plan, as there are no obligations to respond in this period.
The results of this upper bound estimate of federal plan burden are
presented below:
Respondents/affected entities: 1,028.
Respondents' obligation to respond: Not applicable, no responses
are required during the period covered by the ICR.
Estimated number of respondents: Unknown at this time, but have
assumed all affected entities are respondents for an upper bound
estimate.
Frequency of response: None, no responses are required during the
period covered by the ICR.
Total estimated burden: 17,133 hours (per year). Burden is defined
at 5 CFR 1320.3(b).
Total estimated cost: $1,706,501 (per year).
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 the
EPA's regulations in 40 CFR are listed in 40 CFR part 9.
Submit your comments on the agency's need for this information, the
accuracy of the provided burden estimates, and any suggested methods
for minimizing respondent burden to the EPA using the docket identified
at the beginning of this rule. You may also send your ICR-related
comments to OMB's Office of Information and Regulatory Affairs via
email to [email protected], Attention: Desk Officer for the
EPA. Since OMB is required to make a decision concerning the ICR
between 30 and 60 days after receipt, OMB must receive comments no
later than November 23, 2015. The EPA will respond to any ICR-related
comments in the final rule.
C. Regulatory Flexibility Act (RFA)
Pursuant to section 603 of the RFA, the EPA prepared an initial
regulatory flexibility analysis (IRFA) that examines the impact of the
proposed rule on small entities along with regulatory alternatives that
could minimize that impact. The complete IRFA is available for review
within the RIA in docket EPA-HQ-OAR-2015-0199 and is summarized here.
The small entities subject to the requirements of this proposed
rule may include privately-owned and publicly-owned entities, and rural
electric cooperatives that are majority owners of affected EGUs. The
EPA conducted this regulatory flexibility analysis at the highest level
of ownership, evaluating parent entities with the largest share of
ownership in at least one potentially-affected EGU included in EPA's
Base Case using the IPM v.5.15, used in the RIA for this proposed rule.
This analysis drew on parsed unit-level estimates using IPM results for
2030.
The EPA identified 223 potentially affected EGUs owned by 74 small
entities included in 2030 projections from EPA's IPM v.5.15. Fifty-nine
of these potentially affected EGUs are projected to no longer be
operating by 2030 in the Base Case of EPA's version of IPM. Twenty-four
small entities are projected to have all of their potentially affected
EGUs cease operation by 2030 in this base case.
The EPA estimated net compliance costs for individual EGUs for the
proposed rule using components for operating and annualized capital
costs, fuel costs, demand-side energy efficiency program costs, and
revenue changes. This approach is consistent with previous proposed
power sector regulations, but also adds the additional component of
change in demand-side energy efficiency program costs. Investment in
demand-side energy efficiency results in lower electricity demand, and
consequently fewer emissions as production is reduced to meet the lower
demand, an important emission-reduction strategy modeled in the rate-
based and mass-based federal plan approaches. For this analysis, the
EPA used the parsed unit-level estimates to estimate three of the four
components of the net compliance cost equation using IPM outputs: The
change in operating and annualized capital costs, the change in fuel
costs, and the change in revenue, where all changes are estimated as
the difference between the base case and federal plan scenario. These
impacts were then summed for each small entity, adjusting for ownership
share. An additional analysis was performed outside of EPA's IPM model
to estimate the change in demand-side energy efficiency program costs,
based largely on IPM-projected outputs.
As noted earlier, there are 74 small entities with potentially
affected EGUs that are modeled in the IPM base case in 2030. Of these,
24 small entities are projected to withdraw all of their potentially
affected EGUs from operation under base case conditions. This leaves 50
small entities with potentially affected EGUs that are projected to be
generating electricity in 2030. Under the rate-based federal plan
approach, 7 of these 50 small entities are projected to withdraw all of
their potentially affected EGUs from operation by 2030. Under the mass-
based federal plan approach, 5 of these 50 small entities are projected
withdraw all of their potentially affected EGUs from operation by 2030.
Under the rate-based federal plan approach, 23 small entities are
projected to incur net compliance costs greater than 3 percent of
generation revenues from their potentially affected EGUs. In contrast,
9 entities are estimated to have net compliance cost savings greater
than 3 percent of their generation revenues from affected EGUs. Under
the mass-based federal plan approach, 21 small entities are projected
to incur net compliance costs greater than 3 percent of generation
revenues from their potentially affected EGUs. In contrast, 11 entities
are estimated to have net compliance cost savings greater than 3
percent of generation revenues from their affected EGUs.
There are uncertainties and limitations in this analysis that may
result in estimates that diverge from what we might see in reality. For
example, at the time of this proposal,
[[Page 65056]]
the EPA has no information on whether any or how many states will
require a federal plan. The rate-based and mass-based federal plan
approaches analyzed in this IRFA are based on a scenario where all
states of the contiguous United States will be regulated under a
federal plan. Another factor to consider is that entities operating in
regulated or cost-of-service markets are likely able to recover
compliance costs through rate adjustments; as a result these costs can
be viewed as likely being over-estimates for this set of utilities.
Other uncertainties and data limitations exist and are described in the
complete IRFA available for review within the RIA for this proposal.
As discussed earlier in this preamble, the reporting, recordkeeping
and other compliance requirements are most likely covered under 40 CFR
part 75 and part 98 programs for affected EGUs. Therefore, only a
marginal additional cost is expected for the monitoring, reporting and
recordkeeping requirements of the proposed federal plan for affected
EGUs.
Owners of affected EGUs may be subject to other related rules. For
example, on September 20, 2013, the EPA proposed carbon pollution
standards for new fossil fuel fired EGUs. On June 2, 2014, the EPA
proposed carbon pollution standards for modified and reconstructed
fossil fuel-fired EGUs, in addition to the Clean Power Plan EGs, to cut
carbon pollution from existing fossil fuel-fired EGUs. These existing
EGUs are, or will be, potentially impacted by several other recently
finalized EPA rules. On February 16, 2012, the EPA issued the mercury
and air toxics standards (MATS) rule (77 FR 9304) to reduce emissions
of toxic air pollutants from new and existing coal- and oil-fired EGUs.
On May 19, 2014, the EPA issued a final rule under section 316(b) of
the Clean Water Act (33 U.S.C. 1326(b)). This rule establishes new
standards to reduce injury and death of fish and other aquatic life
caused by cooling water intake structures at existing power plants and
manufacturing facilities. On June 18, 2014 (79 FR 34830), the EPA
promulgated the stream electric effluent limitation guidelines (SE ELG)
rule to strengthen the controls on discharges from certain steam
electric power plants. On April 17, 2015 (80 FR 21302), the EPA
promulgated the coal combustion residuals (CCR) rule, which establishes
technical requirements for CCR landfills and surface impoundments under
subtitle D of the Resource Conservation and Recovery Act (RCRA), the
nation's primary law for regulating solid waste.
As required by section 609(b) of the RFA, the EPA also convened a
Small Business Advocacy Review (SBAR) Panel to obtain advice and
recommendations from small entity representatives that potentially
would be subject to the rule's requirements. The SBAR Panel evaluated
the assembled materials and small-entity comments on issues related to
elements of an IRFA. A copy of the full SBAR Panel Report is available
in the rulemaking docket.
The EPA also considered whether the separate changes that we are
proposing to make, as explained in section VII of this preamble, to the
framework regulations in subpart B of part 60 of the CAA regulations
would have any impacts on small entities. Since these changes only
modify and enhance the procedures that the Administrator will follow in
processing state plans and promulgating a federal plan, and do not
alter the rules or requirements that states or regulated entities must
follow, the agency does not believe that there will be economic impacts
on small entities from this portion of this proposal. After considering
the economic impacts of the proposed changes to 40 CFR 60.27, I certify
those changes will not have a significant economic impact on a
substantial number of small entities.
D. Unfunded Mandates Reform Act (UMRA)
This action contains a federal mandate under UMRA, 2 U.S.C. 1531-
1538, that could potentially result in expenditures of $100 million or
more for state, local, and tribal governments, in the aggregate, or the
private sector in any 1 year. This federal plan will apply only to
those affected EGUs located in states that do not submit approvable
state plans, which is a subset of the EGUs considered in the RIA for
the final EGs (see RIA for this proposal for further discussion of
impacts). Because it is impossible to determine at this time which
states might be ultimately subject to a federal plan, the EPA cannot
determine whether this rule, when finalized, will be subject to UMRA.
However, as noted below, the agency has done substantial outreach to
government entities as part of both the federal plan and the related
CAA section 111(d) rulemaking. Further, regardless of whether the EPA
does determine that this action ultimately meets the UMRA threshold,
the agency intends to do additional outreach with government entities
between now and the final rule. Additionally, the EPA has determined
that this action 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.
Nevertheless, the EPA is aware that there is substantial interest
in this rule among small entities (e.g., municipal and rural electric
cooperatives). In light of this interest, prior to this action, the EPA
sought early input from representatives of small entities while
formulating the provisions of the proposed regulation. Such outreach is
also consistent with the President's January 18, 2011 Memorandum on
Regulatory Flexibility, Small Business, and Job Creation, which
emphasizes the important role small businesses play in the American
economy. This outreach process has enabled the EPA to hear directly
from these representatives, as the EPA developed the rule about how the
EPA should approach the complex question of how to apply section 111 of
the CAA to the regulation of GHGs from these source categories. We
invite comments on all aspects of this proposal and its impacts,
including potential adverse impacts, on small entities.
E. Executive Order 13132: Federalism
The EPA believes that this proposed rule may be of significant
interest to state and local governments due to its relationship with
the Clean Power Plan EGs. Therefore, the EPA has determined that
consultations with state and local governments conducted during the
Clean Power Plan EGs development process are also relevant to this
proposed rule. Consistent with the EPA's policy to promote
communications between the EPA and state and local governments, the EPA
consulted with state and local officials early in the process of
developing the Clean Power Plan EGs to permit them to have meaningful
and timely input into its development. As described in the Federalism
discussion in the preamble to the proposed standards of performance for
GHG emissions from new EGUs (79 FR 1501; January 8, 2014), the EPA
consulted with state and local officials in the process of developing
the proposed standards for newly constructed EGUs. A detailed
Federalism Summary Impact Statement (FSIS) describing the most pressing
issues raised in pre-proposal and post-proposal comments will be
forthcoming with the final Clean Power Plan EGs, as required by section
6(b) of Executive Order 13132. In the spirit of Executive Order 13132,
and consistent with the EPA's policy to promote communications between
the EPA and state and local governments, the EPA specifically solicits
comment on this
[[Page 65057]]
proposed action from state and local officials.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
This proposed action has tribal implications. However, it will
neither impose substantial direct compliance costs on federally
recognized tribal governments, nor preempt tribal law. The EGUs
potentially impacted by this proposed rulemaking located on Indian
reservations are primarily owned by private entities, and in one case,
partially owned by an agency of the U.S. government. As a result, the
tribes on whose areas of Indian country those units are located will
not be directly impacted by any costs of complying with this proposed
rulemaking incurred by the owners/operators of those units. There would
only be tribal implications in regards to compliance costs associated
with this proposed rulemaking in the case where a tribal government has
an ownership interest in a potentially affected EGU. A tribal
government could also incur costs in the event that it seeks and is
given delegated authority to enforce the federal plan proposed in this
rulemaking. The EPA has, nevertheless, offered consultation to the
tribes on whose areas of Indian country the units are located. As part
of its general outreach to tribes regarding this proposed rulemaking,
the EPA received feedback from a number of tribes regarding the
potential overall economic impact that both the proposed Clean Power
Plan and a proposed federal plan rulemaking may have on them. In these
instances, the EPA has reached out to these tribes and as part of the
consultation on the Clean Power Plan engaged with them on their
concerns regarding a potential federal plan.
The EPA has conducted consultation with tribes on the Clean Power
Plan and the Supplemental Proposal for the Clean Power Plan and will
offer all tribes consultation on this proposed action. The EPA held
consultations with tribes on the Clean Power Plan in the fall of 2014
before the agency issued its Supplemental Proposal for Indian country
and U.S. Territories. Additionally, the EPA held consultations for
tribes shortly following the release of the supplemental proposal. The
agency also held a public hearing on the supplemental proposal on
November 19, 2014, in Phoenix, Arizona. At the public hearing the
agency received oral comments from community members representing a
number of tribes and a number of tribal officials. The agency also
conducted consultations with tribes in the spring and summer of 2015.
An overview of the consultations provided as part of the Clean Power
Plan is available in section XII.F of the final EGs.
Additionally, the EPA engaged in meaningful dialogue with tribal
stakeholders to obtain their feedback in the pre-proposal stages of
this rulemaking. We provided an update on this proposed rulemaking on
the May 28, 2015, National Tribal Air Association and the EPA Air
Policy call. Staff attended the National Tribal Forum conference on May
20, 2015 and provided an overview of the Clean Power Plan and explained
that the agency would be proposing a federal plan.
Consistent with previous rulemakings impacting the power sector,
there is significant tribal interest in these rulemakings because of
the potential indirect impacts that rules such as the Clean Power Plan
and this proposed federal plan may have on tribes. The EPA specifically
solicits additional feedback from tribal officials on all aspects of
this proposed rulemaking, including whether tribes whose areas of
Indian country contain affected EGU(s) are interested in developing
their own plan implementing the final EGs. Additionally, tribal
stakeholders will be included in the outreach that the agency will be
conducting with those communities already overburdened by pollution,
which are often low-income communities, communities of color, and
indigenous communities. The actions that the agency will be taking are
outlined in section IX of this preamble.
G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
The EPA interprets EO 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 EO 13045 because it does not involve decisions on
environmental health or safety risks that may disproportionately affect
children. The EPA believes that the CO2 emission reductions
resulting from implementation of the proposed federal plan, as well as
substantial ozone and PM2.5 emission reductions as a
cobenefit, would further improve children's health.
H. Executive Order 13211: Actions That Significantly Affect Energy
Supply, Distribution, or Use
This action, which is a significant regulatory action under EO
12866, is likely to have a significant effect on the supply,
distribution, or use of energy. The EPA has prepared a Statement of
Energy Effects for this action as follows. We estimate a 1 to 2 percent
change in retail electricity prices on average across the contiguous
United States in 2025, and a 22 to 23 percent reduction in coal-fired
electricity generation as a result of this rule. The EPA projects that
utility power sector delivered natural gas prices will increase by up
to 2.5 percent in 2030. For more information on the estimated energy
effects, please refer to the economic impact analysis for this
proposal. The analysis is available in the RIA, which is in the public
docket.
I. National Technology Transfer and Advancement Act (NTTAA) and 1 CFR
Part 51
This proposed action involves technical standards. The EPA proposes
to recognize ANSI accreditation under ISO 14065 for GHG validation and
verification bodies as a component of accreditation of independent
verifiers under both proposed federal plan approachs. The EPA also
proposes that net energy output measurements must be performed using
0.2 accuracy class electricity metering instrumentation and calibration
procedures as specified under ANSI Standards No. C12.20.
J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
Executive Order 12898 (59 FR 7629; February 16, 1994) establishes
federal executive policy on environmental justice (EJ). Its main
provision directs federal agencies, to the greatest extent practicable
and permitted by law, to make EJ 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 populations and low-income populations in the
United States. The EPA defines EJ as the fair treatment and meaningful
involvement of all people regardless of race, color, national origin,
or income with respect to the development, implementation, and
enforcement of environmental laws, regulations, and policies. The EPA
has this goal for all communities and persons across this Nation. It
will be achieved when everyone enjoys the
[[Page 65058]]
same degree of protection from environmental and health hazards and
equal access to the decision-making process to have a healthy
environment in which to live, learn, and work.
Leading up to this rulemaking the EPA summarized the public health
and welfare effects of GHG emissions in its 2009 Endangerment Finding.
As part of the Endangerment Finding, the Administrator considered
climate change risks to minority populations and low-income
populations, finding that certain parts of the population may be
especially vulnerable based on their characteristics or circumstances.
Populations that were found to be particularly vulnerable to climate
change risks include the poor, the elderly, the very young, those
already in poor health, the disabled, those living alone, and/or
indigenous populations dependent on one or a few resources. See
sections X.F and X.G of this preamble, above, where the EPA discusses
Consultation and Coordination with Tribal Governments and Protection of
Children. The Administrator placed weight on the fact that certain
groups, including children, the elderly, and the poor, are most
vulnerable to climate-related health effects.
The record for the 2009 Endangerment Finding summarizes the strong
scientific evidence in the major assessment reports by the U.S. Global
Change Research Program, the Intergovernmental Panel on Climate Change
(IPCC), and the National Research Council of the National Academies
that the potential impacts of climate change raise EJ issues. These
reports concluded that poor communities can be especially vulnerable to
climate change impacts because they tend to have more limited adaptive
capacities and are more dependent on climate-sensitive resources such
as local water and food supplies. In addition, Native American tribal
communities possess unique vulnerabilities to climate change,
particularly those impacted by degradation of natural and cultural
resources within established reservation boundaries and threats to
traditional subsistence lifestyles. Tribal communities whose health,
economic well-being, and cultural traditions that depend upon the
natural environment will likely be affected by the degradation of
ecosystem goods and services associated with climate change. The 2009
Endangerment Finding record also specifically noted that Southwest
native cultures are especially vulnerable to water quality and
availability impacts. Native Alaskan communities are already
experiencing disruptive impacts, including coastal erosion and shifts
in the range or abundance of wild species crucial to their livelihoods
and well-being.
The most recent assessments continue to strengthen scientific
understanding of climate change risks to minority populations and low-
income populations in the United States.\154\ The new assessment
literature provides more detailed findings regarding these populations'
vulnerabilities and projected impacts they may experience. In addition,
the most recent assessment reports provide new information on how some
communities of color may be uniquely vulnerable to climate change
health impacts in the United States. These reports find that certain
climate change related impacts--including heat waves, degraded air
quality, and extreme weather events--have disproportionate effects on
low-income populations and some communities of color (in particular,
populations defined jointly by ethnic/racial characteristics and
geographic location), raising EJ concerns. Existing health disparities
and other inequities in these communities increase their vulnerability
to the health effects of climate change. In addition, assessment
reports also find that climate change poses particular threats to
health, well-being, and ways of life of indigenous peoples in the
United States.
---------------------------------------------------------------------------
\154\ Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W.
Yohe, Eds., 2014: Climate Change Impacts in the United States: The
Third National Climate Assessment. U.S. Global Change Research
Program, 841 pp.
IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and
Vulnerability. Part A: Global and Sectoral Aspects. Contribution of
Working Group II to the Fifth Assessment Report of the
Intergovernmental Panel on Climate Change [Field, C.B., V.R. Barros,
D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. Chatterjee,
K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N.
Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)].
Cambridge University Press, 1132 pp.
IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and
Vulnerability. Part B: Regional Aspects. Contribution of Working
Group II to the Fifth Assessment Report of the Intergovernmental
Panel on Climate Change [Barros, V.R., C.B. Field, D.J. Dokken, M.D.
Mastrandrea, K.J. Mach, T.E. Bilir, M. Chatterjee, K.L. Ebi, Y.O.
Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. Levy, S.
MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. Cambridge
University Press, 688 pp.
---------------------------------------------------------------------------
As the scientific literature presented above and as the 2009
Endangerment Finding illustrates, low-income populations and some
communities of color are especially vulnerable to the health and other
adverse impacts of climate change. The EPA believes that communities
will benefit from this proposed federal plan because this action
directly addresses the impacts of climate change by limiting GHG
emissions through the establishment of CO2 emission
standards for existing affected fossil fuel-fired EGUs.
In addition to reducing CO2 emissions, the guidelines
finalized in this rulemaking would reduce other emissions from affected
EGUs that reduce generation due to higher adoption of EE and RE. These
emission reductions will include SO2 and NOX,
which form ambient PM2.5 and ozone in the atmosphere, and
HAP, such as mercury and hydrochloric acid. In the final rule revising
the annual PM2.5 NAAQS,\155\ the EPA identified low-income
populations as being a vulnerable population for experiencing adverse
health effects related to PM exposures. Low-income populations have
been generally found to have a higher prevalence of pre-existing
diseases, limited access to medical treatment, and increased
nutritional deficiencies, which can increase this population's
susceptibility to PM-related effects.\156\ In areas where this
rulemaking reduces exposure to PM2.5, ozone, and
methylmercury, low-income populations will also benefit from such
emission reductions. The RIA for this rulemaking, included in the
docket for this rulemaking, provides additional information regarding
the health and ecosystem effects associated with these emission
reductions.
---------------------------------------------------------------------------
\155\ ``National Ambient Air Quality Standards for Particulate
Matter, Final Rule,'' 78 FR 3086 (January 15, 2013).
\156\ U.S. Environmental Protection Agency (U.S. EPA). 2009.
Integrated Science Assessment for Particulate Matter (Final Report).
EPA-600-R-08-139F. National Center for Environmental Assessment--RTP
Division. December. Available on the Internet at http://www.cfpub.epa.gov/si/si_public_record_Report.cfm?dirEntryId=216546.
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Additionally, as outlined in the community and EJ considerations
section IX of this preamble, the EPA has taken a number of actions to
help ensure that this action will not have potential disproportionately
high and adverse human health or environmental effects on vulnerable
communities. The EPA consulted its May 2015, Guidance on Considering
Environmental Justice During the Development of Regulatory Actions,
when determining what actions to take.\157\ As described in section IX
of this preamble (community and EJ considerations), the EPA also
conducted a proximity analysis, which is available in the docket of
this rulemaking and is discussed in section IX of this preamble.
Additionally, as outlined in sections I and IX of this preamble the EPA
has
[[Page 65059]]
engaged meaningfully with communities throughout the development of the
Clean Power Plan and has devised a robust outreach strategy for
continual engagement throughout this rulemaking.
---------------------------------------------------------------------------
\157\ Guidance on Considering Environmental Justice During the
Development of Regulatory Actions. http://www.epa.gov/environmentaljustice/resources/policy/considering-ej-in-rulemaking-guide-final.pdf. May 2015.
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List of Subjects
40 CFR Part 60
Environmental protection, Administrative practice and procedure,
Air pollution control, Intergovernmental relations.
40 CFR Part 62
Environmental protection, Administrative practice and procedure,
Air pollution control, Incorporation by reference, Intergovernmental
relations, Reporting and recordkeeping requirements.
40 CFR Part 78
Environmental protection, Administrative practice and procedure,
Air pollution control.
Dated: August 3, 2015.
Gina McCarthy,
Administrator.
For the reasons stated in the preamble, title 40, chapter I, parts
60, 62, and 78 of the Code of the Federal Regulations is amended as
follows:
PART 60--STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES
0
1. The authority citation for part 60 continues to read as follows:
Authority: 42 U.S.C. 7401 et seq.
0
2. Section 60.27 is amended by:
0
a. Revising paragraphs (b), (c) introductory text, and (c)(1);
0
b. Removing and reserving paragraph (c)(2);
0
c. Revising paragraphs (c)(3), (d), and (e)(1); and
0
d. Adding paragraphs (g) through (k).
The revisions and additions read as follows:
Sec. 60.27 Actions by the Administrator.
* * * * *
(b) After receipt of a complete plan or complete plan revision, the
Administrator will propose the plan or revision for approval or
disapproval. The Administrator shall, within 12 months after the date
on which the submission of a complete plan or complete plan revision is
received, approve or disapprove such plan or revision, or each portion
thereof.
(c) The Administrator shall promulgate a federal plan within 12
months after the date the Administrator:
(1) Finds the State failed to submit a complete plan or complete
plan revision within the time prescribed; or
* * * * *
(3) Disapproves the State plan or plan revision or any portion
thereof, as unsatisfactory because the requirements of this subpart and
the applicable emission guidelines have not been met.
(d) The Administrator will promulgate the regulations under
paragraph (c) of this section for all or a portion of a federal plan,
with such modifications as may be appropriate, unless, prior to such
promulgation, the State has adopted and submitted a plan or plan
revision which the Administrator approves. After the promulgation of a
federal plan, the Administrator may approve a State plan or plan
revision or portion thereof and withdraw all or a portion of the
federal plan.
(e)(1) Except as provided in paragraph (e)(2) of this section,
regulations promulgated by the Administrator under this section will
prescribe emission standards of the same stringency as the
corresponding emission guideline(s) specified in the final guideline
document published under Sec. 60.22(a) and will require final
compliance with such standards as expeditiously as practicable but no
later than the times specified in the guideline document.
* * * * *
(g) Completeness criteria--(1) General. Within 60 days of the
Administrator's receipt of a state submission, but no later than 6
months after the date, if any, by which a State is required to submit
the plan or revision, the Administrator shall determine whether the
minimum criteria for completeness have been met. Any plan or plan
revision that a State submits to the EPA, and that has not been
determined by the EPA by the date 6 months after receipt of the
submission to have failed to meet the minimum criteria, shall on that
date be deemed by operation of law to meet such minimum criteria. Where
the Administrator determines that a plan submission does not meet the
minimum criteria of this paragraph (g), the State will be treated as
not having made the submission.
(2) Administrative criteria. In order to be complete, a State plan
must contain each of the following administrative criteria:
(i) A formal letter of submittal from the Governor or her designee
requesting EPA approval of the plan or revision thereof;
(ii) Evidence that the State has adopted the plan in the state code
or body of regulations. That evidence must include the date of adoption
or final issuance as well as the effective date of the plan, if
different from the adoption/issuance date;
(iii) Evidence that the State has the necessary legal authority
under state law to adopt and implement the plan;
(iv) A copy of the actual regulation, or document submitted for
approval and incorporation by reference into the plan. The submittal
must be a copy of the official state regulation or document signed,
stamped and dated by the appropriate state official indicating that it
is fully enforceable by the State. The effective date of the regulation
or document must, whenever possible, be indicated in the document
itself. The State's electronic copy must be an exact duplicate of the
hard copy. For revisions to the approved plan, the submittal must
indicate the changes made (for example, by redline/strikethrough) to
the approved plan;
(v) Evidence that the State followed all of the procedural
requirements of the state's laws and constitution in conducting and
completing the adoption and issuance of the plan;
(vi) Evidence that public notice was given of the proposed change
with procedures consistent with the requirements of Sec. 60.23,
including the date of publication of such notice;
(vii) Certification that public hearing(s) were held in accordance
with the information provided in the public notice and the State's laws
and constitution, if applicable and consistent with the public hearing
requirements in Sec. 60.23;
(viii) Compilation of public comments and the State's response
thereto; and
(ix) Such other criteria for completeness as may be specified by
the Administrator under the applicable emission guidelines.
(3) Technical criteria. In order to be complete, a State plan must
contain each of the following technical criteria:
(i) Description of the plan approach and geographic scope;
(ii) Identification of each affected source, identification of
emission standards for the affected sources, and monitoring,
recordkeeping and reporting requirements that will determine compliance
by each affected source;
(iii) Identification of compliance schedules and/or increments of
progress;
(iv) Demonstration that the State plan submittal is projected to
achieve emissions performance under the applicable emission guidelines;
(v) Documentation of state recordkeeping and reporting
[[Page 65060]]
requirements to determine the performance of the plan as a whole; and
(vi) Demonstration that each emission standard is quantifiable,
non-duplicative, permanent, verifiable, and enforceable.
(4) Parallel processing. A State may submit a State plan prior to
actual adoption by the State in order to expedite review and provide an
opportunity for the State to consider EPA comments prior to submission
of a final plan for final review and action. Under these circumstances,
the following exceptions to the criteria in this paragraph apply to
plans submitted explicitly for parallel processing:
(i) The letter required by paragraph (g)(2)(i) of this section must
request that EPA propose approval of the proposed plan by parallel
processing;
(ii) In lieu of paragraph (g)(2)(ii) of this section the State must
submit a schedule for final adoption or issuance of the plan;
(iii) In lieu of paragraph (g)(2)(iv) of this section the plan must
include a copy of the proposed/draft regulation or document, including
indication of the proposed changes to be made to the existing approved
plan, where applicable; and
(iv) The requirements of paragraphs (g)(2)(v) through (ix) of this
section do not apply to plans submitted for parallel processing. The
exceptions granted in the preceding sentence apply only to EPA's
determination of proposed action and all requirements of paragraph
(g)(2) of this section must be met prior to publication of EPA's final
determination of plan approvability.
(h) Full and partial approval and disapproval. If a portion of the
plan revision meets all the applicable requirements of this chapter,
the Administrator may approve the plan revision in part and disapprove
the plan revision in part. The Administrator may authorize partial plan
submissions in conjunction with a federal plan, where in combination,
the federal and State plans constitute a complete and approvable plan
meeting all of the requirements of this subpart and the applicable
emissions guidelines.
(i) Conditional approval. The Administrator may approve a plan or a
plan revision based on a commitment of the State, by a date certain
established by the Administrator, to adopt specific enforceable
measures, review and revise if appropriate State plans, or otherwise
commit to making changes in the State's plan necessary to meet the
requirements of the applicable emission guidelines. Any such
conditional approval automatically converts to a disapproval if the
State fails to comply with such commitment by the date certain
established by the Administrator.
(j) Calls for plan revisions. Whenever the Administrator finds that
the applicable plan is substantially inadequate to meet the
requirements of the applicable emission guidelines, to provide for the
implementation of such plan, or to otherwise comply with any
requirement of the Clean Air Act, the Administrator must require the
State to revise the plan as necessary to correct such inadequacies. The
Administrator must notify the State of the inadequacies, and may
establish reasonable deadlines (not to exceed 18 months after the date
of such notice) for the submission of such plan revisions. Such
findings and notice must be public. Any finding under this paragraph
shall, to the extent the Administrator deems appropriate, subject the
State to the requirements of this part to which the State was subject
when it developed and submitted the plan for which such finding was
made, except that the Administrator may adjust any dates applicable
under such requirements as appropriate.
(k) Error corrections. Whenever the Administrator determines that
the Administrator's action approving, disapproving, or promulgating any
plan or plan revision (or portion thereof) was in error, the
Administrator may in the same manner as the approval, disapproval, or
promulgation revise such action as appropriate without requiring any
further submission from the State. Such determination and the basis
thereof shall be provided to the State and public.
PART 62--APPROVAL AND PROMULGATION OF STATE PLANS FOR DESIGNATED
FACILITIES AND POLLUTANTS
0
3. The authority citation for part 62 continues to read as follows:
Authority: 42 U.S.C. 7401 et seq.
0
4. Add subpart MMM to read as follows:
Subpart MMM--Greenhouse Gas Emissions Mass-based Model Trading Rule for
Electric Utility Generating Units That Commenced Construction on or
Before January 8, 2014
Introduction
Sec.
62.16205 What is the purpose of this subpart?
Applicability of This Subpart
62.16210 Am I subject to this subpart?
62.16215 What requirements apply to affected EGUs that retire?
General Requirements
62.16220 What requirements must I comply with?
62.16225 How should I compute time under the CO2 Mass-
based Trading Program?
62.16230 What are the administrative appeal procedures?
62.16231 How will the Clean Energy Incentive Program be administered
under the federal plan?
Emission Goals, Set-Asides, and Allowance Allocations
62.16235 What are the statewide mass-based emission goals, renewable
energy set-asides, output-based set-asides, and Clean Energy
Incentive Program early action set-asides?
62.16240 When are allowances allocated?
62.16245 How are set-aside allowances allocated?
62.16250 What is the process for revocation of qualification status
of an eligible resource?
62.16255 What is the process for error adjustments or misstatement,
and suspension of allowance issuance?
Evaluation Measurement and Verification Plans, Monitoring and
Verification Reports, and Verification
62.16260 What are the requirements for evaluation, measurement and
verification plans for eligible resources?
62.16265 What are the requirements for monitoring and verification
reports for eligible resources?
62.16270 What are the requirements for verification reports?
62.16275 What is the accreditation procedure for independent
verifiers?
62.16280 What are the procedures accredited independent verifiers
must follow to avoid conflict of interest?
62.16285 What is the process for the revocation of accreditation
status for an independent verifier?
Designated Representatives
62.16290 How are designated representatives and alternate designated
representatives authorized and what role do authorized designated
representatives and alternate designated representatives play?
62.16295 What responsibilities do designated representatives and
alternate designated representatives hold?
62.16300 What are the processes for changing designated
representatives, alternate designated representatives, owners and
operators, and affected EGUs at the facility?
62.16305 What must be included in a certificate of representation?
62.16310 What is the Administrator's role in objections concerning
designated representatives and alternate designated representatives?
62.16315 What process must designated representatives and alternate
designated representatives follow to delegate their authority?
Monitoring, Recordkeeping, Reporting
62.16320 How are compliance accounts and general accounts
established?
[[Page 65061]]
62.16325 When will CO2 allowances be recorded in
compliance accounts?
62.16330 How must transfers of CO2 allowances be
submitted?
62.16335 When will CO2 allowance transfers be recorded?
62.16340 How will deductions for compliance with a CO2
emission standard occur?
62.16345 What monitoring requirements must I comply with?
62.16350 May I bank CO2 annual allowances for future use
or transfer?
62.16355 How does the Administrator process account errors?
62.16360 What are my reporting, notification and submission
requirements?
62.16365 What are my recordkeeping requirements?
62.16370 What actions may the Administrator take on submissions?
Definitions
62.16375 What definitions apply to this subpart?
62.16380 What measurements, abbreviations, and acronyms apply to
this subpart?
Subpart MMM--Greenhouse Gas Emissions Mass-based Model Trading Rule
for Electric Utility Generating Units That Commenced Construction
on or Before January 8, 2014
Introduction
Sec. 62.16205 What is the purpose of this subpart?
(a) This subpart sets forth the requirements for the Clean Power
Plan (CPP) CO2 Mass-based Trading Program, under section 111
of the Clean Air Act and subpart UUUU of part 60 of this chapter, as a
means of meeting emission guidelines limiting greenhouse gas emissions
from an affected steam generating unit, integrated gasification
combined cycle (IGCC), or stationary combustion turbine.
(b) The pollutants regulated by this subpart are greenhouse gases.
The greenhouse gas limitations in this subpart are in the form of an
emission standard for carbon dioxide (CO2).
(c) PSD and title V thresholds for greenhouse gases. (1) For the
purposes of Sec. 51.166(b)(49)(ii) of this chapter, with respect to
GHG emissions from affected facilities, the ``pollutant that is subject
to the standard promulgated under section 111 of the Act'' is
considered to be the pollutant that otherwise is subject to regulation
under the Act as defined in Sec. 51.166(b)(48) and in any state
implementation plan approved by the EPA that is interpreted to
incorporate, or specifically incorporates, Sec. 51.166(b)(48) of this
chapter.
(2) For the purposes of Sec. 52.21(b)(50)(ii) of this chapter,
with respect to GHG emissions from affected facilities, the ``pollutant
that is subject to the standard promulgated under section 111 of the
Act'' is considered to be the pollutant that otherwise is subject to
regulation under the Act as defined in Sec. 52.21(b)(49) of this
chapter.
(3) For the purposes of Sec. 70.2 of this chapter, with respect to
greenhouse gas emissions from affected facilities, the ``pollutant that
is subject to any standard promulgated under section 111 of the Act''
is considered to be the pollutant that otherwise is ``subject to
regulation'' as defined in Sec. 70.2 of this chapter.
(4) For the purposes of Sec. 71.2 of this chapter, with respect to
greenhouse gas emissions from affected facilities, the ``pollutant that
is subject to any standard promulgated under section 111 of the Act''
is considered to be the pollutant that otherwise is ``subject to
regulation'' as defined in Sec. 71.2 of this chapter.
Applicability of this Subpart
Sec. 62.16210 Am I subject to this subpart?
(a) You are subject to this subpart if you are the owner or
operator of an affected electric generating unit (EGU) located within a
State that has incorporated by reference this subpart as a State plan,
or portion of a State plan, that has been approved by the Administrator
and is effective under subpart UUUU of part 60 of this chapter, or if
this subpart is promulgated and effective as a federal plan in your
State under part 62 of this chapter.
(b) An affected EGU is any steam generating unit, IGCC, or
stationary combustion turbine that meets the applicability requirements
in Sec. Sec. 60.5840(b) and 60.5845 of this chapter.
Sec. 62.16215 What requirements apply to affected EGUs that retire?
(a) Exemption. (1) Any affected EGU that is permanently retired as
defined in Sec. 62.16375 is exempt from Sec. Sec. 62.16220(c)(1)
[CO2 Emissions Requirements], 62.16340 [Compliance
Requirements], 62.16345 [Monitoring], 62.16360 [Reporting], and
62.16365 [Recordkeeping].
(2) The exemption under paragraph (a)(1) of this section will
become effective on the first day of the compliance period immediately
following the compliance period in which the retirement took effect.
Within 30 days of the affected EGU's permanent retirement, the
designated representative must submit a statement to the Administrator.
The statement must state, in a format prescribed by the Administrator,
that the affected EGU was permanently retired on a specified date and
will comply with the requirements of paragraph (b) of this section.
(b) Special provisions. (1) An affected EGU exempt under paragraph
(a) of this section must not emit any CO2, 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 an affected EGU exempt under paragraph (a)
of this section must retain, at the facility that includes the unit,
records demonstrating that the affected EGU 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 affected EGU is
permanently retired.
(3) The owners and operators and, to the extent applicable, the
designated representative of an affected EGU exempt under paragraph (a)
of this section must comply with the requirements of the CO2
Mass-based Trading Program accruing during any compliance periods for
which the exemption is not in effect, even if such requirements must be
complied with after the exemption takes effect.
General Requirements
Sec. 62.16220 What requirements must I comply with?
(a) Designated representative requirements. The owners and
operators must have a designated representative, and may have an
alternate designated representative, in accordance with Sec. Sec.
62.16290 through 62.16300.
(b) Emissions monitoring, reporting, and recordkeeping
requirements. (1) The owners and operators, and the designated
representative, of each facility and each affected EGU at the facility
must comply with the monitoring, reporting, and recordkeeping
requirements of Sec. Sec. 62.16345, 62.16360, and 62.16365.
(2) The emissions data determined in accordance with Sec. Sec.
62.16345, 62.16360, and 62.16365 must be used to calculate allocations
of CO2 allowances under Sec. 62.16240(a) and (b) and to
determine compliance with the CO2 emission standard 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 must be the mass emissions amount for the monitoring
location determined in accordance with
[[Page 65062]]
Sec. 62.16345 and rounded to the nearest ton.
(c) CO2 emission standard requirements--(1) CO2 emission
standard. (i) As of the allowance transfer deadline for a compliance
period in a given year, the owners and operators of each facility and
each affected EGU at the facility with affected EGUs must hold, in the
facility's compliance account, CO2 allowances available for
deduction for such compliance period under Sec. 62.16340(a) in an
amount not less than the tons of total CO2 emissions for
such compliance period from all affected EGUs at the facility.
(ii) If total CO2 emissions during a compliance period
in a given year from the affected EGUs at a facility are in excess of
the CO2 emission standard set forth in paragraph (c)(1)(i)
of this section, then:
(A) The owners and operators of the facility and each affected EGU
at the facility must hold the CO2 allowances required for
deduction under Sec. 62.16340(d); and
(B) The owners and operators of the facility and each affected EGU
at the facility are subject to federal enforcement pursuant to sections
113(a) through (h), and section 304, of the Clean Air Act, and the
United States, States, and other persons have the ability to enforce
against violations (including if an affected EGU does not meet its
emission standard based on its allowances) and secure appropriate
corrective actions, and must pay any fine, penalty, or assessment or
comply with any other remedy imposed, for the same violations, under
the Clean Air Act, and each ton of such excess emissions and each day
of such compliance period will constitute a separate violation of this
subpart and the Clean Air Act.
(2) Compliance periods. (i) An affected EGU will be subject to the
requirements under paragraph (c)(1) of this section for the compliance
period starting on January 1, 2022 and for each compliance period
thereafter.
(ii) [Reserved]
(3) Vintage of allowances held for compliance. (i) A CO2
allowance held for compliance with the requirements under paragraph
(c)(1)(i) of this section for a compliance period must be a
CO2 allowance that was allocated for a year in such
compliance period or for a year in a prior compliance period.
(ii) A CO2 allowance held for compliance with the
requirements under paragraph (c)(1)(ii)(A) of this section for a
compliance period must be a CO2 allowance that was allocated
for a year in a prior compliance period, or the current compliance
period, or in the immediately following compliance period.
(4) Allowance Tracking and Compliance System (ATCS) requirements.
Each CO2 allowance must be held in, deducted from, or
transferred into, out of, or between ATCS accounts in accordance with
this subpart.
(5) Limited authorization. A CO2 allowance is a limited
authorization to emit one ton of CO2 during the compliance
period in one year. Such authorization is limited in its use and
duration as follows:
(i) Such authorization must only be used in accordance with the
CO2 Mass-based Trading Program; and
(ii) Notwithstanding any other provision of this subpart, the
Administrator has the authority to terminate or limit the use and
duration of such authorization to the extent the Administrator
determines is necessary or appropriate to implement any provision of
the Clean Air Act.
(6) Property right. A CO2 allowance does not constitute
a property right.
(d) Title V permit requirements. (1) Unless otherwise specified in
this paragraph, all requirements of this subpart are applicable
requirements that must be included in an affected EGU's title V permit.
(2) The applicable requirements of this subpart, as well as other
terms or conditions necessary to ensure compliance with the applicable
requirements, 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 such changes
do not conflict with any existing terms of the permit. This paragraph
explicitly provides that the addition of, or change to, an affected
EGU'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.
(3) No title V permit revision will be required for any allocation,
holding, deduction, or transfer of CO2 allowances in
accordance with this subpart, provided that the requirements applicable
to such allocations, holdings, deductions, or transfers of
CO2 allowances are already incorporated in such permit.
(e) Liability. (1) Any provision of the CO2 Mass-based
Trading Program that applies to an affected EGU at a facility or the
designated representative of affected EGUs at a facility will also
apply to the owners and operators of such facility and of the affected
EGUs at the facility.
(2) Any provision of the CO2 Mass-based Trading Program
that applies to an affected EGU or the designated representative of an
affected EGU will also apply to the owners and operators of such
affected EGU.
(f) Effect on other authorities. No provision of the CO2
Mass-based Trading Program or exemption under Sec. 62.16215 shall be
construed as exempting or excluding the owners and operators, and the
designated representative, of an affected EGU from compliance with any
other provision of the applicable, approved state implementation plan,
a federally enforceable permit, or any other requirement of the Clean
Air Act.
Sec. 62.16225 How should I compute time under the CO2
Mass-based Trading Program?
(a) Unless otherwise stated, any time period scheduled, under the
CO2 Mass-Based Trading Program, to begin on the occurrence
of an act or event will begin on the day the act or event occurs.
(b) Unless otherwise stated, any time period scheduled, under the
CO2 Mass-Based Trading Program, to begin before the
occurrence of an act or event will 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 CO2 Mass-Based Trading Program, is not a business
day, then the time period will be extended to the next business day.
Sec. 62.16230 What are the administrative appeal procedures?
The administrative appeal procedures for decisions of the
Administrator under the CO2 Mass-Based Trading Program are
set forth in part 78 of this chapter.
Sec. 62.16231 How will the Clean Energy Incentive Program be
administered under the federal plan?
(a)(1) The Administrator will participate in the Clean Energy
Incentive Program, established under subpart UUUU of part 60 of this
chapter, on behalf of any state for which this subpart is promulgated
as a federal plan under section 111(d) of the Clean Air Act. The
Administrator will award, on behalf of each such state, early action
allowances for generation and savings achieved in 2020 and/or 2021 that
result from the following types of eligible renewable energy (RE) and
demand-side energy efficiency (EE) projects:
(i) Metered wind power;
(ii) Metered solar power; and
(iii) Demand-side EE implemented in a low-income community.
(2) Eligible RE projects must commence construction, and eligible
demand-side EE projects must
[[Page 65063]]
commence implementation after September 6, 2018 for those states on
whose behalf the EPA is implementing the federal plan. Eligible
projects must be located in or benefit the state on whose behalf the
EPA is implementing the federal plan.
(b) Early action allowances will be distributed pursuant to a
process to be prescribed by the Administrator, from an allowance set-
aside equal to 300 million allowances for all states. This set-aside
does not increase the total budget of allowances for the affected EGUs
in the state subject to this subpart.
(c) The Administrator will match these early action allowances with
additional matching allowances pursuant to a process to be prescribed
by the Administrator. Matching awards will be made up to a limit
equivalent to the state's pro rata share of 300 million short tons of
CO2 emissions.
(d) The awards, including the matching award, will be executed as
follows:
(1) For RE projects that generate metered MWh from wind or solar
resources: for every two MWh generated, the project will receive a
number of early action allowances the Administrator determines to be
equivalent to one MWh from the set-aside under paragraph (b) of this
section and a number of matching allowances the Administrator
determines to be equivalent to one MWh from the match under paragraph
(c) of this section.
(2) For EE projects implemented in low-income communities as
determined by the Administrator solely for purposes of this subpart:
for every two MWh in end-use demand savings achieved, the project will
receive a number of early action allowances the Administrator
determines to be equivalent to two MWh from the set-aside under
paragraph (b) of this section and a number of matching allowances the
Administrator determines to be equivalent to two MWh from the match
under paragraph (c) of this section.
Emission Goals, Set-Asides, and Allowance Allocations
Sec. 62.16235 What are the statewide mass-based emission goals,
renewable energy set-asides, output-based set-asides, and Clean Energy
Incentive Program early action set-asides?
(a) The statewide mass-based emission goals with renewable energy
set-asides and output-based set-asides for allocations of
CO2 allowances for the interim 3- and 2-year compliance
periods in 2022 through 2029, and the final 2-year compliance periods
in 2030 and thereafter are specified in Table 1 of this subpart.
Table 1 to Subpart MMM of Part 62--Statewide Mass-based Emission Goals \1\ (short tons)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Interim period Final period
---------------------------------------------------------------------------------------------------
State 2030-2031 and
Step 1 2022-2024 Step 2 2025-2027 Step 3 2028-2029 thereafter
--------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama............................................. 66,164,470 60,918,973 58,215,989 56,880,474
Arizona............................................. 35,189,232 32,371,942 30,906,226 30,170,750
Arkansas............................................ 36,032,671 32,953,521 31,253,744 30,322,632
California.......................................... 53,500,107 50,080,840 48,736,877 48,410,120
Colorado............................................ 35,785,322 32,654,483 30,891,824 29,900,397
Connecticut......................................... 7,555,787 7,108,466 6,955,080 6,941,523
Delaware............................................ 5,348,363 4,963,102 4,784,280 4,711,825
Florida............................................. 119,380,477 110,754,683 106,736,177 105,094,704
Georgia............................................. 54,257,931 49,855,082 47,534,817 46,346,846
Idaho............................................... 1,615,518 1,522,826 1,493,052 1,492,856
Illinois............................................ 80,396,108 73,124,936 68,921,937 66,477,157
Indiana............................................. 92,010,787 83,700,336 78,901,574 76,113,835
Iowa................................................ 30,408,352 27,615,429 25,981,975 25,018,136
Kansas.............................................. 26,763,719 24,295,773 22,848,095 21,990,826
Kentucky............................................ 76,757,356 69,698,851 65,566,898 63,126,121
Lands of the Fort Mojave Tribe...................... 636,876 600,334 588,596 588,519
Lands of the Navajo Nation.......................... 26,449,393 23,999,556 22,557,749 21,700,587
Lands of the Uintah and Ouray Reservation........... 2,758,744 2,503,220 2,352,835 2,263,431
Louisiana........................................... 42,035,202 38,461,163 36,496,707 35,427,023
Maine............................................... 2,251,173 2,119,865 2,076,179 2,073,942
Maryland............................................ 17,447,354 15,842,485 14,902,826 14,347,628
Massachusetts....................................... 13,360,735 12,511,985 12,181,628 12,104,747
Michigan............................................ 56,854,256 51,893,556 49,106,884 47,544,064
Minnesota........................................... 27,303,150 24,868,570 23,476,788 22,678,368
Mississippi......................................... 28,940,675 26,790,683 25,756,215 25,304,337
Missouri............................................ 67,312,915 61,158,279 57,570,942 55,462,884
Montana............................................. 13,776,601 12,500,563 11,749,574 11,303,107
Nebraska............................................ 22,246,365 20,192,820 18,987,285 18,272,739
Nevada.............................................. 15,076,534 14,072,636 13,652,612 13,523,584
New Hampshire....................................... 4,461,569 4,162,981 4,037,142 3,997,579
New Jersey.......................................... 18,241,502 17,107,548 16,681,949 16,599,745
New Mexico.......................................... 14,789,981 13,514,670 12,805,266 12,412,602
New York............................................ 35,493,488 32,932,763 31,741,940 31,257,429
North Carolina...................................... 60,975,831 55,749,239 52,856,495 51,266,234
North Dakota........................................ 25,453,173 23,095,610 21,708,108 20,883,232
Ohio................................................ 88,512,313 80,704,944 76,280,168 73,769,806
Oklahoma............................................ 47,577,611 43,665,021 41,577,379 40,488,199
Oregon.............................................. 9,097,720 8,477,658 8,209,589 8,118,654
Pennsylvania........................................ 106,082,757 97,204,723 92,392,088 89,822,308
Rhode Island........................................ 3,811,632 3,592,937 3,522,686 3,522,225
South Carolina...................................... 31,025,518 28,336,836 26,834,962 25,998,968
South Dakota........................................ 4,231,184 3,862,401 3,655,422 3,539,481
[[Page 65064]]
Tennessee........................................... 34,118,301 31,079,178 29,343,221 28,348,396
Texas............................................... 221,613,296 203,728,060 194,351,330 189,588,842
Utah................................................ 28,479,805 25,981,970 24,572,858 23,778,193
Virginia............................................ 31,290,209 28,990,999 27,898,475 27,433,111
Washington.......................................... 12,395,697 11,441,137 10,963,576 10,739,172
West Virginia....................................... 62,557,024 56,762,771 53,352,666 51,325,342
Wisconsin........................................... 33,505,657 30,571,326 28,917,949 27,986,988
Wyoming............................................. 38,528,498 34,967,826 32,875,725 31,634,412
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ The values in this table are annual amounts; the mass goal for each multi-year compliance period is the annual value multiplied by the number of
years in the compliance period. Each emission goal includes the renewable energy set-asides and output-based set-asides (the output-based set-asides
are zero in the first compliance period). The first compliance period goals also include the early action Clean Energy Incentive Program set-aside.
(b) If implementing interstate trading, then the Administrator will
use the sum of a covered group of States' mass-based emission goals as
the aggregate mass-based emission goal.
(c) The renewable energy set-aside for each State covered by the
federal mass-based emissions trading plan must reserve 5 percent from
the State's annual allowances prior to allocation of that year's
allowances to facilities. The renewable energy set-asides are specified
in Table 2 of this subpart.
Table 2 to Subpart MMM of Part 62--Statewide Renewable Energy Set-Aside (short tons)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Interim period Final period
---------------------------------------------------------------------------------------------------
State Final compliance
Compliance period 1 Compliance period 2 Compliance period 3 periods 2030-2031 and
2022-2024 2025-2027 2028-2029 thereafter
--------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama............................................. 3,308,224 3,045,949 2,910,799 2,844,024
Arizona............................................. 1,759,462 1,618,597 1,545,311 1,508,538
Arkansas............................................ 1,801,634 1,647,676 1,562,687 1,516,132
California.......................................... 2,675,005 2,504,042 2,436,844 2,420,506
Colorado............................................ 1,789,266 1,632,724 1,544,591 1,495,020
Connecticut......................................... 377,789 355,423 347,754 347,076
Delaware............................................ 267,418 248,155 239,214 235,591
Florida............................................. 5,969,024 5,537,734 5,336,809 5,254,735
Georgia............................................. 2,712,897 2,492,754 2,376,741 2,317,342
Idaho............................................... 80,776 76,141 74,653 74,643
Illinois............................................ 4,019,805 3,656,247 3,446,097 3,323,858
Indiana............................................. 4,600,539 4,185,017 3,945,079 3,805,692
Iowa................................................ 1,520,418 1,380,771 1,299,099 1,250,907
Kansas.............................................. 1,338,186 1,214,789 1,142,405 1,099,541
Kentucky............................................ 3,837,868 3,484,943 3,278,345 3,156,306
Lands of the Fort Mojave Tribe...................... 31,844 30,017 29,430 29,426
Lands of the Navajo Nation.......................... 1,322,470 1,199,978 1,127,887 1,085,029
Lands of the Uintah and Ouray Reservation........... 137,937 125,161 117,642 113,172
Louisiana........................................... 2,101,760 1,923,058 1,824,835 1,771,351
Maine............................................... 112,559 105,993 103,809 103,697
Maryland............................................ 872,368 792,124 745,141 717,381
Massachusetts....................................... 668,037 625,599 609,081 605,237
Michigan............................................ 2,842,713 2,594,678 2,455,344 2,377,203
Minnesota........................................... 1,365,158 1,243,429 1,173,839 1,133,918
Mississippi......................................... 1,447,034 1,339,534 1,287,811 1,265,217
Missouri............................................ 3,365,646 3,057,914 2,878,547 2,773,144
Montana............................................. 688,830 625,028 587,479 565,155
Nebraska............................................ 1,112,318 1,009,641 949,364 913,637
Nevada.............................................. 753,827 703,632 682,631 676,179
New Hampshire....................................... 223,078 208,149 201,857 199,879
New Jersey.......................................... 912,075 855,377 834,097 829,987
New Mexico.......................................... 739,499 675,734 640,263 620,630
New York............................................ 1,774,674 1,646,638 1,587,097 1,562,871
North Carolina...................................... 3,048,792 2,787,462 2,642,825 2,563,312
North Dakota........................................ 1,272,659 1,154,781 1,085,405 1,044,162
Ohio................................................ 4,425,616 4,035,247 3,814,008 3,688,490
Oklahoma............................................ 2,378,881 2,183,251 2,078,869 2,024,410
Oregon.............................................. 454,886 423,883 410,479 405,933
Pennsylvania........................................ 5,304,138 4,860,236 4,619,604 4,491,115
Rhode Island........................................ 190,582 179,647 176,134 176,111
[[Page 65065]]
South Carolina...................................... 1,551,276 1,416,842 1,341,748 1,299,948
South Dakota........................................ 211,559 193,120 182,771 176,974
Tennessee........................................... 1,705,915 1,553,959 1,467,161 1,417,420
Texas............................................... 11,080,665 10,186,403 9,717,567 9,479,442
Utah................................................ 1,423,990 1,299,099 1,228,643 1,188,910
Virginia............................................ 1,564,510 1,449,550 1,394,924 1,371,656
Washington.......................................... 619,785 572,057 548,179 536,959
West Virginia....................................... 3,127,851 2,838,139 2,667,633 2,566,267
Wisconsin........................................... 1,675,283 1,528,566 1,445,897 1,399,349
Wyoming............................................. 1,926,425 1,748,391 1,643,786 1,581,721
--------------------------------------------------------------------------------------------------------------------------------------------------------
(d) The output-based set-aside for each State under this subpart,
beginning in compliance period 2, must reserve a share of the State's
annual allowances prior to allocation of that year's allowances to
facilities as set forth in this paragraph (d). The output-based set-
asides are specified in Table 3 of this subpart.
Table 3 to Subpart MMM of Part 62--Statewide Output-based Set-Aside
(short tons)
------------------------------------------------------------------------
Allowances in output-based set-
State aside (short tons)
------------------------------------------------------------------------
Alabama............................. 4,185,496
Arizona............................. 4,197,813
Arkansas............................ 2,102,538
California.......................... 8,458,604
Colorado............................ 1,348,187
Connecticut......................... 1,090,811
Delaware............................ 649,190
Florida............................. 12,102,688
Georgia............................. 3,563,104
Idaho............................... 246,638
Illinois............................ 1,598,615
Indiana............................. 1,106,150
Iowa................................ 492,510
Kansas.............................. 62,257
Kentucky............................ 288,730
Lands of the Fort Mojave Tribe...... 248,127
Lands of the Navajo Nation.......... 0
Lands of the Uintah and Ouray 0
Reservation........................
Louisiana........................... 2,207,879
Maine............................... 563,925
Maryland............................ 103,762
Massachusetts....................... 2,439,991
Michigan............................ 2,105,786
Minnesota........................... 909,724
Mississippi......................... 3,132,671
Missouri............................ 815,210
Montana............................. 0
Nebraska............................ 144,635
Nevada.............................. 2,326,529
New Hampshire....................... 542,721
New Jersey.......................... 3,413,100
New Mexico.......................... 627,085
New York............................ 3,815,381
North Carolina...................... 2,120,178
North Dakota........................ 0
Ohio................................ 1,757,326
Oklahoma............................ 3,121,167
Oregon.............................. 1,291,027
Pennsylvania........................ 4,392,931
Rhode Island........................ 778,307
South Carolina...................... 1,029,366
South Dakota........................ 130,831
Tennessee........................... 632,949
Texas............................... 15,990,657
Utah................................ 825,586
Virginia............................ 3,011,811
[[Page 65066]]
Washington.......................... 1,383,060
West Virginia....................... 0
Wisconsin........................... 1,181,175
Wyoming............................. 45,114
------------------------------------------------------------------------
(e)(1) The Clean Energy Investment Program Set-Aside for each State
covered under this subpart must contain an amount of allowances shown
in Table 4 of this subpart, which must reserve a share of the State's
annual allowances prior to allocation of that year's allowances to
facilities as set forth in this paragraph.
Table 4 to Subpart MMM of Part 62--Clean Energy Investment Program Early
Action Set-Aside (short tons)
------------------------------------------------------------------------
Allowances in early action set-
State aside (short tons)
------------------------------------------------------------------------
Alabama............................. 3,122,306
Arizona............................. 1,719,618
Arkansas............................ 2,187,230
California.......................... 218,846
Colorado............................ 2,223,192
Connecticut......................... 69,415
Delaware............................ 138,392
Florida............................. 3,230,248
Georgia............................. 2,755,623
Idaho............................... 14,929
Illinois............................ 5,968,721
Indiana............................. 5,754,076
Iowa................................ 2,191,183
Kansas.............................. 2,115,630
Kentucky............................ 4,952,862
Lands of the Fort Mojave Tribe...... 5,885
Lands of the Navajo Nation.......... 1,623,066
Lands of the Uintah and Ouray 175,509
Reservation........................
Louisiana........................... 1,497,428
Maine............................... 20,739
Maryland............................ 972,775
Massachusetts....................... 170,471
Michigan............................ 3,727,861
Minnesota........................... 2,002,903
Mississippi......................... 357,307
Missouri............................ 3,771,322
Montana............................. 1,310,344
Nebraska............................ 1,481,695
Nevada.............................. 336,288
New Hampshire....................... 107,798
New Jersey.......................... 446,005
New Mexico.......................... 823,049
New York............................ 557,771
North Carolina...................... 2,674,590
North Dakota........................ 2,150,635
Ohio................................ 4,788,372
Oklahoma............................ 2,067,006
Oregon.............................. 154,353
Pennsylvania........................ 5,039,346
Rhode Island........................ 35,674
South Carolina...................... 1,652,802
South Dakota........................ 264,207
Tennessee........................... 2,178,084
Texas............................... 10,400,192
Utah................................ 1,401,189
Virginia............................ 1,386,546
Washington.......................... 751,434
West Virginia....................... 3,506,890
Wisconsin........................... 2,393,870
Wyoming............................. 3,104,324
------------------------------------------------------------------------
[[Page 65067]]
(2) Allowances may be distributed from the set-aside for projects
meeting the criteria of paragraph (e)(3) of this section, upon
application of a project proponent that meets the requirements of Sec.
62.16245(a), except as may be prescribed by the Administrator in a
future action. In order to receive a distribution, the project
proponent must establish a general account in the tracking system as
provided in Sec. 62.16320(c).
(3) Projects eligible for distribution of allowances from this set-
aside must meet each of the criteria in paragraphs (e)(3)(i) through
(iii) of this section. All categories of resources other than those
listed in paragraphs (e)(3)(iii)(A) and (B) of this section, and all
provisions of this subpart relating to such resources, are not
available or applicable in States where this subpart has been
promulgated as a federal plan pursuant to section 111(d)(2) of the
Clean Air Act.
(i) The project was constructed or implemented on or after the
signature date of the final rule promulgating subpart UUUU of part 60
of this chapter;
(ii) The creditable generation or energy savings from the project
must occur in calendar years 2020 or 2021; and
(iii) Generation or energy savings must be from one of the
following types of sources capable of revenue-quality metering:
(A) Onshore wind;
(B) Solar; or
(C) Demand-side EE.
Sec. 62.16240 When are allowances allocated?
(a) Allowance allocations. (1) By June 1, 2021, and by June 1 of
each year prior to the beginning of each compliance period thereafter,
CO2 allowances will be allocated, for the multi-year
compliance periods in the Interim Period beginning in 2022 and the
Final Period beginning in 2030, as provided by the Administrator in a
notice of data availability or through this subpart (if applicable).
Providing an allocation to an entity does not constitute as an
applicability determination of an affected EGU.
(2) Notwithstanding paragraph (a)(1) of this section, if an
affected EGU which is provided an allocation does not operate for 2
consecutive calendar years, then such affected EGU will not be
allocated the CO2 allowances provided by the Administrator
in a notice of data availability or through this subpart (if
applicable) for the affected EGU for the next compliance period for
which allowances have not yet been recorded and for each compliance
period after that compliance period. All CO2 allowances that
would otherwise have been allocated to such affected EGU will be
allocated to the renewable energy set-aside for the State where such
affected EGU is located and for the respective compliance periods
involved.
(3) Notwithstanding paragraph (a)(1) of this section, if an
affected EGU provided an allocation issued by the Administrator in
notice of data availability or through this subpart (if applicable) is
modified or reconstructed such that it is no longer subject to this
subpart, then such affected EGU will not be allocated the
CO2 allowances provided for the affected EGU for the next
compliance period for which allowances have not yet been recorded and
for each compliance period after that compliance period. All
CO2 allowances that would otherwise have been allocated to
such affected EGU will be allocated to the renewable energy set-aside
for the State where such affected EGU is located and for the respective
compliance periods involved.
(b) Set-asides--(1) Renewable energy set-asides. (i) By December 1,
2021 and December 1 of each year thereafter, the Administrator will
calculate and allocate the CO2 allowance allocation to each
approved renewal energy project in a State, in accordance with Sec.
62.16245(a)(2) through (5), for the generation year of the applicable
calculation deadline under this paragraph.
(ii) By December 1, 2021 and December 1 of each year thereafter,
the Administrator will calculate and allocate the CO2
allowance allocation to each affected EGU in a State, in accordance
with Sec. 62.16245(a)(6) and (7) for the generation year of the
applicable calculation, and will promulgate a notice of data
availability of the results of the calculations.
(2) Output-based set-asides. (i) By November 1 of the first year of
each compliance period beginning in 2025, and each compliance period
thereafter, the Administrator will calculate and allocate the
CO2 allowance allocation to each affected EGU in a State, in
accordance with Sec. 62.16245(b)(3), for the generation period of the
applicable calculation deadline under this paragraph.
(ii) By November 1 of the first year of each compliance period
beginning in 2025, and each compliance period thereafter, the
Administrator will calculate and allocate the CO2 allowance
allocation to each affected EGU in a State, in accordance with Sec.
62.16245(b)(4) and (5) for the generation period of the applicable
calculation, and will promulgate a notice of data availability of the
results of the calculations.
(c) Affected EGUs incorrectly allocated CO2 allowances.
(1) For each compliance period in 2022 and thereafter, if the
Administrator determines that CO2 allowances were allocated
under paragraph (a) of this section, or under a provision of a state
allowance distribution methodology approved under subpart UUUU of part
60 of this chapter, where such compliance period and the recipient are
covered by the provisions of paragraph (c)(1)(i) of this section or
were allocated under Sec. 62.16245(a) and (b), where such compliance
period and the recipient are covered by the provisions of paragraph
(c)(1)(ii) of this section, then the Administrator will notify the
designated representative of the recipient and will act in accordance
with the procedures set forth in paragraphs (c)(2) through (5) of this
section. The situations for the Administrator to act according to the
procedures in paragraphs (c)(2) through (5) are if:
(i)(A) The recipient is not actually an affected EGU under Sec.
62.16210 as of January 1, 2022 and is allocated CO2
allowances for such compliance period or, in the case of an allocation
under a provision of a state allowance distribution methodology
approved under subpart UUUU of part 60 of this chapter, the recipient
is not actually an affected EGU as of January 1, 2022 and is allocated
CO2 allowances for such compliance period that the state
allowance distribution methodology provides should be allocated only to
recipients that are affected EGUs as of January 1, 2022; or
(B) The recipient is not located as of January 1 of the compliance
period in the State from whose CO2 allowances the
CO2 allowances allocated under paragraph (a) of this
section, or under a provision of a state allowance distribution
methodology approved under subpart UUUU of part 60 of this chapter,
were allocated for such compliance period.
(ii) The recipient is not actually an affected EGU under Sec.
62.16210 as of January 1 of such compliance period and is allocated
CO2 allowances for such compliance period or, in the case of
an allocation under a provision of a state allowance distribution
methodology approved under subpart UUUU of part 60 of this chapter, the
recipient is not actually an affected EGU as of January 1 of such
compliance period and is allocated CO2 allowances for such
compliance period that the state allowance distribution methodology
provides should be allocated only to recipients that are
[[Page 65068]]
affected EGUs as of January 1 of such compliance period.
(2) Except as provided in paragraph (c)(3) or (4) of this section,
the Administrator will not record such CO2 allowances under
Sec. 62.16325.
(3) If the Administrator already recorded such CO2
allowances under Sec. 62.16325 and if the Administrator makes the
determination under paragraph (c)(1) of this section before making
deductions for the facility that includes such recipient under Sec.
62.16340(b) for such compliance period, then the Administrator will
deduct from the account in which such CO2 allowances were
recorded an amount of CO2 allowances allocated for the same
or a prior compliance period equal to the amount of such already-
recorded CO2 allowances. The authorized account
representative must ensure that there are sufficient CO2
allowances in such account for completion of the deduction.
(4) If the Administrator already recorded such CO2
allowances under Sec. 62.16325 and if the Administrator makes the
determination under paragraph (c)(1) of this section after making
deductions for the facility that includes such recipient under Sec.
62.16340(b) for such compliance period, then the Administrator will not
make any deduction to take account of such already-recorded
CO2 allowances.
(5)(i) With regard to the CO2 allowances that are not
recorded, or that are deducted as an incorrect allocation, in
accordance with paragraphs (c)(2) and (3) of this section for a
recipient under paragraph (c)(1)(i) of this section, the Administrator
will:
(A) Transfer such CO2 allowances to the renewable energy
set-aside for such compliance period for the State from whose
CO2 allowances the CO2 allowances were allocated;
or
(B) If the State has a state allowance distribution methodology
approved under subpart UUUU of part 60 of this chapter covering such
compliance period, then include such CO2 allowances in the
portion of the CO2 allowances that may be allocated for such
compliance period in accordance with such state allowance distribution
methodology.
(ii) With regard to the CO2 allowances that were not
allocated from a renewable energy or output-based set-aside for such
compliance period and that are not recorded, or that are deducted as an
incorrect allocation, in accordance with paragraphs (c)(2) and (3) of
this section for a recipient under paragraph (c)(1)(ii) of this
section, the Administrator will:
(A) Transfer such CO2 allowances to the renewable energy
set-aside for such compliance period; or
(B) If the State has a state allowance distribution methodology
approved under subpart UUUU of part 60 of this chapter covering such
compliance period, then include such CO2 allowances in the
portion of the CO2 allowances that may be allocated for such
compliance period in accordance with such state allowance distribution
methodology.
(iii) With regard to the CO2 allowances that were
allocated from the renewable energy or output-based set-aside for such
compliance period and that are not recorded, or that are deducted as an
incorrect allocation, in accordance with paragraphs (c)(2) and (3) of
this section for a recipient under paragraph (c)(1)(ii) of this
section, the Administrator will transfer such CO2 allowances
back to the renewable energy set-aside, or to the output-based set-
aside, respectively, for such compliance period.
Sec. 62.16245 How are set-aside allowances allocated?
(a)(1) Renewable energy set-aside. The Administrator will establish
a renewable energy set-aside as set forth in Sec. 62.16235(c), and
allocate CO2 allowances from the set-aside for each year of
a compliance period as outlined in this section.
(2) Eligible renewable energy capacity. To be eligible to receive
renewable energy set-aside allowances, an eligible resource must meet
each of the requirements in paragraphs (a)(2)(i) through (v) of this
section. Any resource that does not meet the requirements of paragraphs
(a)(2)(i) through (v) of this section cannot receive set-aside
allowances.
(i) The resource must be a renewable energy resource that falls
into one of the following categories of resources: on-shore utility
scale wind, solar, geothermal power, or utility scale hydropower.
(ii) The resources must only include resources which increased new
installed electrical generation nameplate capacity, or new electrical
savings measures installed or implemented after January 1, 2013. If a
resource had a nameplate capacity uprate, then set-aside allowances may
be issued only for the difference in generation between the uprated
nameplate capacity and its nameplate capacity prior to the uprate. Set-
aside allowances must not be issued for generation for an uprate that
followed a derate that occurred on or after January 1, 2013. A resource
that is relicensed or receives a license extension is considered
existing capacity and is not an eligible resource, unless it receives a
capacity uprate as a result of the relicensing process that is
reflected in its relicensed permit. In such a case, only the difference
in nameplate capacity between its relicensed permit and its prior
permit is eligible to be issued set-aside allowances.
(iii) The resource must be located in the mass-based State for
which the set-aside has been designated.
(iv) The resource must be connected to, and delivers energy to or
saves electricity, on the electric grid in the contiguous United
States.
(v) The resource must not have received emission rate credits
(ERCs) for any period of time for which it receives set-aside
allowances.
(3) Process for issuance of set-aside allowances. The process and
requirements for issuance of set-aside allowances are set forth in
paragraphs (a)(3)(i) through (x) of this section.
(i) Eligibility application. To receive set-aside allowances, an
authorized account representative of an eligible resource must submit
an eligibility application to the Administrator that demonstrates that
the requirements of paragraph (a)(2) of this section are met and
demonstrates that the following requirements are met:
(A) Identification of the authorized account representative of the
eligible resource, including the authorized account representative's
name, address, email address, telephone number, and allowance tracking
system account number; and
(B) Identification of the eligible resource(s), including the
physical location of the eligible resource; contact information for the
owner or operator of the eligible resource, if different from the
authorized account representative and designated representative;
generator prime mover and technology type; generator nameplate capacity
(if applicable); generator category (e.g., wholesale generator,
wholesale generator also serving onsite customer load, customer-sited
distributed generator) (if applicable); facility and generating unit
IDs (EIA ORIS Code, Facility Registration System (FRS) Code, if
applicable) (if applicable); the control area, balancing authority, ISO
conditions as defined in Sec. 62.16375 (if applicable), or regional
transmission organization in which the generator is located (if
applicable); and a copy of the most recent filing of a copy of the
generating facility's U.S. Energy Information Agency's Annual Electric
Generator Report Form EIA-860 (if applicable).
[[Page 65069]]
(ii) Renewable energy providers must open a general account per the
requirements in Sec. 62.16320(c), and submit a project application for
renewable energy set-aside allowances to the Administrator by June 1 of
the year prior to the generation year for which set-aside allowances
are requested. Providers may update submitted projections for future
generation years, these projections must be received by June 1 of the
year prior to the generation year in question. The project application
must contain the following information:
(A) Projection of the project's annual renewable energy generation
in MWh.
(B) Documentation of the methodology, data facilities, and
assumptions used to project the project's annual renewable energy
generation.
(C) A certification that the eligibility application has only been
submitted to the Administrator or pursuant to an EPA-approved multi-
State approach where States are providing for joint issuance of
allowances pursuant to the authority in their individual State plans.
(D) A evaluation, measurement, and verification (EM&V) plan.
(E) A verification report from an accredited independent verifier
who meets the requirements of Sec. 62.16275 and Sec. 62.16280. While
considered a part of the eligibility application, the verification
report must be submitted separately by the accredited independent
verifier to the Administrator.
(F) An authorization that provides for the following: the
Administrator may inspect (including a physical inspection of the
eligible resource and its meter) and/or audit the eligible resource at
any time and verify that the eligible resource and the EM&V plan have
been implemented as described in the eligibility application.
(G) The following statement, signed by the authorized account
representative of the eligible resource:
(1) ``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
personal knowledge and/or 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) [Reserved]
(H) Any other information required by the Administrator.
(4) Monitoring and verification. After the generation year for
which a provider received set-aside allowances for an eligible
resource, the authorized account representative must submit to the
Administrator:
(i) A measurement and verification (M&V) report.
(ii) A verification report from an accredited independent verifier
that meets the requirements of Sec. 62.16275 and Sec. 62.16280. While
considered a part of the M&V report, the verification report must be
submitted separately by the accredited independent verifier to the
Administrator.
(5) Allocation of renewable energy set-aside allowances. The
Administrator will enter the projected generation from each approved
project into a pool of projects for that State that will receive set-
asides for a generation year.
(i) The Administrator will distribute renewable energy set-aside
allowances for a generation year with the number of allowances
distributed to each project prorated according to its percentage of the
total approved projected MWhs for that State that the project
represents.
(ii) If in the previous generation year, the project did not reach
the MWhs projected, then the unfulfilled MWhs will be subtracted from
that provider's projected generation eligible for the set-aside pool.
(iii) If the unfulfilled MWhs from a previous year exceed the
projected hours for the generation year, then the Administrator will
carry over the deficit and subtract from the projected generation in
subsequent years until there is no deficit. If this deficit is greater
than 10 percent in a particular year, then the provider will need to
provide an explanation to the Administrator of the deficit, and will be
required to reevaluate their projections for future years. If such
deficits continue through all 3 years of the first or second compliance
period, then the Administrator will disqualify the provider from
receiving future set-asides for the following compliance period.
(6) Surplus renewable set-aside allowances. If, after completion of
the procedures under paragraph (a)(5) of this section for each
compliance period, any unallocated CO2 allowances remain in
the renewable energy set-aside for the State for such generation year,
the Administrator will allocate the amount of CO2 allowances
in a pro rata fashion on the same distribution basis as their initial
allocations were made to each affected EGU that: is in the State; is
allocated an amount of CO2 allowances in the notice of data
availability issued under Sec. 62.16240(a)(1); and continues to be
allocated CO2 allowances for such compliance period in
accordance with Sec. 62.16240(a)(2).
(7) Notice of surplus renewable energy set-aside allowance
distribution. The Administrator will make public the amount of
CO2 allowances allocated under paragraph (a)(6) of this
section for such generation year period to each affected EGU eligible
for such allocation.
(b)(1) Output-based set-aside. The Administrator will establish an
output-based set-aside beginning in compliance period 2, and allocate
CO2 allowances from the set-aside for each year of a
compliance period as set forth in Sec. 62.16235(c).
(2) Unit eligibility. To be eligible to receive output-based set-
aside allowances, affected EGUs must meet the following eligibility
requirements:
(i) The affected EGU must be a natural gas combined cycle unit;
(ii) The affected EGU must be located in the mass-based State for
which the set-aside has been designated; and
(iii) The affected EGU's average capacity factor in the preceding
compliance period was above 50 percent based on net summer capacity and
net generation.
(3) Allocation of output-based set-aside allowances. The
Administrator will allocate output based set-aside allowances for each
eligible EGU based on its average net generation and net summer
capacity in the preceding compliance period.
(i) The Administrator will calculate the amount of allowances an
eligible EGU receives from the output-based set-aside as the unit's
average net generation in the preceding compliance period over 50
percent multiplied by the allocation rate of 1,030 lb/MWh-net.
(ii) If the amount of total allowances exceeds the size of the
State's set-aside, then the allowances will be allocated to the State's
eligible generation on a pro-rata basis.
(iii) The Administrator will provide notice of the net summer
capacity and net generation data used, and the resulting allocations by
August 1 of the first year of each compliance period beginning in 2025.
The notice of the net summer capacity and net generation data used, and
the resulting allocations, must allow 30 days for public comment on the
data and allocations, until August 31 of the same year.
(iv) The Administrator will provide notice of the final set-aside
allocations by November 1 of the same year.
(4) Surplus output-based set-aside allowances. If, after completion
of the
[[Page 65070]]
procedures under paragraph (b)(3) of this section for each compliance
period, any unallocated CO2 allowances remain in the out-put
based set-aside for the State for such generation period, the
Administrator will allocate the amount of CO2 allowances in
a pro rata fashion on the same distribution basis as their initial
allocations were made to each affected EGU that: is in the State; is
allocated an amount of CO2 allowances in the notice of data
availability issued under Sec. 62.16240(a)(1); and continues to be
allocated CO2 allowances for such compliance period in
accordance with Sec. 62.16240(a)(2).
(5) Notice of surplus output-based set-aside. The Administrator
will notify the public, through the promulgation of the notices of data
availability described in Sec. 62.16240(b)(1) and (2), of the amount
of CO2 allowances allocated under paragraphs (b)(3) and (4)
of this section for such compliance period to each affected EGU
eligible for such allocation.
Sec. 62.16250 What is the process for revocation of qualification
status of an eligible resource?
(a) If an eligible resource is found to not meet the requirements
of Sec. 62.16260 in the CO2 Mass-based Trading Program,
then the Administrator will revoke the eligibility of the eligible
resource to be issued set-aside allowances. In addition, the provisions
of Sec. 62.16255(d) may apply.
(b) Any instance of intentional misrepresentation in an eligibility
application or M&V report may be cause for revocation of the
qualification status of an eligible resource.
(c) Repeated instances of error or misstatement of MWh of
electricity generation or savings in submitted M&V reports, or in any
other submissions may be cause for the Administrator to revoke the
eligibility of an eligible resource to be issued set-aside allowances.
(d) In the event of an intentional misrepresentation, or repeated
instances of error or misstatement, in program submissions, by the
authorized account representative of the eligible resource, the
Administrator may prohibit the eligible resource from any further
eligibility to be issued allowances. In addition, the provisions of
Sec. 62.16255(a) through (d) may apply.
Sec. 62.16255 What is the process for error adjustments or
misstatement, and suspension of allowance issuance?
(a) In the event of error or misstatement of quantified MWh of
electricity generation or savings in a previous M&V report for which
set-aside allowances have been issued, the Administrator may adjust the
number of set-aside allowances issued in a subsequent reporting period
to address the error or misstatement, by subtracting a number of MWh
from the quantified and verified MWh in the M&V report for the
subsequent reporting period. In the event that an error or inadvertent
misstatement occurs in a final M&V report for an eligible resource, for
which set-aside allowances have been issued, the provisions of
paragraph (b) of this section will apply.
(b) In the event of error or misstatement of quantified MWh of
electricity generation or savings in the final M&V report for an
eligible resource, for which set-aside allowances have been issued, the
Administrator will revoke set-aside allowances from the general account
held by the authorized account representative of the eligible resource,
in an amount necessary to correct the error or misstatement. In the
event that the general account of the eligible resource holds an
insufficient number of set-aside allowances to correct the error or
misstatement, the authorized account representative must submit to the
Administrator within 30 days a number of set-aside allowances necessary
to correct the error or misstatement. Failure to meet this requirement
will result in prohibition of the authorized account representative for
the eligible resource from further participation in the program, unless
reauthorized at the discretion of the Administrator.
(c) The Administrator may freeze the general account held by an
authorized account representative of an eligible resource at any time,
for cause, if the Administrator determines set-aside allowances have
been improperly issued, based on a misrepresentation or misstatement in
an eligibility application or M&V report. The Administrator may also
freeze the general account of an authorized account representative of
an eligible resource pending investigation of potential
misrepresentation, error, or misstatement in an eligibility application
of an eligible resource, or in an M&V report for which set-aside
allowances have been issued. Freezing a general account will prevent
transfer of allowances out of the account.
(d) If set-aside allowances are issued for an eligible resource
that is found to be ineligible, then the Administrator may take the
actions in paragraphs (d)(1) through (3) of this section.
(1) Freeze the general account of the authorized account
representative for an eligible resource, preventing any transfers of
allowances out of the account.
(2) Revoke or deduct allowances held in the general account of the
authorized account representative for an eligible resource, in a number
equal to the number of allowances issued for the ineligible eligible
resource.
(3) In the event that the general account of the eligible resource
holds a number of allowances less than the number of set-aside
allowances issued for the ineligible eligible resource, the delegated
representative of an eligible resource must submit to the Administrator
within 30 days a number of allowances necessary to fully account for
all allowances issued for the ineligible eligible resource. Failure to
meet this requirement will result in prohibition of the eligible
resource from further participation in the program, unless reauthorized
at the discretion of the Administrator.
(e) The Administrator may temporarily or permanently suspend
issuance of set-aside allowances for an eligible resource, for the
following reasons in paragraphs (e)(1) through (3) of this section.
(1) Pending investigation of potential misrepresentation, error, or
misstatement in an M&V report, for which set-aside allowances have been
issued, or the eligibility status of an eligible resource.
(2) In the case of repeated error or misstatements in submitted M&V
reports.
(3) In the case of an intentional misrepresentation in a submitted
M&V report.
Evaluation Measurement and Verification Plans, Monitoring and
Verification Reports, and Verification
Sec. 62.16260 What are the requirements for evaluation, measurement
and verification plans for eligible resources?
(a) EM&V plan requirements. Any EM&V plan submitted in support of
the issuance of a set-aside allowance pursuant to this rule must meet
the requirements of this section.
(b) General EM&V plan criteria. Each EM&V plan must identify the
eligible resource and its approved eligibility application.
(c) Specific EM&V plan criteria. Each EM&V plan must provide the
manner in which the electricity generated or saved by the eligible
resource will be quantified, monitored and verified, and the manner of
quantification, monitoring and verification must meet the criteria
listed in paragraphs (c)(1) through (7) of this section, as applicable
to the specific eligible resource.
[[Page 65071]]
(1) For a nuclear energy resource or a renewable energy resource
with a nameplate capacity of 10 kW or more and for a renewable energy
resource with a nameplate capacity of less than 10 kW for which metered
data are available, each EM&V plan must specify that the requirements
in paragraphs (c)(1)(i) through (vi) of this section must be met.
(i) The generation data are physically measured on a continuous
basis using a revenue-quality meter, which means a meter used by a
control area operator for financial settlements, or a meter that meets
the American National Standards Institute No. C12.20., Code for
Electricity Metering, metering accuracy standards, or a meter that
meets an alternative equivalent standard that has been approved in
advance of its use to measure generation pursuant to this regulation by
the EPA.
(ii) The generating data are measured at the generator's bus bar,
or, for a renewable energy resource with a nameplate capacity of less
than 10 kW that is interconnected behind an individual business or
household meter, the generating data were measured at the AC output of
the inverter and adjusted to reflect the only energy delivered into
either the transmission or distribution grid at the generator bus bar
and not any energy used on-site at the generator.
(iii) The generation data from only one eligible resource
generating unit may be associated with each meter, and generation data
may not be aggregated, unless all the following provisions are met:
(A) All of the generating units have the same essential generation
characteristics;
(B) All of the generating units are located in the same State;
(C) The nameplate capacity of the individual units being aggregated
is each less than 150 kW, and units collectively do not exceed a total
nameplate capacity of 1 MW when aggregated, or alternative requirements
approved by the EPA in connection with the specific State plan pursuant
to which that EM&V plan or M&V report is submitted; and
(D) The generation data are measured by the same type of meter that
is subject to the same maintenance and quality assurance procedures.
(iv) The generation data are collected electronically and
telemetered from the generator to its control area operator and
verified through a control area energy accounting or settlement process
which occurs at least monthly, unless the generation unit does not go
through a control area operator, in which case the generation data must
be collected by manual meter readings conducted by an independent
verifier that is either not affiliated with the owner or operator of
the qualifying renewable energy generating resource or is precluded
pursuant to the relevant State plan from the ability to transfer or
retire set-aside allowances issued to that qualifying renewable energy
generating resource or, if the generating unit is less than 10 kw and
does not generate enough electricity to enable monthly reporting, then
the data may be self-reported and reported no less than annually.
(v) The generation data serve a load that otherwise would have been
served by the grid if not for the generator. Specifically:
(A) Set-aside allowances shall not be issued for energy generation
used to supply the ancillary equipment used to operate a generating
station or substation (``station service'') or parasitic load on the
generator's side of the point of interconnection; and
(B) For generators interconnected to transmission systems and with
on-site loads other than station service drawing generation before the
metering point, set-aside allowances may be issued for on-site load, if
the owner or operator of the eligible resource can demonstrate that the
metering used is capable of distinguishing between on-site load and
station service.
(vi) Any other requirements approved by the EPA in connection with
the specific State plan pursuant to which that EM&V plan is submitted.
(2) For a renewable energy resource with a nameplate capacity of
less than 10 kW and that does not have a meter, each EM&V plan must
require that the following requirements in paragraphs (c)(2)(i) through
(vii) of this section are met.
(i) Metered data are unavailable.
(ii) At least 1 MW of net energy output is generated to the
distribution or transmission system over a continuous 365-day period.
(iii) The generation data may not be aggregated, unless the
following provisions are met:
(A) All of the generating units have the same essential generation
characteristics;
(B) All of the generating units are located in the same State;
(C) The nameplate capacity of the individual units being aggregated
is each less than 150 kW, and units collectively do not exceed a total
nameplate capacity of 1 MW when aggregated, or alternative requirements
approved by the EPA in connection with the specific State plan pursuant
to which that EM&V plan or M&V report is submitted; and
(D) The generation data are measured by the same generation
estimating software or algorithms.
(iv) The generation data are measured on at least a monthly basis
using generation estimating software or algorithms that are based on an
on-site inspection prior to interconnection and a resource study (wind,
shading, solar irradiance, depending on the resource), or engineering
information that takes into account the capacity, age, and type of
qualifying energy generating resource, and all input parameters and
assumptions must be clearly delineated, or if the generating unit does
not generate enough electricity to enable monthly reporting, then the
data may be reported no less than annually.
(v) The generation data are self-reported to the distribution
utility through an electronic internet-based portal with software that
reports total and hourly generation.
(vi) The generation data serves a load that otherwise would have
been served by the grid if not for the generator. The set-aside
allowance is only based on generation transferred from the eligible
resource to the transmission or distribution grid, and is not based on
the generation used on-site by the customer.
(vii) Any other requirements approved by the EPA in connection with
the specific State plan pursuant to which that EM&V plan is submitted.
(3) For qualified biomass feedstocks used, in addition to the
requirements of paragraph (c)(1) or (2) of this section, whichever
section is applicable, each EM&V plan must demonstrate that the
requirements approved by the EPA for that biomass feedstock, and its
associated biogenic CO2, have been met.
(4) For a waste-to-energy resource, in addition to the requirements
of paragraph (c)(1) or (2) of this section, as applicable, and
paragraph (c)(3) of this section, each EM&V plan must specify:
(i) The total net energy generation from the resource in MWh;
(ii) The method for determining the specific portion of the total
net energy output from the resource that is related to the biogenic
portion of the waste; and
(iii) The net energy output is measured with the relevant method
approved by the EPA in connection with the specific State plan pursuant
to which that EM&V plan is submitted demonstrates that the requirements
approved by the EPA in connection with that State plan have been met.
(5) For a combined heat and power unit, in addition to the
requirements of paragraphs (c)(1) or (2) of this section,
[[Page 65072]]
as applicable, and paragraph (c)(3) of this section, each EM&V plan
must meet one of the requirements in paragraphs (c)(5)(i) through (iv)
of this section, as applicable, and any other requirements approved by
the EPA.
(i) If the combined heat and power unit has an electric generating
capacity greater than 25 MW, then the EM&V plan must meet the
requirements that apply to an affected EGU under Sec. 62.16540 of this
subpart.
(ii) If the combined heat and power unit has an electric generating
capacity less than or equal to 25 MW and greater than 1 MW, and it uses
only natural gas and/or distillate fuel oil, then the EM&V plan must
meet the low mass emission unit CO2 emission monitoring and
reporting methodology in part 75 of this chapter.
(iii) If the combined heat and power unit has an electric
generating capacity less than or equal to 25 MW and greater than 1 MW,
and it uses anything other than only natural gas and/or distillate fuel
oil, then the EM&V plan must meet the low mass emission unit
CO2 emission monitoring and reporting methodology in part 75
of this chapter.
(iv) If the combined heat and power unit has an electric generating
capacity less than or equal to 1 MW the unit must keep monthly
cumulative recordings of useful thermal output and fossil fuel input
along with the determination of baseline thermal source efficiencies
based on manufacturer data. For CHP units that directly serve on-site
end-use electricity loads, avoided transmission and distribution (T&D)
system losses can be assessed as is commonly practiced with demand-side
EE.
(6) For electricity savings that avoid a transmission and
distribution loss, each EM&V plan must measure the transmission and
distribution loss based on the lesser of 6 percent of the site-level
electricity savings measured at the end use meter or the statewide
annual average transmission and distribution loss rate (expressed as a
percentage) from the most recent year that is published in the US EIA
State Electricity Profile expressed as a percentage. No other
transmission and distribution loss factors may be used in calculating
the electricity savings, including measures such as conservation
voltage reduction and volt/VAR optimization.
(7) Each EM&V plan for an EE program, EE project, or EE measure
must specify how each of the requirements in paragraphs (c)(7)(i)
through (x) of this section will be met in quantifying the electricity
savings from that EE program, EE project, or EE measure.
(i) All electricity savings must be quantified on an ex-post basis,
which means after the electricity savings have occurred, or on a real-
time basis, which means at the time the electricity savings are
occurring. Electricity savings must not be quantified on an ex-ante
basis, which means estimates of MWh savings that are generated prior to
implementing the subject EE program, EE project, or EE measure, and
that are not quantified using EM&V methods and procedures.
(ii) All electricity savings must be quantified and verified based
on methods and procedures detailed in an industry best-practice EM&V
protocol or guideline. Each EM&V plan must include a demonstration of
how the best-practice protocol or guideline was selected and will be
applied to the specific EE program, EE project, or EE measure covered
in the EM&V plan, and an explanation of why that particular protocol or
guideline was selected. Protocols and guidelines are considered to be
best practice if they:
(A) Have gone through a rigorous and credible peer review process
that shows the applicable methods to be valid through empirical
testing; and
(B) Have been accepted and approved for use by identifiable state
regulatory commissions. Examples of such protocols and guidelines that
may be provided in EM&V guidance issued by the Administrator will be
acceptable.
(iii) All electricity savings must be quantified as the difference
between the observed electricity use and a common practice baseline
(CPB), which is the equipment that would typically have been
installed--or that a typical consumer or building owner would have
continued using--in a given circumstance (i.e., a given building type,
EE program type or delivery mechanism, and geographic region) at the
time of EE implementation. Examples of CPBs for specific EE programs,
EE projects, EE measures, and for certain EM&V methods that may be
provided in EM&V guidance issued by the Administrator will be
acceptable. The EM&V plan must specify the reason the specific CPB was
selected, which must include an analysis of the appropriateness of that
CPB for the EE program, EE project, or EE measure covered in the EM&V
plan, based on:
(A) Characteristics of the EE program, EE project, or EE measure;
(B) The delivery mechanism used to implement the EE program, EE
project, or EE measure (e.g., installed as part of a utility EE program
versus a point-of-sale rebate);
(C) Local consumer and market characteristics;
(D) Applicable building energy codes and standards and average
compliance rates; and
(E) The method applied: project-based measurement and verification
(PB-MV), comparison group approaches, or deemed savings.
(iv) All electricity savings must be quantified by applying one or
more of the following methods: PB-MV, comparison group approaches, or
deemed savings.
(A) If a comparison group approach is used, then the EM&V plan must
quantify electricity savings by taking the difference between a
comparison group's electricity use and the electricity use of EE
program participants. Comparison group approaches may include
randomized control trials and quasi-experimental methods, as described
in industry best-practice protocols and guidelines. Examples of such
protocols and guidelines provided in EM&V guidance that may be issued
by the Administrator will be acceptable.
(B) If deemed savings are used, then the EM&V plan must specify
that the deemed savings values will only be used for the specific EE
measure for which they were derived. The EM&V plan must also specify
the name and Web address of the technical reference manual (TRM) in
which all deemed electricity savings values will be documented. Prior
to use in an EM&V plan, all TRMs must undergo a review process in which
the public, stakeholders, and experts are invited--with adequate
advance notification (via the internet and other social media)--to
provide comment, have at least 2 months to provide comment, and in
which all such comments and associated responses are made publicly
available. All TRMs must also be publicly accessible over the full
period of time in which they are being used in conjunction with an EM&V
plan for the purpose of quantifying savings, and must be subsequently
updated in the same manner at least every 3 years. The TRM must
indicate, for each subject EE measure, the associated electricity
savings value, the conditions under which the value can be applied
(including the climate zone, building type, manner of implementation,
applicable end uses, operating conditions, and effective useful life),
and the manner in which the electricity savings value was quantified,
which must include applicable engineering algorithms, source
documentation, specific assumptions, and other relevant
[[Page 65073]]
data to support the quantification of savings from the subject EE
measure.
(v) All EE programs, EE projects, or EE measures must be quantified
at time intervals (in years) sufficient to ensure that MWh savings are
accurately and reliably quantified. Such time intervals must be
specified and explained in the EM&V plan. Factors that must be taken
into consideration when determining the appropriate time interval
include the characteristics of the specific EE program, EE project, or
EE measure, expected variability in electricity savings (where greater
variability necessitates more frequent quantification), the expected
scale and magnitude of the electricity savings (where greater
quantities of savings necessitate more frequent quantification), and
the experience implementing and quantifying savings from the resource
(where less experience--for example, with new and innovative EE program
types--necessitates more frequent quantification). The time intervals
must end no sooner than the last day of the effective useful life of
the EE program, EE project, or EE measure, and must last no longer
than:
(A) Every 4-year intervals for building energy codes and product
standards;
(B) Every 1, 2 or 3 years for public or consumer-funded EE program,
EE project, or EE measure, as relevant for the type of EE program, EE
project, or EE measure and factors listed in paragraph (c)(7)(v) of
this section; and
(C) Annually for commercial and industrial projects, unless the
resource provider can provide a reasonable justification in the EM&V
plan for why an annual time interval is not feasible, and can
additionally explain how the accuracy and reliability of savings values
will not be lessened.
(vi) EM&V plans must specify and document how the EM&V components
in paragraphs (c)(7)(vi)(A) through (E) of this section will be
analyzed, considered, or otherwise addressed in the quantification and
verification of electricity savings.
(A) The effects of changes in independent factors on reported
electricity savings (i.e., factors that are not directly related to the
EE measure, such as weather, occupancy, and production levels).
(B) The effective useful life (EUL) or duration of time the EE
measure is anticipated to remain in place and operable with the
potential to save electricity, which must be based on the application
of EM&V methods, an industry best-practice persistence study, deemed
estimates of effective useful life, or a combination of all three.
(1) If deemed estimates of effective useful life are used, then
they must specify the date by which the EE measure will stop saving
electricity.
(2) If industry best-practices persistence studies are used to
modify an effective-useful-life value, then they must be conducted at
least every 5 years.
(C) The potential sources of double counting, and the associated
steps for avoiding and correcting for it, such as:
(1) For an EE program or EE project with identified participants,
track the type and number of EE measures implemented at the utility-
customer level.
(2) For an EE program or EE project without identified
participants, such as point-of-sale rebates and retailer or
manufacturer incentive programs, track applicable vendor, retailer, and
manufacturer data.
(3) For EE programs (such as those implemented by a utility) and EE
projects (such as those implemented by an energy service company) that
both have identified participants, use tracking data to avoid and
correct for double counting that may occur across the two; and
(4) For EE programs with identified participants and those without
(such as retail incentives to purchase energy-efficient equipment), use
EE program tracking data for the former and use applicable vendor,
retailer, and manufacturer data for the latter to avoid and correct for
double counting that may occur across the two.
(D) The EE savings verification approaches for ensuring that EE
measures have been properly installed, are operating as intended, and
therefore have the potential to save electricity, including how
verification will be carried out within the first year of
implementation of the EE program, EE project, or EE measure using best-
practice approaches, such as physical inspections at a customer's
premises, phone and mail surveys, and reviews of sales receipts and
other documentation. If such approaches are documented in EM&V guidance
issued by the Administrator, they will be treated as acceptable.
(E) The interactive effects of EE programs, EE projects, or EE
measures on electricity usage, which are increases or decreases in
electricity usage at an end-use facility or premises that occurs
outside of specific end-uses(s) targeted by the EE program, EE project,
or EE measure (e.g., lighting retrofits to improve EE can reduce waste
heat to the surrounding conditioned space, and therefore may increase
the required electric heating load in a facility or premises).
(vii) The EM&V plan must specify how the accuracy and reliability
of the electricity savings of the EE program, EE project, or EE measure
will be assessed, and must discuss the rigor of the method selected to
quantify the electricity savings. It must also discuss the approaches
that will be used to control all relevant types of bias and to minimize
the potential for systematic and random error, as well as the program-
or project-specific circumstances in which such bias and error are
likely to arise. Approaches to minimizing bias and error are provided
in the EM&V guidance that may be issued by the Administrator will be
acceptable.
(viii) If sampling will be used to quantify the electricity savings
from an EE program, then the MWh estimates derived from sampling must
have at least 90 percent confidence intervals whose end points are no
more than +/-10 percent of the estimate, and the statistical precision
of the associated estimates must be specified in the EM&V plan.
(ix) All data sources and key assumptions used to quantify
electricity savings must be described in the EM&V plan.
(x) Any additional information necessary to demonstrate that the
electricity savings were appropriately quantified and verified.
Approaches to quantifying and verifying savings from several EE program
and EE project types that are provided in EM&V guidance that may be
issued by the Administrator will be acceptable.
(d) You must ensure that any EM&V plan submitted pursuant to this
subpart includes the following certification:
(1) ``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) [Reserved]
Sec. 62.16265 What are the requirements for monitoring and
verification reports for eligible resources?
(a) M&V report requirements. Any M&V report that is submitted, in
[[Page 65074]]
support of the issuance of a set-aside allowance that can be used in
accordance with Sec. 62.16240, must meet the requirements of this
section.
(b) General M&V report criteria. Each M&V report must include the
information in paragraphs (b)(1) and (2) of this section.
(1) For the first M&V report submitted, documentation that the
electricity-generating resources, electricity-saving measures, or
practices were installed or implemented consistent with the description
in the approved eligibility application required in Sec.
62.16245(a)(3).
(2) For each M&V report submitted:
(i) Identification of the time period covered by the M&V report;
(ii) A description of how relevant quantification methods,
protocols, guidelines, and guidance specified in the EM&V plan were
applied during the reporting period to generate the quantified MWh of
generation or MWh of electricity savings;
(iii) Documentation (including data) of the energy generation and/
or electricity savings from any activity, project, measure, or program
addressed in the EM&V report, quantified and verified in MWh for the
period covered by the M&V report, in accordance with its EM&V plan, and
based on ex-post energy generation or savings;
(iv) Documentation of any change in the energy generation or
savings capability of the eligible resource during the period covered
by the M&V report and the date on which the change occurred, and either
certification that the eligible resource continued to meet all
eligibility requirements during the reporting period covered by the M&V
report or disclosure of any material changes to the eligible resource
from the description of the eligible resource in the approved
eligibility application, which must include any change in the energy
generation (e.g., nameplate MW capacity) or electricity savings
capability of the qualifying eligible resource (including the date of
the change); and
(v) Documentation of any change in ownership interest of the
qualifying eligible resource (including the date of the change).
(c) You must ensure that any M&V report submitted pursuant to this
subpart includes the following certification:
(1) ``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) [Reserved]
Sec. 62.16270 What are the requirements for verification reports?
(a) A verification report included as part of an eligibility
application or an M&V report must meet the requirements of paragraph
(b) of this section (for the eligibility application verification
report) and paragraph (c) of this section (for the M&V report
verification report) and include the following:
(1) A verification statement that sets forth the findings of the
accredited independent verifier, based on the verifier's assessment of
the information and data in the eligibility application or M&V report
that is the subject of the verification report, including an assessment
of whether the eligibility application or M&V report contains any
material misstatements or material data discrepancies, and whether the
submittal conforms with applicable regulatory requirements. The
verification statement must clearly identify how levels of assurance
and materiality are defined as part of the verifier assessment.
(2) The following statement, signed by the accredited independent
verifier: ``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
personal knowledge and/or 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) A verification report included as part of an eligibility
application must, at a minimum, describe the review conducted by the
accredited independent verifier and verify each of the following:
(1) The eligibility of the eligible resource to be issued set-aside
allowances pursuant to this regulation, in accordance with Sec.
62.16245(a), including an analysis of the adequacy and validity of the
information submitted by the authorized account representative to
demonstrate that the eligible resource meets each applicable
requirement of Sec. 62.16245;
(2) The eligible resource is not duplicative of a resource used to
meet emission standards or a state measure in another approved State
plan;
(3) The eligible resource exists or the operation or activity will
be implemented in the manner specified in the eligibility application;
(4) That the EM&V plan meets the requirements of Sec. 62.16260;
(5) Disclosure of any mandatory or voluntary programs to which data
is reported relating to the eligible resource (e.g., reporting of
electric generation by a renewable energy resource to a renewable
energy certificate tracking system); and
(6) Any other information required by the Administrator or that the
accredited independent verifier finds, in its professional opinion, is
necessary to assess the adequacy and validity of information and data
supplied by the authorized account representative.
(c) A verification report included as part of an M&V report must,
at a minimum, describe the review conducted by the accredited
independent verifier and verify the information specified in paragraphs
(c)(1) through (3) of this section.
(1) The adequacy and validity of the information and data submitted
in the submittal by the authorized account representative to quantify
eligible MWh of electric generation or electricity savings during the
period for which the authorized account representative seeks issuance
of set-aside allowances, as well as all supporting information and data
identified in the EM&V plan and M&V report. This analysis must include
a quality assurance and quality control check of the data and ensure
that all generation or savings data is within a technically feasible
range for that specific eligible resource.
(i) For metered generation, the data validity check must compare
reported electricity generation to an engineering estimate of the
maximum generation potential of the qualified renewable energy
resource, based on, at a minimum, its maximum nameplate capacity in MW
and the number of days since the prior cumulative meter reading was
entered in the allowance tracking system. If the data entered exceeds
the estimated technically feasible generation, then the reported data
and the estimate must be analyzed in the verification report.
(ii) For all electricity generated or saved, the accredited
independent verifier must describe the likely source of any data
discrepancy and determine
[[Page 65075]]
in the verification report any MWh generated or saved.
(2) The M&V report meets the requirements of Sec. 62.16265.
(3) Any other information required by the Administrator or that the
accredited independent verifier finds, in its professional opinion, is
necessary to assess the adequacy and validity of information and data
supplied by the authorized account representative.
Sec. 62.16275 What is the accreditation procedure for independent
verifiers?
(a) Only Administrator-accredited independent verifiers may provide
a verification report for an eligibility application or M&V report.
(b) Applications for accreditation must follow a procedure and form
specified by the Administrator which includes a demonstration by the
verifier that it meets the requirements in paragraph (c) of this
section.
(c) Independent verifiers must meet each of the requirements in
paragraphs (c)(1) through (6) of this section to be accredited.
(1) Independent verifiers must have the skills, experience,
resources (personnel and otherwise) to provide verification reports,
including the following:
(i) Appropriate technical qualification (professional engineer or
otherwise) to evaluate the eligible resource for which the independent
verifier is seeking accreditation, which may include ANSI accreditation
under ISO 14065 for GHG validation and verification bodies;
(ii) Appropriate auditing and accounting qualifications for
financial and non-financial data monitoring, auditing, and quality
assurance and quality control to evaluate the eligible resource for
which the independent verifier is seeking accreditation;
(iii) Knowledge of the requirements of the Administrator's
CO2 Mass-based Trading Program regulations and related
guidance;
(iv) Knowledge of the eligible resource categories for which the
independent verifier is seeking accreditation, including relevant
aspects of the design, operation, and related energy generation or
electricity savings monitoring and reporting approaches for such
eligible resources; and
(v) Capability to perform key verification activities, such as
development of a verification report; site visits; review and
recalculation of reported data; review of data management systems;
review of quantification methods used in accordance with an approved
EM&V plan; preparation of a verification opinion, list of findings, and
verification report; and internal review of the verification findings
and report.
(2) Independent verifiers must document, in the application for
accreditation, the independent verifiers that will provide verification
services, including lead verifiers, key personnel and any contractors
or subcontractors (collectively, accredited independent verification
team) and demonstrate that they meet the requirements of paragraph
(c)(1) of this section. Once accredited, only the accredited
independent verification team identified in the accreditation
application and accredited by the State may provide a verification
report.
(3) An independent verifier must specify the eligible resource
categories for which it is seeking accreditation, and an accredited
independent verifier may only provide verification services related to
an eligible resource category for which it is accredited.
(4) Prospective independent verifiers must meet the requirements of
Sec. 62.16280(d) through (f) and demonstrate that they have in place
adequate systems and protocols to identify, disclose and avoid
potential conflicts of interest.
(5) An accredited independent verifier must not be debarred,
suspended, or proposed for debarment pursuant to the Government-wide
Debarment and Suspension regulations, 40 CFR part 32 of this chapter,
or the Debarment, Suspension and Ineligibility provisions of the
Federal Acquisition Regulations, 48 CFR part 9, subpart 9.4.
(6) An accredited independent verifier must maintain, for its
employees, and ensure the maintenance of, for any parties that it
employs, professional liability insurance, as defined in 31 CFR
50.5(q), through an insurance provider that possesses a financial
strength rating in the top four categories from either Standard &
Poor's or Moody's, specifically, AAA, AA, A or BBB for Standard &
Poor's, and Aaa, Aa, A, or Baa for Moody's. Any entity covered by this
paragraph must disclose the level of professional liability insurance
they possess when entering into contracts to provide verification
services pursuant to this regulation.
(d) Requirements for maintenance of accreditation status.
(1) Accredited independent verifiers must meet the requirements of
Sec. 62.16280 when providing verification services for an authorized
account representative.
(2) The instances specified in Sec. 62.16280(d) are cause for
revocation of a verifier's accreditation.
Sec. 62.16280 What are the procedures accredited independent
verifiers must follow to avoid conflict of interest?
(a) Accredited independent verifiers must not provide verification
services for any eligible resource for which it has a conflict of
interest (COI), which means:
(1) Accredited independent verifiers must have, or have had, no
direct or indirect financial interest in, or other financial
relationships with, an eligible resource, or any prospective eligible
resource, for which they seek to provide a verification report;
(2) Accredited independent verifiers must have, or have had, no
direct or indirect organizational or personal relationships with an
eligible resource, that would impact their impartiality in assessing
the validity and accuracy of the information in an eligibility
application or M&V report;
(3) Accredited independent verifiers must have, or have had, no
role in the development and implementation of an eligible resource for
which an authorized account representative seeks issuance of set-aside
allowances, beyond the provision of verification services;
(4) Accredited independent verifiers must not be compensated,
financially or otherwise, directly or indirectly, on the basis of the
content of its verification report (including eligibility approval of
an eligible resource, the quantified and verified MWh in an M&V report,
set-aside allowance issuance, or the number of set-aside allowances
issued);
(5) Accredited independent verifiers must not own, buy, sell, or
hold set-aside allowances, or other financial derivatives related to
set-aside allowances, or have a financial relationship with other
parties that own, buy, sell, or hold set-aside allowances or other
related financial derivatives;
(6) An accredited independent verifier must not be incapable of
providing an impartial verification report for any other reason; and
(7) An accredited independent verifier must ensure that the subject
of any verification report must not have the opportunity to review or
influence any draft or final verification report before its submittal
to the Administrator, and the accredited independent verifier must
share any drafts of its reports with the Administrator at the same time
as it shares them with the subject of the report.
(b) A contract with an eligible resource for the provision of
verification services will not constitute a COI.
(c) Verification reports must include an attestation by the
accredited independent verifier that it evaluated
[[Page 65076]]
and disclosed to the Administrator any potential COI related to an
eligible resource.
(d) Prior to engaging for the provision of verification services,
an accredited independent verifier must demonstrate that it has no COI
related to the eligible resource, as specified in paragraph (a) of this
section. If a COI is identified for a person or persons within an
accredited independent verifier for a specific subject or verification,
in accordance with paragraphs (e) and (f) of this section, then an
accredited independent verifier may propose to the Administrator steps
that will be taken to eliminate the COI, which include prohibiting the
person or persons with the conflict from any involvement in the matter
subject to the conflict, including verification services, access to
information related to the verification services, access to any draft
or final verification reports, any communications with the person(s)
conducting the verification services. In no instance shall an
accredited independent verifier engage in verification services for an
eligible resource without the approval of the Administrator.
(e) Prior to engaging in verification services and writing a
verification report, an accredited independent verifier must disclose
to the Administrator all information necessary for the Administrator to
evaluate a potential COI (including information concerning its
ownership, past and current clients, related entities, as well as any
other facts or circumstances that have the potential to create a COI).
(f) Accredited verifiers have an ongoing obligation to disclose to
the Administrator any facts or circumstances that may give rise to a
COI as defined in paragraph (a) of this section.
(g) The Administrator may reject a verification report from an
accredited independent verifier, if the Administrator determines that
the accredited independent verifier has a COI as defined in paragraph
(a) of this section. If the Administrator rejects an accredited
independent verifier report for such reasons, then the eligibility
application or M&V report submittal shall be deemed incomplete and set-
aside allowances must not be issued pursuant to it.
Sec. 62.16285 What is the process for the revocation of accreditation
status for an independent verifier?
(a) The Administrator may revoke the accreditation of an
independent verifier at any time for cause, including for the reasons
specified in paragraphs (a)(1) through (4) of this section.
(1) Failure to fully disclose any issues that may lead to a COI
with respect to an eligible resource, or other related entity, in
accordance with Sec. 62.16280(d) through (f).
(2) The accredited independent verifier is no longer qualified to
provide verification services.
(3) Negligence in the conduct of verification activities, or
neglect of responsibilities pursuant to the requirements of Sec. Sec.
62.16270, 62.16275, and 62.16280.
(4) Intentional misrepresentation of data in a verification report.
(b) [Reserved]
Designated Representatives
Sec. 62.16290 How are designated representatives and alternate
designated representatives authorized, and what role do authorized
designated representatives and alternate designated representatives
play?
(a) Except as provided under Sec. 62.16300, each facility,
including all affected EGUs at the facility, shall have one and only
one designated representative, with regard to all matters under the
CO2 Mass-based Trading Program.
(1) The designated representative shall be selected by an agreement
binding on the owners and operators of the facility and all affected
EGUs at the facility and must act in accordance with the certification
statement in Sec. 62.16305(a)(4)(iii).
(2) Upon and after receipt by the Administrator of a complete
certificate of representation under Sec. 62.16305:
(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 facility and
each affected EGU at the facility in all matters pertaining to the
CO2 Mass-based Trading Program, notwithstanding any
agreement between the designated representative and such owners and
operators; and
(ii) The owners and operators of the facility and each affected EGU
at the facility shall be bound by any decision or order issued to the
designated representative by the Administrator regarding the facility
or any such affected EGU.
(b) Except as provided under Sec. 62.16300, each facility 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 must 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 facility and all
affected EGUs at the facility and must act in accordance with the
certification statement in Sec. 62.16305(a)(4)(iii).
(2) Upon and after receipt by the Administrator of a complete
certificate of representation under Sec. 62.16305:
(i) The alternate designated representative must 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 facility and each affected
EGU at the facility shall be bound by any decision or order issued to
the alternate designated representative by the Administrator regarding
the facility or any such affected EGU.
(c) Except in this section, Sec. 62.16375, and Sec. Sec. 62.16295
through 62.16315, whenever the term ``designated representative'' (as
distinguished from the term ``common designated representative'') is
used in this subpart, the term shall be construed to include the
designated representative or any alternate designated representative.
Sec. 62.16295 What responsibilities do designated representatives and
alternate designated representatives hold?
(a) Except as provided under Sec. 62.16315 concerning delegation
of authority to make submissions, each submission under the
CO2 Mass-based Trading Program shall be made, signed, and
certified by the designated representative or alternate designated
representative for each facility and affected EGU for which the
submission is made. Each such submission must 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 facility or affected EGUs 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
[[Page 65077]]
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
facility or an affected EGU only if the submission has been made,
signed, and certified in accordance with paragraph (a) of this section
and Sec. 62.16315.
Sec. 62.16300 What are the processes for changing designated
representative, alternate designated representative, owners and
operators, and affected EGUs at the facility?
(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. 62.16305. 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 facility and the affected EGUs at the facility.
(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. 62.16305. 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 facility and the affected EGUs at the facility.
(c) Changes in owners and operators. (1) In the event an owner or
operator of a facility or an affected EGU at the facility is not
included in the list of owners and operators in the certificate of
representation under Sec. 62.16305, 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 facility or affected EGU, 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 facility or an affected EGU at the facility, including the addition
or removal of an owner or operator, the designated representative or
any alternate designated representative must submit a revision to the
certificate of representation under Sec. 62.16305 amending the list of
owners and operators to reflect the change.
(d) Changes in affected EGUs at the facility. Within 30 days of any
change in which affected EGUs are located at a facility (including the
addition or removal of an affected EGU), the designated representative
or any alternate designated representative must submit a certificate of
representation under Sec. 62.16305 amending the list of affected EGUs
to reflect the change.
(1) If the change is the addition of an affected EGU that operated
(other than for purposes of testing by the manufacturer before initial
installation) before being located at the facility, then the
certificate of representation must identify, in a format prescribed by
the Administrator, the entity from whom the affected EGU was purchased
or otherwise obtained (including name, address, telephone number, and
facsimile transmission number (if any)), the date on which the affected
EGU was purchased or otherwise obtained, and the date on which the
affected EGU became located at the facility.
(2) If the change is the removal of an affected EGU, then the
certificate of representation must identify, in a format prescribed by
the Administrator, the entity to which the affected EGU was sold or
that otherwise obtained the affected EGU (including name, address,
telephone number, email address and facsimile transmission number (if
any)), the date on which the affected EGU was sold or otherwise
obtained, and the date on which the affected EGU became no longer
located at the facility.
Sec. 62.16305 What must be included in a certificate of
representation?
(a) A complete certificate of representation for a designated
representative or an alternate designated representative must include
the following elements in a format prescribed by the Administrator:
(1) Identification of the facility, and each affected EGU at the
facility, for which the certificate of representation is submitted,
including facility and affected EGU names, facility 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 affected
EGU, actual or projected date of commencement of commercial operation,
net summer capacity at the affect EGU, and a statement of whether such
facility is located in Indian country. If a projected date of
commencement of commercial operation is provided, then the actual date
of commencement of commercial operation must be provided when such
information becomes available.
(2) The name, address, email 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 facility and of each
affected EGU at the facility.
(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 facility and
each affected EGU at the facility''; and
(ii) ``I certify that I have all the necessary authority to carry
out my duties and responsibilities under the CO2 Mass-based
Trading Program on behalf of the owners and operators of the facility
and of each affected EGU at the facility and that each such owner and
operator shall be fully bound by my representations, actions,
inactions, or submissions and by any decision or order issued to me by
the Administrator regarding the facility or unit.''
(iii) ``Where there are multiple holders of a legal or equitable
title to, or a leasehold interest in, an affected EGU, or where a
utility or industrial customer purchases power from an affected EGU
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 facility and of each affected EGU at the facility;
and CO2 allowances and proceeds of transactions involving
CO2 Mass-based Trading 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 CO2 allowances by contract, then
CO2 allowances and proceeds of transactions involving
CO2 Mass-based Trading allowances will be deemed to be held
or
[[Page 65078]]
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. 62.16310 What is the Administrator's role in objections
concerning designated representatives and alternate designated
representatives?
(a) Once a complete certificate of representation under Sec.
62.16305 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. 62.16305 is received
by the Administrator.
(b) Except as provided in paragraph (a) of this section, no
objection or other communication submitted to the Administrator
concerning the authorization, or any representation, action, inaction,
or submission, of a designated representative or alternate designated
representative shall affect any representation, action, inaction, or
submission of the designated representative or alternate designated
representative or the finality of any decision or order by the
Administrator under the CO2 Mass-based 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 CO2 allowance transfers.
Sec. 62.16315 What process must designated representatives and
alternate designated representatives follow to delegate their
authority?
(a) A designated representative may delegate, to one or more
natural persons, his or her authority to make an electronic submission
to the Administrator provided for or required under this subpart.
(b) An alternate designated representative may delegate, to one or
more natural persons, his or her authority to make an electronic
submission to the Administrator provided for or required under this
subpart.
(c) In order to delegate authority to a natural person to make an
electronic submission to the Administrator in accordance with paragraph
(a) or (b) of this section, the designated representative or alternate
designated representative, as appropriate, must submit to the
Administrator a notice of delegation, in a format prescribed by the
Administrator, that includes the elements in paragraphs (c)(1) through
(4) of this section.
(1) The name, address, email address, telephone number, and
facsimile transmission number (if any) of such designated
representative or alternate designated representative.
(2) The name, address, email address, telephone number, and
facsimile transmission number (if any) of each such natural person
(referred to in this section as an ``agent'').
(3) For each such natural person, a list of the type or types of
electronic submissions under paragraph (a) or (b) of this section for
which authority is delegated to him or her.
(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 Sec. 62.16315(d)
shall be deemed to be an electronic submission by me''; and
(ii) ``Until this notice of delegation is superseded by another
notice of delegation under Sec. 62.16315(d), I agree to maintain an
email account and to notify the Administrator immediately of any change
in my email address unless all delegation of authority by me under
Sec. 62.16315 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.
Monitoring, Recordkeeping, Reporting
Sec. 62.16320 How are compliance accounts and general accounts
established?
(a) Compliance accounts. Upon receipt of a complete certificate of
representation under Sec. 62.16305, the Administrator will establish a
compliance account for the facility for which the certificate of
representation was submitted, unless the facility already has a
compliance account. The designated representative and any alternate
designated representative of the facility shall be the authorized
account representative and the alternate authorized account
representative respectively of the compliance account.
(b) Retirement accounts. (1) A retirement account, into which
allowances held in a compliance account for an affected EGU are
surrendered by the owner or operator of an affected EGU, for use in
demonstrating compliance with its emission standards. The retirement
account may only be held by the Administrator, and allowances deposited
into it are permanently retired. Once an allowance is retired, the
allowance shall no longer be transferable to another account in that
allowance tracking system or any other allowance tracking system.
(2) [Reserved]
(c) General accounts--(1) Application for a general account. (i)
Any person may apply to open a general account, for the purpose of
holding and transferring CO2 allowances, by submitting to
the Administrator a complete application for a general account. Such
application must 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 CO2
allowances held in the general account.
(B) The agreement by which the alternate authorized account
representative is selected must include
[[Page 65079]]
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 must include the
following elements in a format prescribed by the Administrator:
(A) Name, mailing address, email 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 CO2 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 CO2 allowances held in the general account.
I certify that I have all the necessary authority to carry out my
duties and responsibilities under the CO2 Mass-based Trading
Program on behalf of such persons and that each such person shall be
fully bound by my representations, actions, inactions, or submissions
and by any decision or order issued to me by the Administrator
regarding the general account''; and
(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 (c)(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 CO2
allowances held in the general account in all matters pertaining to the
CO2 Mass-based 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; and
(C) Each person who has an ownership interest with respect to
CO2 allowances held in the general account shall be bound by
any decision or order issued to the authorized account representative
or alternate authorized account representative by the Administrator
regarding the general account.
(ii) Except as provided in paragraph (c)(5) of this section
concerning delegation of authority to make submissions, each submission
concerning the general account shall be made, signed, and certified by
the authorized account representative or any alternate authorized
account representative for the persons having an ownership interest
with respect to CO2 allowances held in the general account.
Each such submission must 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
CO2 allowances held in the general account. I certify under
penalty of law that I have personally examined, and am familiar with,
the statements and information submitted in this document and all its
attachments. Based on my inquiry of those individuals with primary
responsibility for obtaining the information, I certify that the
statements and information are to the best of my knowledge and belief
true, accurate, and complete. I am aware that there are significant
penalties for submitting false statements and information or omitting
required statements and information, including the possibility of fine
or imprisonment.''
(iii) Except in this section, whenever the term ``authorized
account representative'' is used in this subpart, the term shall be
construed to include the authorized account representative or any
alternate authorized account representative.
(3) Changing authorized account representative and alternate
authorized account representative; changes in persons with ownership
interest.
(i) The authorized account representative of a general account may
be changed at any time upon receipt by the Administrator of a
superseding complete application for a general account under paragraph
(c)(1) of this section. Notwithstanding any such change, all
representations, actions, inactions, and submissions by the previous
authorized account representative before the time and date when the
Administrator receives the superseding application for a general
account shall be binding on the new authorized account representative
and the persons with an ownership interest with respect to the
CO2 allowances in the general account.
(ii) The alternate authorized account representative of a general
account may be changed at any time upon receipt by the Administrator of
a superseding complete application for a general account under
paragraph (c)(1) of this section. Notwithstanding any such change, all
representations, actions, inactions, and submissions by the previous
alternate authorized account representative before the time and date
when the Administrator receives the superseding application for a
general account shall be binding on the new alternate authorized
account representative, the authorized account representative, and the
persons with an ownership interest with respect to the CO2
allowances in the general account.
(iii)(A) In the event a person having an ownership interest with
respect to CO2 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 CO2 allowances in the
general account, including the addition or removal of a person, the
authorized account representative or any alternate authorized account
representative must submit a revision to the application for a general
account amending the list of persons having an ownership interest with
respect to the
[[Page 65080]]
CO2 allowances in the general account to include the change.
(4) Objections concerning authorized account representative and
alternate authorized account representative.
(i) Once a complete application for a general account under
paragraph (c)(1) of this section has been submitted and received, the
Administrator will rely on the application unless and until a
superseding complete application for a general account under paragraph
(c)(1) of this section is received by the Administrator.
(ii) Except as provided in paragraph (c)(4)(i) of this section, no
objection or other communication submitted to the Administrator
concerning the authorization, or any representation, action, inaction,
or submission of the authorized account representative or any alternate
authorized account representative of a general account shall affect any
representation, action, inaction, or submission of the authorized
account representative or any alternate authorized account
representative or the finality of any decision or order by the
Administrator under the CO2 Mass-based 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
CO2 allowance transfers.
(5) Delegation by authorized account representative and alternate
authorized account representative. (i) An authorized account
representative of a general account may delegate, to one or more
natural persons, his or her authority to make an electronic submission
to the Administrator provided for or required under this subpart.
(ii) An alternate authorized account representative of a general
account may delegate, to one or more natural persons, his or her
authority to make an electronic submission to the Administrator
provided for or required under this subpart.
(iii) In order to delegate authority to a natural person to make an
electronic submission to the Administrator in accordance with paragraph
(c)(5)(i) or (ii) of this section, the authorized account
representative or alternate authorized account representative, as
appropriate, must submit to the Administrator a notice of delegation,
in a format prescribed by the Administrator, that includes the
following elements:
(A) The name, address, email address, telephone number, and
facsimile transmission number (if any) of such authorized account
representative or alternate authorized account representative;
(B) The name, address, email address, telephone number, and
facsimile transmission number (if any) of each such natural person
(referred to in this section as an ``agent'');
(C) For each such natural person, a list of the type or types of
electronic submissions under paragraph (c)(5)(i) or (ii) of this
section for which authority is delegated to him or her;
(D) The following certification statement by such authorized
account representative or alternate authorized account representative:
``I agree that any electronic submission to the Administrator that is
made by an agent identified in this notice of delegation and of a type
listed for such agent in this notice of delegation and that is made
when I am an authorized account representative or alternate authorized
representative, as appropriate, and before this notice of delegation is
superseded by another notice of delegation under Sec.
62.16320(c)(5)(iv) shall be deemed to be an electronic submission by
me''; and
(E) The following certification statement by such authorized
account representative or alternate authorized account representative:
``Until this notice of delegation is superseded by another notice of
delegation under Sec. 62.16320(c)(5)(iv), I agree to maintain an email
account and to notify the Administrator immediately of any change in my
email address unless all delegation of authority by me under Sec.
62.16320(c)(5) is terminated.''
(iv) A notice of delegation submitted under paragraph (c)(5)(iii)
of this section shall be effective, with regard to the authorized
account representative or alternate authorized account representative
identified in such notice, upon receipt of such notice by the
Administrator and until receipt by the Administrator of a superseding
notice of delegation submitted by such authorized account
representative or alternate authorized account representative, as
appropriate. The superseding notice of delegation may replace any
previously identified agent, add a new agent, or eliminate entirely any
delegation of authority.
(v) Any electronic submission covered by the certification in
paragraph (c)(5)(iii)(D) of this section and made in accordance with a
notice of delegation effective under paragraph (c)(5)(iv) of this
section shall be deemed to be an electronic submission by the
designated representative or alternate designated representative
submitting such notice of delegation.
(6) Closing a general account. (i) The authorized account
representative or alternate authorized account representative of a
general account may submit to the Administrator a request to close the
account. Such request must include a correctly submitted CO2
allowance transfer under Sec. 62.16330 for any CO2
allowances in the account to one or more other ATCS accounts.
(ii) If a general account has no CO2 allowance transfers
to or from the account for a 12-month period or longer and does not
contain any CO2 allowances, then the Administrator may
notify the authorized account representative for the account that the
account will be closed 30 days after the notice is sent. The account
will be closed after the 30-day period unless, before the end of the
30-day period, the Administrator receives a correctly submitted
CO2 allowance transfer under Sec. 62.16330 to the account
or a statement submitted by the authorized account representative or
alternate authorized account representative demonstrating to the
satisfaction of the Administrator good cause as to why the account
should not be closed.
(d) Account identification. The Administrator will assign a unique
identifying number to each account established under paragraphs (a)
through (c) of this section.
(e) Responsibilities of authorized account representative and
alternate authorized account representative. After the establishment of
a compliance account or general account, the Administrator will accept
or act on a submission pertaining to the account, including, but not
limited to, submissions concerning the deduction or transfer of
CO2 allowances in the account, only if the submission has
been made, signed, and certified in accordance with Sec. Sec.
62.16295(a) and 62.16315 or paragraphs (c)(2)(ii) and (c)(5) of this
section.
Sec. 62.16325 When will CO2 allowances be recorded in compliance
accounts?
(a) By June 1, 2021, and by June 1 of each year prior to the
beginning of each compliance period thereafter, the Administrator will
record in each facility's compliance account the CO2
allowances allocated to the affected EGUs at the facility in accordance
with Sec. 62.16240(a), or with a state allowance-distribution
methodology approved under subpart UUUU of part 60 of this
[[Page 65081]]
chapter, for the upcoming compliance period.
(b) Except as specified in paragraph (a) of this section, the
Administrator will record an allocation in the appropriate ATCS account
by the date on which any allocation of CO2 allowances to a
recipient must be made by or submitted to the Administrator in
accordance with either Sec. 62.16240 or with state allowance-
distribution methodology approved under subpart UUUU of part 60 of this
chapter.
(c) When recording the allocation of CO2 allowances to
an affected EGU or other entity in an ATCS account, the Administrator
will assign each CO2 allowance a unique serial number that
will include digits identifying the year of the compliance period for
which the CO2 allowance is allocated.
(d) By December 1, 2021 and December 1 of each year thereafter, the
Administrator will record in each renewable energy project's general
account, the CO2 allowances allocated from the renewable
energy set-aside to the project in accordance with Sec. 62.16245(a),
for the following year.
(e) By November 1 of the first year of each compliance period
beginning in 2025, and each compliance period thereafter, the
Administrator will record in each facility's compliance account the
CO2 allowances allocated from the output-based set-aside to
the eligible EGUs at the facility in accordance with Sec. 62.16245(b)
or with a state allowance-distribution methodology approved under
subpart UUUU of part 60 of this chapter, for the following year.
Sec. 62.16330 How must transfers of CO2 allowances be submitted?
(a) An authorized account representative seeking recordation of a
CO2 allowance transfer must submit the transfer to the
Administrator.
(b) A CO2 allowance transfer is 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 CO2 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 CO2 allowance identified by
serial number in the transfer.
Sec. 62.16335 When will CO2 allowance transfers be recorded?
(a) Within 5 business days (except as provided in paragraph (b) of
this section) of receiving a CO2 allowance transfer that is
correctly submitted under Sec. 62.16330, the Administrator will record
a CO2 allowance transfer by moving each CO2
allowance from the transferor account to the transferee account as
specified in the transfer.
(b) A CO2 allowance transfer to or from a compliance
account that is submitted for recordation after the allowance transfer
deadline for a compliance period and that includes any CO2
allowances allocated for any compliance period before such allowance
transfer deadline will not be recorded until after the Administrator
completes the deductions from such compliance account under Sec.
62.16340 for the compliance period immediately before such allowance
transfer deadline.
(c) Where a CO2 allowance transfer is not correctly
submitted under Sec. 62.16330, the Administrator will not record such
transfer.
(d) Within 5 business days of recordation of a CO2
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 CO2
allowance transfer that is not correctly submitted under Sec.
62.16330, 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. 62.16340 How will deductions for compliance with a CO2 emission
standard occur?
(a) Availability for deduction for compliance. CO2
allowances are available to be deducted for compliance with a
facility's CO2 emission standard for a compliance period
only if the CO2 allowances:
(1) Were allocated for a year in such compliance period or a prior
compliance period; and
(2) Are held in the facility's compliance account as of the
allowance transfer deadline for such compliance period.
(b) Deductions for compliance. After the recordation, in accordance
with Sec. 62.16335, of CO2 allowance transfers submitted by
the allowance transfer deadline for a compliance period, the
Administrator will deduct from each facility's compliance account
CO2 allowances available under paragraph (a) of this section
in order to determine whether the facility meets the CO2
emission standard for such compliance period, as follows:
(1) Until the amount of CO2 allowances deducted equals
the number of tons of total CO2 emissions from all affected
EGUs at the facility for such compliance period; or
(2) If there are insufficient CO2 allowances to complete
the deductions in paragraph (b)(1) of this section, until no more
CO2 allowances available under paragraph (a) of this section
remain in the compliance account.
(c)(1) Identification of CO2 allowances by serial
number. The authorized account representative for a facility's
compliance account may request that specific CO2 allowances,
identified by serial number, in the compliance account be deducted for
emissions or excess emissions for a compliance period in accordance
with paragraph (b) or (d) of this section. In order to be complete,
such request must be submitted to the Administrator by the allowance
transfer deadline for such compliance period and include, in a format
prescribed by the Administrator, the identification of the facility and
the appropriate serial numbers.
(2) First-in, first-out. The Administrator will deduct
CO2 allowances under paragraph (b) or (d) of this section
from the facility'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 CO2 allowances in such request, on a first-in, first-out
accounting basis in the following order:
(i) Any CO2 allowances that were allocated to the
affected EGUs at the facility and not transferred out of the compliance
account, in the order of recordation; and then
(ii) Any CO2 allowances that were allocated to any
affected EGU or other entity 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 compliance
period in a year in which the facility has excess emissions, the
Administrator will deduct from the facility's compliance account an
amount of CO2 allowances, allocated for a compliance period
in a prior year or the compliance period in the year of the excess
emissions or in the immediately following year, equal to two times the
number of tons of the facility's excess emissions.
[[Page 65082]]
(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. 62.16345 What monitoring requirements must I comply with?
(a) The owner or operator of an affected EGU must prepare a
monitoring plan in accordance with the applicable provisions in Sec.
75.53(g) and (h) of this chapter, unless such a plan is already in
place under another program that requires CO2 mass emissions
to be monitored and reported according to part 75 of this chapter. You
must follow the requirements described in paragraphs (a)(1) through (8)
of this section to monitor emissions and net energy output at your
affected EGU.
(1) For each operating hour, calculate the hourly CO2
mass (tons) according to paragraph (a)(4) or (5) of this section,
except that a complete data record is required, i.e., CO2
mass emissions must be reported for each operating hour. Therefore,
substitute data values recorded under part 75 of this chapter for
CO2 concentration, stack gas flow rate, stack gas moisture
content, fuel flow rate and/or gross calorific value (GCV) must be used
in the calculations; and
(2) Sum all of the hourly CO2 mass emissions values over
the entire compliance period.
(3) The owner or operator of an affected EGU must install,
calibrate, maintain, and operate a sufficient number of watt meters to
continuously measure and record on an hourly basis net electric output.
Measurements must be performed using 0.2 accuracy class electricity
metering instrumentation and calibration procedures as specified under
ANSI Standards No. C12.20. Further, the owner or operator of an
affected EGU that is a combined heat and power facility must install,
calibrate, maintain and operate equipment to continuously measure and
record on an hourly basis useful thermal output and, if applicable,
mechanical output, which are used with net electric output to determine
net energy output (Pnet). The owner or operator must
calculate net energy output according to paragraphs (a)(6)(i)(A) and
(B) of this section.
(4) The owner or operator of an affected EGU must measure and
report the hourly CO2 mass emissions (lbs) from each
affected unit using the procedures in paragraphs (a)(4)(i) through (vi)
of this section, except as otherwise provided in paragraph (a)(5) of
this section.
(i) The owner or operator of an affected EGU must install, certify,
operate, maintain, and calibrate a CO2 continuous emissions
monitoring system (CEMS) to directly measure and record CO2
concentrations in the affected EGU exhaust gases emitted to the
atmosphere and an exhaust gas flow rate monitoring system according to
Sec. 75.10(a)(3)(i) of this chapter. However, when an O2
monitor is used this way, it only quantifies the combustion
CO2; therefore, if the EGU is equipped with emission
controls that produce non-combustion CO2 (e.g., from sorbent
injection), then this additional CO2 must be accounted for,
in accordance with section 3 of appendix G to part 75 of this chapter.
As an alternative to direct measurement of CO2
concentration, provided that the affected EGU does not use carbon
separation (e.g., carbon capture and storage), the owner or operator of
an affected EGU may use data from a certified oxygen (O2)
monitor to calculate hourly average CO2 concentrations, in
accordance with Sec. 75.10(a)(3)(iii) of this chapter. If
CO2 concentration is measured on a dry basis, then the owner
or operator of the affected EGU must also install, certify, operate,
maintain, and calibrate a continuous moisture monitoring system,
according to Sec. 75.11(b) of this chapter. Alternatively, the owner
or operator of an affected EGU may either use an appropriate fuel-
specific default moisture value from Sec. 75.11(b) or submit a
petition to the Administrator under Sec. 75.66 of this chapter for a
site-specific default moisture value.
(ii) Calculate the hourly CO2 mass emission rate (tons/
hr), either from Equation F-11 in Appendix F to part 75 of this chapter
(if CO2 concentration is measured on a wet basis), or by
following the procedure in section 4.2 of Appendix F to part 75 of this
chapter (if CO2 concentration is measured on a dry basis).
CO2 mass emissions must be reported for each operating hour.
Therefore, substitute data values recorded under part 75 of this
chapter for CO2 concentration, stack gas flow rate, stack
gas moisture content, fuel flow rate and/or GCV must be used in the
calculations.
(iii) Next, multiply each hourly CO2 mass emission rate
by the EGU or stack operating time in hours (as defined in Sec. 72.2
of this chapter), to convert it to tons of CO2. Multiply the
result by 2000 lb/ton to convert it to lb.
(iv) The hourly CO2 tons/hr values and EGU (or stack)
operating times used to calculate CO2 mass emissions are
required to be recorded under Sec. 75.57(e) of this chapter and must
be reported electronically under Sec. 75.64(a)(6) of this chapter, if
required by a plan. The owner or operator must use these data, or
equivalent data, to calculate the hourly CO2 mass emissions.
(v) Sum all of the hourly CO2 mass emissions values that
were calculated according to procedures specified in paragraph
(a)(4)(ii) of this section over the entire compliance period.
(vi) For each continuous monitoring system used to determine the
CO2 mass emissions from an affected EGU, the monitoring
system must meet the applicable certification and quality assurance
procedures in Sec. 75.20 of this chapter and Appendices A and B to
part 75 of this chapter.
(5) The owner or operator of an affected EGU that exclusively
combusts liquid fuel and/or gaseous fuel may, as an alternative to
complying with paragraph (a)(4) of this section, determine the hourly
CO2 mass emissions according to paragraphs (a)(5)(i) through
(vi) of this section.
(i) Implement the applicable procedures in appendix D to part 75 of
this chapter to determine hourly EGU heat input rates (MMBtu/h), based
on hourly measurements of fuel flow rate and periodic determinations of
the gross calorific value (GCV) of each fuel combusted. The fuel flow
meter(s) used to measure the hourly fuel flow rates must meet the
applicable certification and quality-assurance requirements in sections
2.1.5 and 2.1.6 of appendix D (except for qualifying commercial billing
meters). The fuel GCV must be determined in accordance with section 2.2
or 2.3 of appendix D, as applicable.
(ii) For each measured hourly heat input rate, use Equation G-4 in
Appendix G to part 75 of this chapter to calculate the hourly
CO2 mass emission rate (tons/hr).
(iii) Determine the hourly CO2 mass emission rate (tons/
hr) using the procedures specified in paragraph (a)(4)(ii) of this
section and multiply it by the EGU or stack operating time in hours (as
defined in Sec. 72.2 of this chapter), to convert to tons of
CO2. Then, multiply the result by 2000 lb/ton to convert to
lb.
(iv) The hourly CO2 tons/hr values and EGU (or stack)
operating times used to calculate CO2 mass emissions are
required to be recorded under Sec. 75.57(e) of this chapter and must
be reported electronically under Sec. 75.64(a)(6), if required by a
plan. You must use these data, or equivalent data, to calculate the
hourly CO2 mass emissions.
(v) Sum all of the hourly CO2 mass emissions values (lb)
that were calculated according to procedures specified in paragraph
(a)(5)(iii) of this
[[Page 65083]]
section over the entire compliance period.
(vi) The owner or operator of an affected EGU may determine site-
specific carbon-based F-factors (Fc) using Equation F-7b in
section 3.3.6 of appendix F to part 75 of this chapter, and may use
these Fc values in the emissions calculations instead of
using the default Fc values in the Equation G-4
nomenclature.
(6) The owner or operator of an affected EGU must install,
calibrate, maintain, and operate a sufficient number of watt meters to
continuously measure and record on an hourly basis net electric output.
Measurements must be performed using 0.2 accuracy class electricity
metering instrumentation and calibration procedures as specified under
ANSI Standards No. C12.20. Further, the owner or operator of an
affected EGU that is a combined heat and power facility must install,
calibrate, maintain and operate equipment to continuously measure and
record on an hourly basis useful thermal output and, if applicable,
mechanical output, which are used with net electric output to determine
net energy output. The owner or operator must calculate net energy
output according to paragraph (a)(6)(i) of this section.
(i) For each operating hour of a compliance period that was used in
paragraph (a)(4) or (5) of this section to calculate the total
CO2 mass emissions, you must determine Pnet (the
corresponding hourly net energy output in MWh) according to the
procedures in paragraphs (a)(6)(i)(A) and (B) of this section, as
appropriate for the type of affected EGU(s). For an operating hour in
which a valid CO2 mass emissions value is determined
according to paragraph (a)(4) or (5) of this section, if there is no
gross or net electrical output, but there is mechanical or useful
thermal output, you must still determine the net energy output for that
hour. In addition, for an operating hour in which a valid
CO2 mass emissions value is determined according to
paragraph (a)(4) or (5) of this section, but there is no (i.e., zero)
gross electrical, mechanical, or useful thermal output, you must use
that hour in the compliance determination. For hours or partial hours
where the gross electric output is equal to or less than the auxiliary
loads, net electric output must be counted as zero for this
calculation.
(A) Calculate Pnet for your affected EGU using the
following equation. All terms in the equation must be expressed in
units of megawatt-hours (MWh). To convert each hourly net energy output
value reported under part 75 of this chapter to MWh, multiply by the
corresponding EGU or stack operating time.
[GRAPHIC] [TIFF OMITTED] TP23OC15.016
Where:
Pnet = Net energy output of your affected EGU in MWh.
(Pe)ST = Electric energy output plus mechanical energy
output (if any) of steam turbines in MWh.
(Pe)CT = Electric energy output plus mechanical energy
output (if any) of stationary combustion turbine(s) in MWh.
(Pe)IE = Electric energy output plus mechanical energy
output (if any) of your affected EGU's integrated equipment that
provides electricity or mechanical energy to the affected EGU or
auxiliary equipment in MWh.
(Pe)A = Electric energy used for any auxiliary loads in
MWh.
(Pt)PS = Useful thermal output of steam (measured
relative to SATP conditions as defined in Sec. 62.16375, as
applicable) that is used for applications that do not generate
additional electricity, produce mechanical energy output, or enhance
the performance of the affected EGU. This is calculated using the
equation specified in paragraph (a)(6)(i)(B) of this section in MWh.
(Pt)HR = Non steam useful thermal output (measured
relative to SATP conditions as defined in Sec. 62.16375, as
applicable) from heat recovery that is used for applications other
than steam generation or performance enhancement of the affected EGU
in MWh.
(Pt)IE = Useful thermal output (relative to SATP
conditions as defined in Sec. 62.16375, as applicable) from any
integrated equipment that is used for applications that do not
generate additional steam, electricity, produce mechanical energy
output, or enhance the performance of the affected EGU in MWh.
TDF = Electric Transmission and Distribution Factor of 0.95 for a
combined heat and power affected EGU where at least on an annual
basis 20.0 percent of the total net energy output consists of
electric or direct mechanical output and 20.0 percent of the total
net energy output consists of useful thermal output on a 12-
operating month rolling average basis, or 1.0 for all other affected
EGUs.
(B) If applicable to your affected EGU (for example, for combined
heat and power), you must calculate (Pt)PS using the
following equation:
[GRAPHIC] [TIFF OMITTED] TP23OC15.017
Where:
(Pt)ps = Useful thermal output of steam (measured
relative to SATP conditions as defined in Sec. 62.16375, as
applicable) that is used for applications that do not generate
additional electricity, produce mechanical energy output, or enhance
the performance of the affected EGU.
Qm = Measured steam flow in kilograms (kg) (or pounds
(lb)) for the operating hour.
H = Enthalpy of the steam at measured temperature and pressure
(relative to SATP conditions as defined in Sec. 62.16375 or the
energy in the condensate return line, as applicable) in Joules per
kilogram (J/kg) (or Btu/lb).
CF = Conversion factor of 3.6 x 10\9\ J/MWh or 3.413 x 10\6\ Btu/
MWh.
(ii) [Reserved]
(7) In accordance with Sec. 60.13(g), if two or more affected EGUs
implementing the continuous emissions monitoring provisions in
paragraph (a)(1) of this section share a common exhaust gas stack and
are subject to the same emissions standard, then the owner or operator
may monitor the hourly CO2 mass emissions at the common
stack in lieu of monitoring each EGU separately. If an owner or
operator of an affected EGU chooses this option, then the hourly net
electric output for the common stack must be the sum of the hourly net
electric output of the individual affected facility and the operating
time must be expressed as ``stack operating hours'' (as defined in
Sec. 72.2 of this chapter).
(8) In accordance with Sec. 60.13(g), if the exhaust gases from an
affected EGU implementing the continuous emissions monitoring
provisions in paragraph (a)(3) of this section are emitted to the
atmosphere through multiple stacks (or if the exhaust gases are routed
to a common stack through multiple ducts and you elect to monitor in
the ducts), the hourly CO2 mass emissions and the ``stack
operating time'' (as defined in Sec. 72.2 of this chapter) at each
stack or duct must be monitored separately. In this case, the owner or
operator of an affected EGU must determine compliance with an
applicable emissions standard by summing the CO2 mass
emissions measured at the individual stacks or ducts and dividing by
the net energy output for the affected EGU.
[[Page 65084]]
(b) [Reserved]
Sec. 62.16350 May I bank CO2 annual allowances for future use or
transfer?
(a) A CO2 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 CO2 allowance that is held in a compliance
account or a general account will remain in such account unless and
until the CO2 allowance is deducted or transferred under
Sec. Sec. 62.16240(b), 62.16335, 62.16340, 62.16355, or 62.16370.
Sec. 62.16355 How does the Administrator process account errors?
The Administrator may, at his or her sole discretion and on his or
her own motion, correct any error in any ATCS account. Within 10
business days of making such correction, the Administrator will notify
the authorized account representative for the account.
Sec. 62.16360 What are my reporting, notification and submission
requirements?
(a) You must prepare and submit reports according to paragraphs (a)
through (e) of this section, as applicable.
(1) You must meet all applicable reporting requirements and submit
reports as required under subpart G of part 75 of this chapter and you
must include the following information, as applicable in the quarterly
reports:
(i) The hourly CO2 mass emission rate value (tons/hr)
and unit (or stack) operating time, as monitored and reported according
to part 75 of this chapter, for each unit or stack operating hour in
the compliance period;
(ii) The calculated CO2 mass emissions (tons) for each
unit or stack operating hour in the compliance period;
(iii) The sum of the CO2 mass emissions (tons) for all
of the unit or stack operating hours in the compliance period;
(iv) The net electric output and the net energy output
(Pnet) values for each unit or stack operating hour in the
compliance period;
(v) The sum of the hourly net energy output values for all of the
unit or stack operating hours in the compliance period; and
(vi) If the report covers the final quarter of a compliance period,
then you must include the CO2 emission standard with which
your affected EGU must comply, the affected EGU's calculated emission
performance as a cumulative mass in units of the emission standard
required, and if an affected EGU is complying with an emission standard
by using allowances, then the designated representative must include in
their report a list of all unique allowance serial numbers retired in
the compliance period, and, for each allowance, the date an allowance
was surrendered and retired. If set-aside allowances were used from an
eligible resource by an affected EGU to comply with its emission
standard, then the designated representative must include in their
report the eligible resource identification information sufficient to
demonstrate that it meets the requirements of Sec. 62.16245 and
qualifies to be issued allowance set-asides (including location, type
of qualifying generation or savings, date commenced generating or
saving, and date of generation or savings for which the allowance was
issued).
(2) [Reserved]
(b) The designated representative of each affected EGU at the
facility must make all submissions required under the CO2
Mass-based Trading Program, except as provided in Sec. 62.16315. 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.
(c) You must submit all electronic reports required under paragraph
(a) of this section using the Emissions Collection and Monitoring Plan
System (ECMPS) Client Tool provided by the Clean Air Markets Division
in the Office of Atmospheric Programs of EPA.
(d) For affected EGUs under this subpart that are not in the Acid
Rain Program, you must also meet the reporting requirements and submit
reports as required under subpart G of part 75 of this chapter, to the
extent that those requirements and reports provide applicable data for
the compliance demonstrations required under this subpart.
(e) If your affected EGU captures CO2 to meet the
applicable emission standard, then you must report in accordance with
the requirements of 40 CFR part 98, subpart PP, of this chapter and
either:
(1) Report in accordance with the requirements of 40 CFR part 98,
subpart RR, of this chapter, if injection occurs on-site; or
(2) Transfer the captured CO2 to an EGU or facility that
reports in accordance with the requirements of 40 CFR part 98, subpart
RR, of this chapter, if injection occurs off site.
(f) You must prepare and submit notifications specified in Sec.
75.61 of this chapter, as applicable to your affected EGUs.
Sec. 62.16365 What are my recordkeeping requirements?
(a) The owner or operator of each affected EGU must maintain the
records, as described in paragraphs (a)(1) and (2) of this section, for
at least 5 years following the date of each compliance period,
occurrence, measurement, maintenance, corrective action, report, or
record.
(1) The owner or operator of an affected EGU must maintain each
record on site for at least 2 years after the date of each compliance
period, compliance true-up period, occurrence, measurement,
maintenance, corrective action, report, or record, whichever is latest,
according to Sec. 60.7 of this chapter. The owner or operator of an
affected EGU may maintain the records off site and electronically for
the remaining year(s).
(2) The owner or operator of an affected EGU must keep all of the
following records:
(i) All emissions monitoring information, in accordance with this
subpart;
(ii) Copies of all reports, compliance certifications, documents,
data files, calculations and methods, other submissions and all records
made or required under, or to demonstrate compliance with an affected
EGU's emission standard under Sec. 62.16220 and any other requirements
of, the CO2 Mass-based Trading Program;
(iii) Data that is required to be recorded by 40 CFR part 75,
subpart F, of this chapter; and
(iv) Data with respect to any allowances used by the affected EGU
in its compliance demonstration including the information in paragraphs
(a)(2)(iv)(A) and (B) of this section.
(A) All documents related to any set-aside allowances used in a
compliance demonstration, including each eligibility application, EM&V
plan, M&V report, and independent verifier verification report
associated with the issuance of each specific set-aside allowance, and
each regulatory approval and any documentation that supports the
issuance of each set-aside allowance by the Administrator.
(B) All records and reports relating to the surrender and
retirement of allowances for compliance with this regulation, including
the date each individual allowance with a unique serial identification
number was surrendered and/or retired.
(b) [Reserved]
Sec. 62.16370 What actions may the Administrator take on submissions?
(a) The Administrator may review and conduct independent audits
concerning
[[Page 65085]]
any submission under the CO2 Mass-based Trading Program and
make appropriate adjustments of the information in the submission.
(b) The Administrator may deduct CO2 allowances from or
transfer CO2 allowances to a compliance account, based on
the information in a submission, as adjusted under paragraph (a) of
this section, and record such deductions and transfers.
Definitions
Sec. 62.16375 What definitions apply to this subpart?
The terms used in this subpart 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 his or her delegate, or the
authorized state official under an approved state plan that
incorporates this subpart.
Affected electric generating unit or Affected EGU means any steam
generating unit, IGCC, or stationary combustion turbine that meets the
applicability requirements in Sec. Sec. 60.5840(b) and 60.5845 of this
chapter. An affected EGU is not an eligible resource.
Allocate or allocation means, with regard to CO2
allowances, the determination by the Administrator, State, or
permitting authority, in accordance with this subpart or any state
allowance-distribution methodology submitted by the State and approved
by the Administrator under Sec. 62.16245, to:
(1) An affected EGU;
(2) A renewable energy set-aside;
(3) An output-based set-aside; or
(4) Any other entity specified by the Administrator.
Allowable CO2 emission rate means, for an affected EGU,
the most stringent state or federal CO2 emission rate limit
(in lb/MWh or, if in lb/mmBtu, converted to lb/MWh by multiplying it by
the affected EGU's heat rate in mmBtu/MWh) that is applicable to the
affected EGU and covers the longest averaging period not exceeding 1
year.
Allowance system means a control program under which the owner or
operator of each affected EGU is required to hold an authorization for
each specified unit of carbon dioxide emitted from that facility during
a specified period and which limits the total amount of such
authorizations available to be held for carbon dioxide for a specified
period and allows the transfer of such authorizations not used to meet
the authorization-holding requirement.
Allowance Tracking and Compliance System (ATCS) means the system by
which the Administrator records allocations, deductions, and transfers
of CO2 allowances under the CO2 Mass-based
Trading Program. Such allowances are allocated, recorded, held,
deducted, or transferred only as whole allowances.
Allowance transfer deadline means, for a compliance period in a
given year, midnight of May 1 (if it is a business day), or midnight of
the first business day thereafter (if May 1 is not a business day),
immediately after such compliance period and is the deadline by which a
CO2 allowance transfer must be submitted for recordation in
a facility's compliance account in order to be available for use in
complying with the facility's CO2 emission standard for such
compliance period in accordance with Sec. Sec. 62.16220 and 62.16340.
Alternate designated representative means, for a CO2
Mass-based Trading Program facility and each affected EGU at the
facility, the natural person who is authorized by the owners and
operators of the facility and all such affected EGUs at the facility,
in accordance with this subpart, to act on behalf of the designated
representative in matters pertaining to the CO2 Mass-based
Trading Program. If the facility is also subject to the Acid Rain
Program, TR NOX Annual Trading Program, TR NOX
Ozone Season Trading Program, TR SO2 Group 1 Trading
Program, or TR SO2 Group 2 Trading Program, then this
natural person shall be the same natural person as the alternate
designated representative, as defined in the respective program.
Annual capacity factor means the ratio between the actual heat
input to an affected EGU during a calendar year and the potential heat
input to the affected EGU had it been operated for 8,760 hours during a
calendar year at the base load rating. Also see capacity factor.
Authorized account representative means, for a general account, the
natural person who is authorized, in accordance with this subpart, to
transfer and otherwise dispose of CO2 allowances held in the
general account and, for a CO2 Mass-based Trading facility's
compliance account, the designated representative of the facility is
the authorized account representative.
Automated data acquisition and handling system (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.
Base load rating means the maximum amount of heat input (fuel) that
an EGU can combust on a steady state basis, as determined by the
physical design and characteristics of the EGU at ISO conditions. For a
stationary combustion turbine, base load rating includes the heat input
from duct burners.
Baseline means the electricity use that would have occurred without
implementation of a specific EE measure.
Biomass means biologically based material that is living or dead
(e.g., trees, crops, grasses, tree litter, roots) above and below
ground, and available on a renewable or recurring basis. Materials that
are biologically based include non-fossilized, biodegradable organic
material originating from modern or contemporarily grown plants,
animals, or microorganisms (including plants, products, byproducts and
residues from agriculture, forestry, and related activities and
industries, as well as the non-fossilized and biodegradable organic
fractions of industrial and municipal wastes, including gases and
liquids recovered from the decomposition of non-fossilized and
biodegradable organic material).
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.
Business day means a day that does not fall on a weekend or a
federal holiday.
Capacity factor means, as used for the output based set-aside, the
ratio of the net electrical energy produced by a generating unit for
the period of time considered to the electrical energy that could have
been produced at continuous net summer capacity during the same period.
Certifying official means a natural person who is:
(1) For a corporation, a president, secretary, treasurer, or vice-
president of the corporation in charge of a principal business function
or any other person who performs similar policy- or decision-making
functions for the corporation;
[[Page 65086]]
(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.
CO2 allowance means a limited authorization issued and
allocated by the Administrator under this subpart, or by a State or
permitting authority under a state allowance-distribution methodology
approved by the Administrator under Sec. 60.24(x) of this chapter, to
emit one ton of CO2 during a compliance period of the
specified calendar year for which the authorization is allocated or of
any calendar year thereafter under the CO2 Mass-Based
Trading Program.
CO2 allowance deduction or deduct CO2
allowances means the permanent withdrawal of CO2 allowances
by the Administrator from a compliance account (e.g., in order to
account for compliance with the CO2 emission standard).
CO2 allowances held or hold CO2 allowances
means the CO2 allowances treated as included in an Allowance
Tracking and Compliance System (ATCS) 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, CO2 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, CO2 allowance transfer in
accordance with this subpart.
CO2 emission goal means a statewide rate-based
CO2 emission goal or mass-based CO2 emission goal
specified in Sec. 62.16235.
CO2 emissions limitation means the tonnage of
CO2 emissions authorized in a compliance period in a given
year by the CO2 allowances available for deduction for the
facility under Sec. 62.16340(a) for such compliance period.
CO2 Mass-Based Trading Program means a multi-state
CO2 air pollution control and emission reduction program
established in accordance with this subpart and subpart UUUU of part 60
of this chapter (including such a program that is revised in a State
plan or state allowance distribution methodology, or by the
Administrator under subpart UUUU of part 60 of this chapter), as a
means of controlling CO2 emissions.
Coal means the definition as defined in subpart TTTT of part 60 of
this chapter.
Combined cycle unit means an electric generating unit that uses a
stationary combustion turbine from which the heat from the turbine
exhaust gases is recovered by a heat recovery steam generating unit to
generate additional electricity.
Combined heat and power unit or CHP unit, (also known as
``cogeneration'') means an electric generating unit that uses a steam-
generating unit or stationary combustion turbine to simultaneously
produce both electric (or mechanical) and useful thermal output from
the same primary energy facility.
Common practice baseline (CPB) means a baseline derived based on a
default technology or condition that would have been in place at the
time of implementation of an EE measure in the absence of the EE
measure (for example, the standard or market-average or pre-existing
equipment that a typical consumer/building owner would have continued
to use or would have installed at the time of project implementation in
a given circumstance, such as a given building type, EE program type or
delivery mechanism, and geographic region).
Common stack means a single flue through which emissions from two
or more units are exhausted.
Compliance account means an ATCS account, established by the
Administrator for a CO2 annual facility under this subpart,
in which any CO2 allowance allocations to the affected EGUs
at the facility are recorded and in which are held any CO2
allowances available for use for a compliance period in a given year in
complying with the facility's CO2 emission standard in
accordance with Sec. Sec. 62.16220 and 62.16340.
Compliance period means the multi-year periods starting January 1
of the first calendar year of the period, except as provided in Sec.
62.16220(c)(3), and ending on December 31 of the last calendar year,
inclusive:
(1) Compliance Period 1 means the period of 3 calendar years from
January 1, 2022 to December 31, 2024.
(2) Compliance Period 2 means the period of 3 calendar years from
January 1, 2025 to December 31, 2027.
(3) Compliance Period 3 means the period of 2 calendar years from
January 1, 2028 to December 31, 2029.
Conservation voltage regulation (or reduction) (CVR) means an EE
measure that produces electricity savings by reducing (or regulating)
voltage at the electrical feeder level.
Continuous emission monitoring system (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 CO2 emissions, stack gas volumetric flow rate,
stack gas moisture content, and O2 concentration (as
applicable), in a manner consistent with part 75 of this chapter and
Sec. 62.16345. 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;
(2) 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;
(3) 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
(4) 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 area operator means an electric system or systems, bounded
by interconnection metering and telemetry, capable of controlling
generation to maintain its interchange schedule with other control
areas and contributing to frequency regulation of the interconnection.
Deemed savings means estimates of average annual electricity
savings for a single unit of an installed demand-side EE measure that:
Has been developed from data sources (such as prior metering studies)
and analytical methods widely considered acceptable for the measure;
and is applicable to the situation and conditions in which the measure
is implemented. Individual parameters or calculation methods also can
be deemed, including EUL values. Common sources of deemed savings
values are previous evaluations and studies that involved actual
measurements and analyses. Deemed savings values are applicable for
specific demand-side EE measures. A
[[Page 65087]]
single deemed savings value may not be used for a program as a whole,
nor for a multi-measure project, because of the degree of variation in
how systems are used in different building types or market segments.
Demand-side energy efficiency or demand-side EE means energy
efficiency activities, projects, programs or measures resulting in
electricity savings.
Derate means a decrease in the available capacity of an electric
generating unit, due to a system or equipment modification or to
discounting a portion of a generating unit's capacity for planning
purposes.
Designated representative means, for a CO2 Mass-based
Trading facility and each affected EGU at the facility, the natural
person who is authorized by the owners and operators of the facility
and all such affected EGUs at the facility, in accordance with this
subpart, to represent and legally bind each owner and operator in
matters pertaining to the CO2 Mass-based Trading Program. If
the CO2 Mass-based Trading facility is also subject to the
Acid Rain Program, TR NOX Annual Trading Program, TR
NOX Ozone Season Trading Program, TR SO2 Group 1
Trading Program, or TR SO2 Group 2 Trading Program, then
this natural person shall be the same natural person as the designated
representative, as defined in the respective program.
Design efficiency means the rated overall net efficiency (e.g.,
electric plus thermal output) on a higher heating value basis of the
EGU at the base load rating and ISO conditions.
Distillate oil means the definition as defined in subpart TTTT of
part 60 of this chapter.
Effective useful life (EUL) means the duration over which
electricity savings from an EE measure occur, reported in years. EUL
values are typically specific to individual EE projects but also may be
specified by EE program.
Energy efficiency measure or EE measure means a single technology,
energy-use practice or behavior that, once implemented or adopted,
reduces electricity use of a particular end-use, facility, or premises;
EE measures may be implemented as part of an EE program or as an
independent privately-funded action.
Energy efficiency program or EE program means organized activities
sponsored and funded by a particular entity to promote the adoption of
one or more EE project or EE measure for the purpose of reducing
electricity use.
Energy efficiency project or EE project means a combination of
multiple technologies, energy-use practices or behaviors implemented at
a single facility or premises for the purpose of reducing electricity
use; EE projects may be implemented as part of an EE program or as an
independent privately-funded action.
Electricity savings means the savings that results from a change in
electricity use resulting from the implementation of an EE measure.
Eligible resource means a resource that meets the requirements of
Sec. 62.16245 and has been registered with the EPA-administered ATCS
or an allowance tracking system approved in a State plan by the EPA. An
eligible resource is not an affected EGU.
EM&V plan means an evaluation measurement and verification plan
that meets the requirements of Sec. 62.16260.
Emissions means air pollutants exhausted from an affected EGU or
facility into the atmosphere; emissions must be measured, recorded, and
reported to the Administrator by the designated representative, and as
modified by the Administrator:
(1) In accordance with this subpart; and
(2) With regard to a period before the affected EGU or facility is
required to measure, record, and report such air pollutants in
accordance with this subpart, and in accordance with part 75 of this
chapter.
Emission rate credit (ERC) means a tradable compliance instrument
that meets the requirements of Sec. 60.5790(c) of this chapter.
Energy service company means a private enterprise engaged in
delivering electricity savings directly for an end-use customer or as
an agent of a sponsoring entity such as a utility.
Essential generating characteristics means any characteristic that
affects the eligibility of the qualifying energy generating facility
for generating allowances pursuant to this regulation, including the
type of facility.
Excess emissions means any ton of emissions from the affected EGUs
at a facility during a compliance period that exceeds the
CO2 emissions limitation for the facility for such
compliance period.
Existing state program, requirement, or measure means, in the
context of a State plan, a regulation, requirement, program, or measure
administered by a state, utility, or other entity that is currently
established. This may include a regulation or other legal requirement
that includes past, current, and future obligations, or current
programs and measures that are in place and are anticipated to be
continued or expanded in the future, in accordance with established
plans. An existing state program, requirement, or measure may have
past, current, and future impacts on EGU CO2 emissions.
Facility 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.
Final compliance period means a compliance period within the final
period, each being 2 calendar years (with a calendar year beginning on
January 1 and ending on December 31), and the first final compliance
period beginning on January 1, 2030 and ending December 31, 2031.
Final period means the period that begins on January 1, 2030 and
continues thereafter. The final period is comprised of final compliance
periods, each of which is 2 calendar years (with a calendar year
beginning on January 1 and ending on December 31).
Fossil fuel means the definition as defined in subpart TTTT of part
60 of this chapter.
Fossil-fuel-fired means, with regard to an affected EGU, combusting
any amount of fossil fuel.
Gaseous fuel means the definition as defined in subpart TTTT of
part 60 of this chapter.
General account means an ATCS account established under this
subpart that is not a compliance account.
Generation period means the compliance period from which the
Administrator uses operations data of affected EGUs to calculate
allowances from the output-based allocation set-aside for the following
compliance period.
Generation year means a calendar year for which a renewable energy
project submits its projected generation to the Administrator by June 1
of the preceding year for allowances from the renewable energy set-
aside.
Generator means a device that produces electricity.
Gross electrical output means, for an affected EGU, 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
affected EGU and any on-site emission controls).
Heat input means, for an affected EGU for a specified period of
time, the product (in mmBtu/time) of the gross calorific value of the
fuel (in mmBtu/lb) fed into the affected EGU multiplied by
[[Page 65088]]
the fuel feed rate (in lb of fuel/time), as measured, recorded, and
reported to the Administrator by the designated representative and as
modified by the Administrator in accordance with this subpart and
excluding the heat derived from preheated combustion air, recirculated
flue gases, or exhaust.
Heat input rate means, for an affected EGU, the amount of heat
input (in mmBtu) divided by affected EGU operating time (in hr) or, for
an affected EGU and a specific fuel, the amount of heat input
attributed to the fuel (in mmBtu) divided by the affected EGU operating
time (in hr) during which the affected EGU combusts the fuel.
Heat rate means, for an affected EGU, the affected EGU's maximum
design heat input (in Btu/hr), divided by the product of 1,000,000 Btu/
mmBtu and the affected EGU's maximum hourly load.
Heat recovery steam generating unit (HRSG) means a unit in which
hot exhaust gases from the combustion turbine engine are routed in
order to extract heat from the gases and generate useful output. Heat
recovery steam generating units can be used with or without duct
burners.
Indian country means ``Indian country'' as defined in 18 U.S.C.
1151.
Integrated gasification combined cycle facility or IGCC facility
means a combined cycle facility that is designed to burn fuels
containing 50 percent (by heat input) or more solid-derived fuel not
meeting the definition of natural gas plus any integrated equipment
that provides electricity or useful thermal output to either the
affected facility or auxiliary equipment. The Administrator may waive
the 50 percent solid-derived fuel requirement during periods of the
gasification system construction, startup and commissioning, shutdown,
or repair. No solid fuel is directly burned in the unit during
operation.
Interim period means the period of 8 calendar years from January 1,
2022 to December 31, 2029. The interim period is comprised of three
compliance periods, compliance period 1, compliance period 2, and
compliance period 3.
ISO conditions means 288 Kelvin (15[deg] C), 60 percent relative
humidity and 101.3 kilopascals pressure.
Liquid fuel means the definition as defined in subpart TTTT of part
60 of this chapter.
M&V report means a monitoring and verification report that meets
the requirements of Sec. 62.16265.
Maximum design heat input means, for an affected EGU, the maximum
amount of fuel per hour (in Btu/hr) that the affected EGU is capable of
combusting on a steady state basis as of the initial installation of
the affected EGU as specified by the manufacturer of the affected EGU.
Mechanical output means the useful mechanical energy that is not
used to operate the affected facility, generate electricity and/or
thermal output, or to enhance the performance of the affected facility.
Mechanical energy measured in horsepower hour should be converted into
MWh by multiplying it by 745.7 then dividing by 1,000,000.
Monitoring system means any monitoring system that meets the
requirements of this subpart, including a continuous emission
monitoring system, an alternative monitoring system, or an excepted
monitoring system under part 75 of this chapter.
Nameplate capacity means, starting from the initial installation of
a generator, the maximum electrical generating output (in MWe, rounded
to the nearest tenth) that the generator is capable of producing on a
steady state basis and during continuous operation (when not restricted
by seasonal or other deratings) of such installation as specified by
the manufacturer of the generator or, starting from the completion of
any subsequent physical change in the generator resulting in an
increase in the maximum electrical generating output that the generator
is capable of producing on a steady state basis and during continuous
operation (when not restricted by seasonal or other deratings), such
increased maximum amount (in MWe, rounded to the nearest tenth) of such
completion as specified by the person conducting the physical change.
Natural gas means the definition as defined in subpart TTTT of part
60 of this chapter.
Net-electric output means the amount of gross generation the
generator(s) produce (including, but not limited to, output from steam
turbine(s), combustion turbine(s), and gas expander(s)), as measured at
the generator terminals, less the electricity used to operate the plant
(i.e., auxiliary loads); such uses include fuel handling equipment,
pumps, fans, pollution control equipment, other electricity needs, and
transformer losses as measured at the transmission side of the step up
transformer (e.g., the point of sale).
Net energy output means:
(1) The net electric or mechanical output from the affected
facility, plus 100 percent of the useful thermal output measured
relative to SATP conditions that is not used to generate additional
electric or mechanical output or to enhance the performance of the
affected EGU (e.g., steam delivered to an industrial process for a
heating application); and
(2) For combined heat and power facilities where at least 20.0
percent of the total gross or net energy output consists of electric or
direct mechanical output and at least 20.0 percent of the total gross
or net energy output consists of useful thermal output on a 12-
operating month rolling average basis, the net electric or mechanical
output from the affected EGU divided by 0.95, plus 100 percent of the
useful thermal output (e.g., steam delivered to an industrial process
for a heating application).
Net summer capacity means the maximum output, commonly expressed in
megawatts (MW), that generating equipment can supply to system load, as
demonstrated by a multi-hour test, at the time of summer peak demand
(period of June 1 through September 30.) This output reflects a
reduction in capacity due to electricity use for station service or
auxiliaries.
Operate or operation means, with regard to an affected EGU, to
combust fuel.
Operator means, for a CO2 Mass-based Trading facility or
an affected EGU at a facility respectively, any person who operates,
controls, or supervises an affected EGU at the facility or the affected
EGU and includes, but is not limited to, any holding company, utility
system, or plant manager of such facility or affected EGU.
Owner means, for a CO2 Mass-based Trading facility or an
affected EGU at a facility respectively, any of the following persons:
(1) Any holder of any portion of the legal or equitable title in an
affected EGU at the facility or the affected EGU;
(2) Any holder of a leasehold interest in an affected EGU at the
facility or the affected EGU, provided that, unless expressly provided
for in a leasehold agreement, ``owner'' does 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 affected EGU; and
(3) Any purchaser of power from an affected EGU at the facility or
the affected EGU under a life-of-the-unit, firm power contractual
arrangement.
Permanently retired means, with regard to an affected EGU, that an
affected EGU is unavailable for service and the affected EGU's owners
and operators: have taken on as enforceable obligations in the
operating permit that covers the affected EGU the conditions of Sec.
62.16215; or rescinded or otherwise
[[Page 65089]]
terminated all permits required for construction or operation of the
affected EGU under the Clean Air Act. Cessations in operations that do
not meet this definition do not constitute permanent retirements.
Qualified biomass means a biomass feedstock that is demonstrated as
a method to control increases of CO2 levels in the
atmosphere.
Random error means errors occurring by chance that may cause
electricity savings values to be inconsistently overestimated or
underestimated, and may result from a change in electricity use due to
unaccounted-for factors that affect electricity use. The magnitude of
random error can be quantified based on the variations observed across
different units.
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
CO2 allowances, the moving of CO2 allowances by
the Administrator into, out of, or between ATCS 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 an affected
EGU, the demolishing of an affected EGU, or the permanent retirement
and permanent disabling of an affected EGU, and the construction of
another affected EGU (the replacement affected EGU) to be used instead
of the demolished or retired affected EGU (the replaced affected EGU).
Solid fuel means any fuel that has a definite shape and volume, has
no tendency to flow or disperse under moderate stress, and is not
liquid or gaseous at ISO conditions. This includes, but is not limited
to, coal, biomass, and pulverized solid fuels.
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.
Standard ambient temperature and pressure (SATP) conditions means
298.15 Kelvin (25[deg] C, 77 [deg]F)) and 100.0 kilopascals (14.504
psi, 0.987 atm) pressure. The enthalpy of water at SATP conditions is
50 Btu/lb.
State agent means an entity acting on behalf of the State, with the
legal authority of the State.
State measures means measures that the State adopts and implements
as a matter of state law. Such measures are enforceable only per state
law, and are not included in and codified as part of the federally
enforceable State plan.
Stationary combustion turbine means all equipment, including but
not limited to the turbine engine, the fuel, air, lubrication and
exhaust gas systems, control systems (except emissions control
equipment), heat recovery system, fuel compressor, heater, and/or pump,
post-combustion emissions control technology, and any ancillary
components and sub-components comprising any simple cycle stationary
combustion turbine, any combined cycle combustion turbine, and any
combined heat and power combustion turbine based system plus any
integrated equipment that provides electricity or useful thermal output
to the combustion turbine engine, heat recovery system or auxiliary
equipment. Stationary means that the combustion turbine is not self-
propelled or intended to be propelled while performing its function. It
may, however, be mounted on a vehicle for portability. If a stationary
combustion turbine burns any solid fuel directly then it is considered
a steam generating unit.
Steam generating unit means any furnace, boiler, or other device
used for combusting fuel and producing steam (nuclear steam generators
are not included) plus any integrated equipment that provides
electricity or useful thermal output to the affected facility or
auxiliary equipment.
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.
Systematic error means inaccuracies in the same direction, causing
electricity savings values to be consistently either overestimated or
underestimated, and may result from factors such as incorrect
assumptions, a methodological issue, or a flawed reporting system.
Transmission and distribution loss means the difference between the
quantity of electricity that serves a load (measured at the busbar of
the generator) and the actual electricity use at the final distribution
location (measured at the on-site meter).
Transmission and distribution measures or T&D measures means EE
measures intended to improve the efficiency of the electrical
transmission and distribution system by decreasing electricity loses on
the system.
Unit operating day means, with regard to an affected EGU, a
calendar day in which the affected EGU combusts any fuel.
Unit operating hour or hour of unit operation means, with regard to
an affected EGU, an hour in which the affected EGU combusts any fuel.
Uprate means an increase in available electric generating unit
power capacity due to a system or equipment modification.
Useful thermal output means the thermal energy made available for
use in any heating application (e.g., steam delivered to an industrial
process for a heating application, including thermal cooling
applications) that is not used for electric generation, mechanical
output at the affected EGU, to directly enhance the performance of the
affected EGU (e.g., economizer output is not useful thermal output, but
thermal energy used to reduce fuel moisture is considered useful
thermal output), or to supply energy to a pollution control device at
the affected EGU. Useful thermal output for affected EGU(s) with no
condensate return (or other thermal energy input to the affected
EGU(s)) or where measuring the energy in the condensate (or other
thermal energy input to the affected EGU(s)) would not meaningfully
impact the emission rate calculation is measured against the energy in
the thermal output at SATP conditions. Affected EGU(s) with meaningful
energy in the condensate return (or other thermal energy input to the
affected EGU) must measure the energy in the condensate and subtract
that energy relative to SATP conditions from the measured thermal
output.
Utility power distribution system means the portion of an
electricity grid owned or operated by a utility and dedicated to
delivering electricity to customers.
Valid data means quality-assured data generated by continuous
monitoring systems that are installed, operated, and maintained
according to part 75 of this chapter. For CEMS, the initial
certification requirements in Sec. 75.20 of this chapter and appendix
A to part 75 of this chapter must be met before quality-assured data
are reported under this subpart; for on-going quality
[[Page 65090]]
assurance, the daily, quarterly, and semiannual/annual test
requirements in sections 2.1, 2.2, and 2.3 of appendix B to part 75 of
this chapter must be met and the data validation criteria in sections
2.1.5, 2.2.3, and 2.3.2 of appendix B to part 75 of this chapter apply.
For fuel flow meters, the initial certification requirements in section
2.1.5 of appendix D to part 75 of this chapter must be met before
quality-assured data are reported under this subpart (except for
qualifying commercial billing meters under section 2.1.4.2 of appendix
D), and for on-going quality assurance, the provisions in section 2.1.6
of appendix D to part 75 of this chapter apply (except for qualifying
commercial billing meters).
Verification report means a report that meets the requirements of
Sec. 62.16270.
Waste-to-Energy means a process or unit (e.g., solid waste
incineration unit) that recovers energy from the conversion or
combustion of waste stream materials, such as municipal solid waste, to
generate electricity and/or heat.
Sec. 62.16380 What measurements, abbreviations, and acronyms apply to
this subpart?
The measurements, abbreviations, and acronyms used in this subpart
are defined as follows:
ADR--alternated designated representative
Btu--British thermal unit
CO2--carbon dioxide
COI--conflict of interest
CPP--clean power plan
CVR--conservation voltage regulation
DR--designated representative
EE--energy efficiency
EGU--electric generating unit
EM&V--evaluation, measurement, and verification
GCV--gross calorific value
GJ--giga joule
H2O--water
hr--hour
IGCC--integrated gasification combined cycle
kg--kilogram
kW--kilowatt electrical
kWh--kilowatt hour
lb--pound
M&V--measurement and verification
mmBtu--million Btu
MWe--megawatt electrical
MWh--megawatt hour
O2--oxygen
PB-MV--project-based measurement and verification
PSD--prevention of significant deterioration
T&D--transmission and distribution
TRM--technical reference manual
yr--year
0
5. Add subpart NNN to read as follows:
Subpart NNN--Greenhouse Gas Emissions Rate-based Model Trading Rule
for Electric Utility Generating Units That Commenced Construction
on or Before January 8, 2014
Sec.
Introduction
62.16405 What is the purpose of this subpart?
Applicability of This Subpart
62.16410 Am I subject to this subpart?
62.16415 What are the requirements for retired affected EGUs?
General Requirements
62.16420 What emission standards and requirements must I comply
with?
62.16425 How should I compute time under the CO2 Rate-
based Trading Program?
62.16430 What are the administrative appeal procedures?
62.16431 How will the Clean Energy Incentive Program be administered
under the federal plan?
Emission Rate Credit Issuance, Adjustment, and Revocation
62.16434 What affected EGUs qualify for generation of ERCs?
62.16435 What eligible resources qualify for generation of ERCs in
addition to affected EGUs?
62.16440 What is the process for revocation of qualification status
of an eligible resource?
62.16445 What is the process for the issuance of ERCs?
62.16450 What is the process for error adjustments or misstatement,
and suspension of ERC issuance?
Evaluation Measurement and Verification Plans, Monitoring and
Verification Reports, and Verification
62.16455 What are the requirements for evaluation measurement and
verification plans for eligible resources?
62.16460 What are the requirements for monitoring and verification
reports for eligible resources?
62.16465 What are the requirements for verification reports?
62.16470 What is the accreditation procedure for independent
verifiers?
62.16475 What are the procedures of accredited independent verifiers
must follow to avoid conflict of interest?
62.16480 What is the process for the revocation of accreditation
status for an independent verifier?
Designated Representatives
62.16485 How are designated representatives and alternate designated
representatives authorized and what role do authorized designated
representatives and alternate designated representatives play?
62.16490 What responsibilities do designated representatives and
alternate designated representatives hold?
62.16495 What are the processes for changing designated
representatives, alternate designated representatives, owners and
operators, and affected EGUs?
62.16500 What must be included in a certificate of representation?
62.16505 What is the Administrator's role in objections concerning
designated representatives and alternate designated representatives?
62.16510 What process must designated representatives and alternate
designated representatives follow to delegate their authority?
Monitoring, Recordkeeping, Reporting
62.16515 How are compliance accounts and general accounts
established and used, and how is ERC issuance documentation
accessed?
62.16525 How must transfers of ERCs be submitted?
62.16530 When will ERC transfers be recorded?
62.16535 How will deductions for compliance with a CO2
emission standard occur?
62.16540 What monitoring requirements must I comply with?
62.16545 May I bank CO2 ERCs for future use or transfer?
62.16550 How does the Administrator process account errors?
62.16555 What are my reporting, notification and submission
requirements?
62.16560 What are my recordkeeping requirements?
62.16565 What actions may the Administrator take on submissions?
Definitions
62.16570 What definitions apply to this subpart?
62.16575 What measurements, abbreviations, and acronyms apply to
this subpart?
Table 1 to Subpart NNN of Part 62--CO2 Emission Standards
(Pounds of CO2 Per Net MWh)
Table 2 to Subpart NNN of Part 62--Incremental Generation Factor for
Emission Rate Credits
Subpart NNN--Greenhouse Gas Emissions Rate-Based Model Trading Rule
for Electric Utility Generating Units That Commenced Construction
on or Before January 8, 2014
Introduction
Sec. 62.16405 What is the purpose of this subpart?
(a) This subpart sets forth the requirements for the Clean Power
Plan (CPP) CO2 Rate-based Trading Program, under section 111
of the Clean Air Act and subpart UUUU of part 60 of this chapter, as a
means of meeting emission guidelines limiting greenhouse gas emissions
from an affected steam generating unit, integrated gasification
combined cycle (IGCC), or stationary combustion turbine.
[[Page 65091]]
(b) The pollutants regulated by this subpart are greenhouse gases.
The greenhouse gas limitations in this subpart are in the form of an
emission standard for carbon dioxide (CO2).
(c) PSD and Title V thresholds for greenhouse gases. (1) For the
purposes of Sec. 51.166(b)(49)(ii) of this chapter, with respect to
GHG emissions from affected facilities, the ``pollutant that is subject
to the standard promulgated under section 111 of the Act'' shall be
considered to be the pollutant that otherwise is subject to regulation
under the Act as defined in Sec. 51.166(b)(48) of this chapter and in
any state implementation plan approved by the EPA that is interpreted
to incorporate, or specifically incorporates, Sec. 51.166(b)(48) of
this chapter.
(2) For the purposes of Sec. 52.21(b)(50)(ii) of this chapter,
with respect to GHG emissions from affected facilities, the ``pollutant
that is subject to the standard promulgated under section 111 of the
Act'' shall be considered to be the pollutant that otherwise is subject
to regulation under the Act as defined in Sec. 52.21(b)(49) of this
chapter.
(3) For the purposes of Sec. 70.2 of this chapter, with respect to
greenhouse gas emissions from affected facilities, the ``pollutant that
is subject to any standard promulgated under section 111 of the Act''
shall be considered to be the pollutant that otherwise is ``subject to
regulation'' as defined in Sec. 70.2 of this chapter.
(4) For the purposes of Sec. 71.2 of this chapter, with respect to
greenhouse gas emissions from affected facilities, the ``pollutant that
is subject to any standard promulgated under section 111 of the Act''
shall be considered to be the pollutant that otherwise is ``subject to
regulation'' as defined in Sec. 71.2 of this chapter.
Applicability of This Subpart
Sec. 62.16410 Am I subject to this subpart?
(a) You are subject to this subpart if you are the owner or
operator of an affected electric generating unit (EGU) located within a
State that has incorporated by reference this subpart as a State plan,
or portion of a State plan, that has been approved by the Administrator
and is effective under subpart UUUU of part 60 of this chapter, or if
this subpart is promulgated and effective as a federal plan in your
State under part 62 of this chapter.
(b) An affected EGU is any steam generating unit, IGCC, or
stationary combustion turbine that meets the applicability requirements
in Sec. Sec. 60.5840(b) and 60.5845 of this chapter.
Sec. 62.16415 What are the requirements for retired affected EGUs?
(a) Exemption. (1) Any affected EGU that is permanently retired as
defined in Sec. 62.16570 is exempt from Sec. Sec. 62.16420(c)(1)
[CO2 Emissions Requirements], 62.16535 [Compliance
Requirements], 62.16540 [Monitoring], 62.16555 [Reporting], and
62.16560 [Recordkeeping].
(2) The exemption under paragraph (a)(1) of this section will
become effective on the first day of the compliance period immediately
following the compliance period in which the retirement took effect.
Within 30 days of the affected EGU's permanent retirement, the
designated representative must submit a statement to the Administrator.
The statement must state, in a format prescribed by the Administrator,
that the affected EGU was permanently retired on a specified date and
will comply with the requirements of paragraph (b) of this section.
(b) Special provisions. (1) An affected EGU exempt under paragraph
(a) of this section must not emit any CO2, 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 an affected EGU exempt under paragraph (a)
of this section must retain, at the affected EGU, records demonstrating
that the affected EGU 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 affected EGU is permanently
retired.
(3) The owners and operators and, to the extent applicable, the
designated representative of an affected EGU exempt under paragraph (a)
of this section must comply with the requirements of the CO2
Rate-based Trading Program accruing during any compliance periods for
which the exemption is not in effect, even if such requirements must be
complied with after the exemption takes effect.
General Requirements
Sec. 62.16420 What emission standards and requirements must I comply
with?
(a) Designated representative requirements. The owners and
operators must have a designated representative, and may have an
alternate designated representative, in accordance with Sec. Sec.
62.16485 through 62.16495.
(b) Emissions monitoring, reporting, and recordkeeping
requirements. (1) The owners and operators, and the designated
representative, of affected EGU must comply with the monitoring,
reporting, and recordkeeping requirements of Sec. Sec. 62.16540,
62.16555, and 62.16560.
(2) The emissions data determined in accordance with Sec. 62.16540
must be used to determine compliance with the CO2 emission
standard under paragraph (c) of this section, provided that, for each
monitoring location from which emissions are reported, the emission
rate used in determining compliance must be the CO2 emission
rate at the monitoring location determined in accordance with paragraph
(c) of this section.
(c) CO2 emission standard requirements. (1) Each designated
representative for each affected EGU must demonstrate compliance with
its emission standard listed in Table 1 of this subpart, as applicable,
by calculating a CO2 emission rate by factoring stack
emissions and any emission rate credits (ERCs) into the following
equation:
[GRAPHIC] [TIFF OMITTED] TP23OC15.018
Where:
CO2 emission rate = An affected EGU's calculated
CO2 emission rate that will be used to determine
compliance with the applicable CO2 emission standard.
MCO2 = Measured CO2 mass in units of pounds
(lbs) summed over the compliance period for an affected EGU.
MWhop = Total net energy output over the compliance
period for an affected EGU in units of MWh.
MWhERC = ERC replacement generation for an affected EGU
in units of MWh (ERCs are denominated in whole integers as specified
in paragraph (c)(2) of this section).
[[Page 65092]]
(2) An ERC qualifies for the compliance demonstration specified in
paragraph (c)(1) of this section if it:
(i) Has a unique serial number;
(ii) Represents one whole MWh of actual energy generated or saved
with zero associated carbon dioxide emissions;
(iii) Was issued to an eligible resource that meets the
requirements of Sec. 62.16435 or to an affected EGU that meets the
requirements of Sec. 62.16434, by the Administrator through an ERC
tracking system or the ATCS; and
(iv) Was surrendered and retired only once for purposes of
compliance with this regulation by the Administrator through an ERC
tracking system or the ATCS.
(3) An ERC does not qualify for the compliance demonstration
specified in paragraph (c)(1) of this section if it does not meet the
requirements of paragraph (c)(2) of this section or if any State has
used that same ERC for purposes of demonstrating achievement of its
state measures.
(4) As of the ERC transfer deadline for a compliance period, the
owners and operators of each affected EGU must hold, in the affected
EGU's compliance account, sufficient ERCs to demonstrate compliance
with its applicable emission standard listed in Table 1 of this subpart
pursuant to the requirement of paragraph (c)(1) of this section.
(5) If an affected EGU exceeds its emission standard during a
compliance period, then:
(i) The owners and operators of the affected EGU must hold ERCs
required for deduction under Sec. 62.16535(e);
(ii) The owners and operators of the affected EGU are subject to
federal enforcement pursuant to sections 113(a)-(h), and section 304,
of the Clean Air Act, and the United States, States, and other persons
have the ability to enforce against violations (including if an
affected EGU does not meet its emission standard based on its
emissions, or use of ERCs that meet the compliance demonstration in
Sec. 62.16420 (c)(2)) and secure appropriate corrective actions, and
the owners and operators must pay any fine, penalty, or assessment or
comply with any other remedy imposed, for the same violations, under
the Clean Air Act, and each day of such compliance period will
constitute a separate violation of this subpart and the Clean Air Act;
(iii) If an affected EGU does not meet its emission standard
because it did not meet the emissions standard based on its stack
emissions and generation alone and it did not obtain sufficient
qualifying ERCs to meet its emission standard by July 1 of the year
following the relevant compliance period, then it may be subject to
federal enforcement pursuant to Sections 113(a)-(h), 42 U.S.C. 7413(a)-
(h), and Section 304 of the Clean Air Act, 42 U.S.C. 7604, and the
United States, states, and other persons have the ability to enforce
violations and secure corrective actions; and
(iv) If an affected EGU obtained sufficient facially valid ERCs to
meet its emission standard, but those ERCs were found to be invalid,
then it may be subject to federal enforcement as specified in paragraph
(c)(5)(iii) of this section.
(d) Compliance periods. An affected EGU will be subject to the
requirements under paragraph (c)(1) of this section for the compliance
period starting on January 1, 2022, and for each compliance period
thereafter.
(1) Vintage of ERCs held for compliance. An ERC held for compliance
with the requirements under paragraph (c)(1) of this section for a
compliance period must be an ERC that was issued for a year in such
compliance period or for a year in a prior compliance period.
(2) ATCS. Each ERC must be held in, deducted from, transferred
into, out of, or between ATCS accounts in accordance with this subpart.
(3) Limited authorization. (i) An ERC shall only be used in
accordance with the CO2 Rate-based Trading Program; and
(ii) Notwithstanding any other provision of this subpart, the
Administrator has the authority to terminate or limit the use and
duration of such authorization to the extent the Administrator
determines is necessary or appropriate to implement any provision of
the Clean Air Act.
(4) Property right. An ERC does not constitute a property right.
(e) Title V permit requirements. (1) Unless otherwise specified in
this paragraph, all requirements of this subpart shall be applicable
requirements that must be included in an affected EGU's title V permit.
(2) The applicable requirements of this subpart, as well as other
terms or conditions necessary to ensure compliance with the applicable
requirements, 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 such changes
do not conflict with any existing terms of the permit. This paragraph
explicitly provides that the addition of, or change to, an affected
EGU'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.
(3) No title V permit revision will be required for any crediting,
holding, deduction, or transfer of ERCs in accordance with this
subpart, provided that the requirements applicable to such creditings,
holdings, deductions, or transfers of ERCs are already incorporated in
such permit.
(f) Liability. Any provision of the CO2 Rate-based
Trading Program that applies to an affected EGU or the designated
representative of an affected EGU shall also apply to the owners and
operators of such affected EGU.
(g) Effect on other authorities. No provision of the CO2
Rate-based Trading Program or exemption under Sec. 62.16415 shall be
construed as exempting or excluding the owners and operators, and the
designated representative, of an affected EGU from compliance with any
other provision of the applicable, approved state implementation plan,
a federally enforceable permit, or any other requirement of the Clean
Air Act.
Sec. 62.16425 How should I compute time under the CO2
Rate-based Trading Program?
(a) Unless otherwise stated, any time period scheduled, under the
CO2 Rate-Based 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
CO2 Rate-Based Trading Program, to begin before the
occurrence of an act or event will 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 CO2 Rate-Based Trading Program, is not a business
day, then the time period will be extended to the next business day.
Sec. 62.16430 What are the administrative appeal procedures?
The administrative appeal procedures for decisions of the
Administrator under the CO2 Rate-based Trading Program are
set forth in part 78 of this chapter.
Sec. 62.16431 How will the Clean Energy Incentive Program be
administered under the federal plan?
(a)(1) The Administrator will participate in the Clean Energy
Incentive Program, established under subpart UUUU of part 60 of this
chapter, on behalf of any state for whom this subpart is promulgated as
a federal plan under section 111(d) of the Act. The Administrator will
award, on behalf of each such state, early action ERCs for generation
and savings achieved in 2020 and/or 2021 that result from the
[[Page 65093]]
following types of eligible renewable energy (RE) and demand-side
energy efficiency (EE) projects:
(i) Metered wind power;
(ii) Metered solar power; and
(iii) Demand-side EE implemented in a low-income community.
(2) Eligible RE projects must commence construction, and eligible
demand-side EE projects must commence implementation, after September
6, 2018 for those states on whose behalf the EPA is implementing the
federal plan. Eligible projects must be located in or benefit the state
on whose behalf the EPA is implementing the federal plan.
(b) Early action ERCs will be distributed pursuant to a process to
be prescribed by the Administrator, and in a manner to be demonstrated
by the Administrator to have no impact on the aggregate emission
performance of affected EGUs required to meet rate-based emission
standards during the compliance periods.
(c) The Administrator will match these early action ERCs with
additional matching ERCs pursuant to a process to be prescribed by the
Administrator. Matching awards will be made up to a limit equivalent to
the state's pro rata share of 300 million short tons of CO2
emissions.
(d) The awards, including the matching award, will be executed as
follows:
(1) For RE projects that generate metered MWh from wind or solar
resources: For every two MWh generated, the project will receive one
early action ERC under paragraph (b) of this section and one matching
ERC from the match under paragraph (c) of this section; and
(2) For EE projects that benefit low-income communities as
determined by the Administrator solely for purposes of this subpart:
For every two MWh in end-use demand savings achieved, the project will
receive two early action ERCs under paragraph (b) of this section and
two matching ERCs from the match under paragraph (c) of this section.
Emission Rate Credit Issuance, Adjustment, and Revocation
Sec. 62.16434 What affected EGUs qualify for generation of ERCs?
(a) ERCs may only be issued to affected EGUs under the conditions
listed in paragraphs (b) and (c) of this section.
(b) For affected EGUs that emit below their applicable emission
standard, the amount of ERCs generated must be calculated using the
following equation:
[GRAPHIC] [TIFF OMITTED] TP23OC15.019
Where:
ERCs = Number of emission rate credits generated by an affected EGU
during an applicable compliance period (MWh).
EGU emission standard = The emission standard the affected EGU must
comply with during the applicable compliance period according to
Sec. 62.16420 (lb/MWh).
EGU emission rate = The affected EGU's measured CO2
emission rate measured in accordance with Sec. 62.16540 (lb/MWh).
EGU generation = Total net energy output generation of the affected
EGU during the applicable compliance period measured in accordance
with Sec. 62.16540 (MWh).
(c) Stationary combustion turbines that meet the definition of an
affected EGU may generate net energy output MWh gas shift ERCs (GS-
ERCs) for all hours of operation during a given compliance period
according to paragraphs (c)(1) through (3) of this section.
(1) To calculate the number of GS-ERCs:
GS-ERCs = EGU Generation * Incremental Generation Factor * GS-ERC
Emission Factor
Where:
GS-ERC = Net energy output MWh gas shift ERCs.
EGU generation = Total net energy output generation of the affected
EGU during the applicable compliance period measured in accordance
with Sec. 62.16540 (MWh).
Incremental Generation Factor = See Table 2 of this subpart for the
applicable factor for each compliance period.
GS-ERC Emission Factor = Value calculated using equation (c)(2) of
this section.
(2) To calculate the GS-ERC Emission factor for your specific
affected EGU you must use the following equation:
[GRAPHIC] [TIFF OMITTED] TP23OC15.020
Where:
GS-ERC Emission Factor = Factor to be used in the equation in
paragraph (c)(1) of this section for GS-ERC calculation.
EGU emission rate = Affected EGU's measured CO2 emission
rate measured in accordance with Sec. 62.16540 (lb/MWh).
Steam turbine emission standard = Steam turbine emission standard
for the corresponding compliance period as found in Table 1 of this
subpart (lb/MWh).
(3) Notwithstanding any other provision of this subpart, GS-ERCs
must not be used for compliance by an affected EGU that is a stationary
combustion turbine. Stationary combustion turbines may use other ERCs
in their compliance demonstration.
Sec. 62.16435 What eligible resources qualify for generation of ERCs
in addition to affected EGUs?
(a) ERCs may only be issued to an eligible resource that meet each
of the requirements in paragraphs (a)(1) through (4) of this section.
All categories of resources other than on-shore utility scale wind,
utility scale solar photovoltaics, concentrated solar power, geothermal
power, nuclear energy, or utility scale hydropower, and all provisions
of this subpart relating to such resources, are not available or
applicable in States where this subpart has been promulgated as a
federal plan pursuant to section 111(d)(2) of the Act.
(1) Resources qualifying for eligibility only include resources
which increased new installed electrical generation nameplate capacity,
or new electrical savings measures installed or implemented after
January 1, 2013. If a resource had a nameplate capacity uprate, then
ERCs may be issued only for the difference in generation between the
uprated nameplate capacity and its nameplate capacity prior to the
uprate. ERCs must not be issued for generation for an uprate that
followed a derate that occurred on or after January 1, 2013. A resource
that is relicensed or receives a license extension is considered
existing
[[Page 65094]]
capacity and is not an eligible resource, unless it receives a capacity
uprate as a result of the relicensing process that is reflected in its
relicensed permit. In such a case, only the difference in nameplate
capacity between its relicensed permit and its prior permit is eligible
to be issued ERCs.
(2) The resource must be connected to, and delivers energy to or
saves electricity, on the electric grid in the contiguous United
States.
(3) The resource is located in a State whose affected EGUs are
subject to rate-based emission standards pursuant to this regulation,
unless the resource is located in a State with mass-based emission
standards and the resource can demonstrate (e.g., through a power
purchase agreement or contract for delivery) transmission of its
generation into a State whose affected EGUs are subject to rate-based
emission standards pursuant to this regulation.
(4) The resource falls into one of the following categories of
resources:
(i) Renewable electric generating technologies using one of the
following renewable energy resources: wind, solar, geothermal, hydro,
wave, tidal;
(ii) Qualified biomass;
(iii) Waste-to-energy (biogenic portion);
(iv) Nuclear energy;
(v) A non-affected combined heat and power unit, including waste
heat power; or
(vi) A demand-side EE or demand-side management measure that saves
electricity and is calculated on the basis of quantified ex poste
savings, not ``projected'' or ``claimed'' savings.
(b) Any resource that does not meet the requirements of this
subpart cannot generate ERCs for use in the compliance demonstration
required under Sec. 62.16420.
(c) ERCs may not be issued to any of the following:
(1) New, modified, or reconstructed EGUs that are subject to
subpart TTTT of part 60 of this chapter, except CHP units that meet the
requirements of a CHP unit under paragraph (a) of this section;
(2) EGUs that do not meet the applicability requirements of Sec.
62.16410, except CHP units that meet the requirements of a CHP unit
under paragraph (a) of this section;
(3) Measures that reduce CO2 emissions outside the
electric power sector, including GHG offset projects representing
emission reductions that occur in the forestry and agriculture sectors,
direct air capture, and crediting of CO2 emission reductions
that occur in the transportation sector as a result of vehicle
electrification; and
(4) Any measure not approved by the EPA to generate ERCs in
connection with a specific State plan.
Sec. 62.16440 What is the process for revocation of qualification
status of an eligible resource?
(a) If an eligible resource is found to not meet the requirements
of Sec. 62.16435 in the Rate-based Trading Program, then the
Administrator will revoke the eligibility of the eligible resource to
be issued ERCs. In addition, the provisions of Sec. 62.16450(d) may
apply.
(b) Any instance of intentional misrepresentation in an eligibility
application or monitoring and verification (M&V) report may be cause
for revocation of the qualification status of an eligible resource.
(c) Repeated instances of error or misstatement of MWh of
electricity generation or savings in submitted M&V reports, or in any
other submissions may be cause for the Administrator to revoke the
eligibility of an eligible resource to be issued ERCs.
(d) In the event of an intentional misrepresentation, or repeated
instances of error or misstatement, in program submissions, by the
authorized account representative of the eligible resource, the
Administrator may prohibit the eligible resource from any further
eligibility to be issued ERCs. In addition, the provisions of Sec.
62.16450 (a) through (d) may apply.
Sec. 62.16445 What is the process for the issuance of ERCs?
The process and requirements for issuance of ERCs for affected EGUs
and eligible resources are set forth in paragraphs (a) through (f) of
this section.
(a) Eligibility application. To receive ERCs, an authorized account
representative of an eligible resource must submit an eligibility
application to the Administrator that demonstrates that the
requirements of Sec. 62.16434 (for an affected EGU) or Sec. 62.16435
(for an eligible resource) are met, and, in the case of an eligible
resource only, demonstrates that the requirements in paragraphs (a)(1)
through (9) of this section are met.
(1) Identification of the authorized account representative of the
eligible resource, including the authorized account representative's
name, address, email address, telephone number, and ERC tracking system
account number.
(2) Identification of the eligible resource(s), including the
information in paragraphs (a)(2)(i) through (v) of this section.
(i) For an eligible resource, the physical location of the eligible
resource; contact information for the owner or operator of the eligible
resource, if different from the designated representative or authorized
account representative; eligible resource generator prime mover and/or
technology type; eligible resource nameplate capacity; eligible
resource category (e.g., wholesale generator, wholesale generator also
serving onsite customer load, customer-sited distributed generator) (if
applicable); facility and generating unit IDs (EIA ORIS Code, Facility
Registration System (FRS) Code, if applicable); for the eligible
resource, the control area, balancing authority, ISO conditions as
defined in Sec. 62.16570, or the regional transmission organization in
which the generator is located (if applicable).
(A) For an eligible resource with a nameplate capacity of1 MW or
more, a copy of the most recent filing of a copy of the generating
facility's U.S. Energy Information Agency's Annual Electric Generator
Report Form EIA-860.
(B) For an electric generating resource with a nameplate capacity
of less than 1 MW, the information that would be contained in U.S.
Energy Information Agency's Annual Electric Generator Report Form EIA-
860, if that electric generating facility had nameplate capacity of 1
MW or more.
(ii) For an energy-saving resource that is project-based, a
detailed description of the demand-side EE or electricity savings
project, including: Location and specifications of the building(s),
facility(ies), or installations where energy-saving measures were
implemented or will be implemented; owner and operator of the
building(s), facility(ies), or installations where the energy-saving
measures are implemented or will be implemented; the parties
implementing the energy-saving project, including lead contractor(s),
subcontractors, and consulting firms (if different from the authorized
account representative); energy-saving measures installed and/or
energy-savings practices implemented (or to be installed/implemented);
specifications of equipment and materials installed, or to be
installed, as part of the energy-saving project; project plans and
technical schematics, as applicable.
(iii) For an energy-savings resource that involves an EE
requirement or program, a description of the electricity savings
program, including: Overall approach or ``logic'' to the requirement or
program, including applicable strategies and activities, along with key
assumptions regarding how such strategies and activities will achieve
quantifiable reductions in electricity consumption; location and
geographic
[[Page 65095]]
distribution of the targeted building(s), facility(ies), or
installations where energy-saving requirements or programs were
implemented or will be implemented; electricity consuming system(s),
end-use(s), building or facility type(s), or installations where the
energy-saving requirements or programs are implemented or will be
implemented; the parties implementing the energy-saving requirement or
program, including lead contractor(s), subcontractor(s), and consulting
firms (if different from the authorized account representative);
specifications of energy-saving equipment and/or energy-savings
practices implemented (or to be installed/implemented) under the
requirement or program; the delivery mechanisms of the requirement or
program, which may include financial incentives or equipment rebates,
dissemination of actionable information to electricity customers, on-
site audits paired with technical recommendations.
(iv) For other electricity-saving resources (e.g., transmission and
distribution (T&D) measures such as conservation voltage reduction
(CVR)), a description of the resource, including: Overall approach or
``logic'' to the electricity-saving resource, including applicable
strategies and activities, along with key assumptions regarding how
such strategies and activities will achieve quantifiable reductions in
electricity consumption; location and geographic distribution of the
targeted building(s), facility(ies), or electricity transmitting and
distributing systems, as applicable, where electricity-saving resources
were implemented or will be implemented; electricity consuming,
transmitting, or distributing system(s), building or facility type(s),
or end-use(s) where the electricity-saving resource are implemented or
will be implemented; the parties implementing the electricity-saving
resource, including lead contractor(s), subcontractor(s), and
consulting firms (if different from the authorized account
representative); specifications of installed equipment and/or
implemented practices (or to be installed/implemented); the delivery
mechanisms used to implement and propagate the electricity-saving
resource, as applicable.
(v) For eligible resources with distributed locations, such as
measures at multiple residential, commercial, or industrial buildings,
at a minimum, aggregated information about the location of measures
that constitute an eligible resource, provided that the accredited
independent verifier and the Administrator have the ability to access
information specifying the location of each discrete measure that
constitutes an eligible resource.
(3) Demonstration that the eligible resource meets all applicable
eligibility requirements in Sec. 62.1435.
(4) A certification that the eligibility application has only been
submitted to the Administrator or pursuant to an EPA-approved multi-
state approach where States are providing for joint issuance of ERCs
pursuant to the authority in their individual State plans.
(5) An evaluation measurement and verification (EM&V) plan.
(6) A verification report from an accredited independent verifier
who meets the requirements of Sec. Sec. 62.16470 and 62.16475.
(7) An authorization that provides for the following: The
Administrator may inspect (including a physical inspection of the
eligible resource and its meter) and/or audit the eligible resource at
any time and verify that the eligible resource and the EM&V plan have
been implemented as described in the eligibility application.
(8) The following statement, signed by the designated
representative of the eligible resource:
(i) ``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
personal knowledge and/or 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.''
(ii) [Reserved]
(9) Any other information required by the Administrator.
(b) Registration of eligible resources. The Administrator must
review the eligibility application to determine whether the affected
EGU or eligible resource meets the requirements of Sec. paragraph (a)
of this section, and if it determines that the requirements are met,
approve the eligibility application and register the affected EGU or
eligible resource in an ERC tracking system that meets the requirements
of Sec. 62.16515. Once so registered, the affected EGU or eligible
resource is eligible to be issued ERCs, provided all other applicable
requirements continue to be met.
(c) M&V reports. For an eligible resource, the designated
representative must submit to the Administrator an M&V report prior to
issuance of ERCs by the Administrator.
(d) Verification reports. For an eligible resource, the authorized
account representative must submit a verification report from an
accredited independent verifier that meets the requirements of
Sec. Sec. 62.16470 and 62.16475 as part of each eligibility
application and M&V report. While considered a part of the eligibility
application and M&V report, the verification report must be submitted
separately by the accredited independent verifier to the Administrator.
(e) Issuance of ERCs. ERCs may only be issued by the Administrator
based on actual electricity generation or savings documented in an M&V
report that meets the requirements of Sec. 62.16460 and a verification
report that meets the requirements of Sec. 62.16465. Only one ERC will
be issued for each verified MWh.
(f) Tracking system. ERCs may only be issued through an ERC
tracking system that meets the requirements of Sec. 62.16515.
Sec. 62.16450 What is the process for error adjustments or
misstatement, and suspension of ERC issuance?
(a) In the event of error or misstatement of quantified MWh of
electricity generation or savings in a previous M&V report for which
ERCs have been issued, the Administrator may adjust the number of ERCs
issued in a subsequent reporting period to address the error or
misstatement, by subtracting a number of MWh from the quantified and
verified MWh in the M&V report for the subsequent reporting period. In
the event that an error or inadvertent misstatement occurs in a final
M&V report for an eligible resource, for which ERCs have been issued,
the provisions of paragraph (b) of this section will apply.
(b) In the event of error or misstatement of quantified MWh of
electricity generation or savings in the final M&V report for an
eligible resource, for which ERCs have been issued, the Administrator
will revoke ERCs from the general account held by the authorized
account representative of the eligible resource, in an amount necessary
to correct the error or misstatement. In the event that the general
account of the eligible resource holds an insufficient number of ERCs
to correct the error or misstatement, the authorized account
representative must submit to the Administrator within 30 days a number
of ERCs necessary to correct the error or misstatement. Failure to meet
this requirement will
[[Page 65096]]
result in prohibition of the authorized account representative for the
eligible resource from further participation in the program, unless
reauthorized at the discretion of the Administrator.
(c) The Administrator may freeze the general account held by an
authorized account representative of an eligible resource at any time,
for cause, if the Administrator determines ERCs have been improperly
issued, based on a misrepresentation or misstatement in an eligibility
application or M&V report. The Administrator may also freeze the
general account of an authorized account representative of an eligible
resource pending investigation of potential misrepresentation, error,
or misstatement in an eligibility application of an eligible resource,
or in an M&V report for which ERCs have been issued. Freezing a general
account will prevent transfer of ERCs out of the account.
(d) If ERCs are issued for an eligible resource that is found to be
ineligible, then the Administrator may take the actions in paragraphs
(d)(1) through (3) of this section.
(1) Freeze the general account for the eligible resource,
preventing any transfers of ERCs out of the account.
(2) Revoke and deduct ERCs held in the general account of the
authorized account representative for an eligible resource, in a number
equal to the number of ERCs issued for the ineligible eligible
resource.
(3) In the event that the general account of the eligible resource
holds a number of ERCs less than the number of ERCs issued for the
ineligible eligible resource, the delegated representative of an
eligible resource must submit to the Administrator within 30 days a
number of ERCs necessary to fully account for all ERCs issued for the
ineligible eligible resource. Failure to meet this requirement will
result in prohibition of the eligible resource from further
participation in the program, unless reauthorized at the discretion of
the Administrator.
(e) The Administrator may temporarily or permanently suspend
issuance of ERCs for an eligible resource, for the following reasons in
paragraphs (e)(1) through (3) of this section.
(1) Pending investigation of potential misrepresentation, error, or
misstatement in an M&V report, for which ERCs have been issued, or the
eligibility status of an eligible resource.
(2) In the case of repeated error or misstatements in submitted M&V
reports.
(3) In the case of an intentional misrepresentation in a submitted
M&V report.
Evaluation Measurement and Verification Plans, Monitoring and
Verification Reports, and Verification
Sec. 62.16455 What are the requirements for evaluation measurement
and verification plans for eligible resources?
(a) EM&V plan requirements. Any EM&V plan submitted in support of
the issuance of an ERC pursuant to this rule must meet the requirements
of this section.
(b) General EM&V plan criteria. Each EM&V plan must identify the
eligible resource and its approved eligibility application.
(c) Specific EM&V plan criteria. Each EM&V plan must provide the
manner in which the electricity generated or saved by the eligible
resource will be quantified, monitored and verified, and the manner of
quantification, monitoring and verification must meet the criteria
listed in paragraphs (c)(1) through (7) of this section, as applicable
to the specific eligible resource.
(1) For a nuclear energy resource or a renewable energy resource
with a nameplate capacity of 10 kW or more and for a renewable energy
resource with a nameplate capacity of less than 10 kW for which metered
data are available, each EM&V plan must specify that the requirements
in paragraphs (c)(1)(i) through (vi) of this section are met.
(i) The generation data are physically measured on a continuous
basis using a revenue-quality meter, which means a meter used by a
control area operator for financial settlements, or a meter that meets
the American National Standards Institute No. C12.20., Code for
Electricity Metering, metering accuracy standards, or a meter that
meets an alternative equivalent standard that has been approved in
advance of its use to measure generation pursuant to this regulation by
the EPA.
(ii) The generating data are measured at the generator's bus bar,
or, for a renewable energy resource with a nameplate capacity of less
than 10 kW that is interconnected behind an individual business or
household meter, the generating data were measured at the AC output of
the inverter and adjusted to reflect the only energy delivered into
either the transmission or distribution grid at the generator bus bar
and not any energy used on-site at the generator.
(iii) The generation data from only one eligible resource
generating unit may be associated with each meter, and generation data
may not be aggregated, unless all the following provisions are met:
(A) All of the generating units have the same essential generation
characteristics;
(B) All of the generating units are located in the same State;
(C) The nameplate capacity of the individual units being aggregated
is each less than 150 kW, and units collectively do not exceed a total
nameplate capacity of 1 MW when aggregated, or alternative requirements
approved by the EPA in connection with the specific State plan pursuant
to which that EM&V plan or M&V report is submitted; and
(D) The generation data are measured by the same type of meter that
is subject to the same maintenance and quality assurance procedures.
(iv) The generation data are collected electronically and
telemetered from the generator to its control area operator and
verified through a control area energy accounting or settlement process
which occurs at least monthly, unless the generation unit does not go
through a control area operator, in which case the generation data must
be collected by manual meter readings conducted by an independent
verifier that is either not affiliated with the owner or operator of
the qualifying renewable energy generating resource or is precluded
pursuant to the relevant State plan from the ability to transfer or
retire ERCs issued to that qualifying renewable energy generating
resource or, if the generating unit is less than 10 kw and does not
generate enough electricity to enable monthly reporting, then the data
may be self-reported and reported no less than annually.
(v) The generation data serve a load that otherwise would have been
served by the grid if not for the generator. Specifically:
(A) ERCs shall not be issued for energy generation used to supply
the ancillary equipment used to operate a generating station or
substation (``station service'') or parasitic load on the generator's
side of the point of interconnection; and
(B) For generators interconnected to transmission systems and with
on-site loads other than station service drawing generation before the
metering point, ERCs may be issued for on-site load, if the owner or
operator of the eligible resource can demonstrate that the metering
used is capable of distinguishing between on-site load and station
service.
(vi) Any other requirements approved by the EPA in connection with
the specific State plan pursuant to which that EM&V plan is submitted.
[[Page 65097]]
(2) For a renewable energy resource with a nameplate capacity of
less than 10 kW and that does not have a meter, each EM&V plan must
require that the following requirements in paragraphs (c)(2)(i) though
(vii) of this section are met.
(i) Metered data are unavailable.
(ii) At least 1 MW of net energy output is generated to the
distribution or transmission system over a continuous 365-day period.
(iii) The generation data may not be aggregated, unless the
following provisions are met:
(A) All of the generating units have the same essential generation
characteristics;
(B) All of the generating units are located in the same State;
(C) The nameplate capacity of the individual units being aggregated
is each less than 150 kW, and units collectively do not exceed a total
nameplate capacity of 1 MW when aggregated, or alternative requirements
approved by the EPA in connection with the specific State plan pursuant
to which that EM&V plan or M&V report is submitted; and
(D) The generation data are measured by the same generation
estimating software or algorithms.
(iv) The generation data are measured on at least a monthly basis
using generation estimating software or algorithms that are based on an
on-site inspection prior to interconnection and a resource study (wind,
shading, solar irradiance, depending on the resource), or engineering
information that takes into account the capacity, age, and type of
qualifying energy generating resource, and all input parameters and
assumptions must be clearly delineated, or if the generating unit does
not generate enough electricity to enable monthly reporting, then the
data may be reported no less than annually.
(v) The generation data are self-reported to the distribution
utility through an electronic internet-based portal with software that
reports total and hourly generation.
(vi) The generation data serve a load that otherwise would have
been served by the grid if not for the generator. The ERC is only based
on generation transferred from the eligible resource to the
transmission or distribution grid, and is not based on the generation
used on-site by the customer.
(vii) Any other requirements approved by the EPA in connection with
the specific State plan pursuant to which that EM&V plan is submitted.
(3) For qualified biomass feedstocks used, in addition to the
requirements of paragraphs (c)(1) or (2) of this section, whichever
section is applicable, each EM&V plan must demonstrate that the
requirements approved by the EPA for that biomass feedstock, and its
associated biogenic CO2, have been met.
(4) For a waste-to-energy resource, in addition to the requirements
of paragraphs (c)(1) or (2) of this section, as applicable, and
paragraph (c)(3) of this section, each EM&V plan must specify:
(i) The total net energy generation from the resource in MWh;
(ii) The method for determining the specific portion of the total
net energy output from the resource that is related to the biogenic
portion of the waste materials; and
(iii) The net energy output measured with the relevant method
approved by the EPA in connection with the specific State plan pursuant
to which that EM&V plan is submitted demonstrates that the requirements
approved by the EPA in connection with that State plan have been met.
(5) For a combined heat and power unit, in addition to the
requirements of paragraphs (c)(1) or (2) of this section, as
applicable, and paragraph (c)(3) of this section, each EM&V plan must
meet one of the requirements in paragraphs (c)(5)(i) through (iv) of
this section, as applicable, and any other requirements approved by the
EPA.
(i) If the combined heat and power unit has an electric generating
capacity greater than 25 MW, then the EM&V plan must meet the
requirements that apply to an affected EGU under Sec. 62.16540.
(ii) If the combined heat and power unit has an electric generating
capacity less than or equal to 25 MW and greater than 1 MW, and it uses
only natural gas and/or distillate fuel oil, then the EM&V plan must
meet the low mass emission unit CO2 emission monitoring and
reporting methodology in part 75 of this chapter.
(iii) If the combined heat and power unit has an electric
generating capacity less than or equal to 25 MW and greater than 1 MW,
and it uses anything other than only natural gas and/or distillate fuel
oil, then the EM&V plan must meet the low mass emission unit
CO2 emission monitoring and reporting methodology in part 75
of this chapter.
(iv) If the combined heat and power unit has an electric generating
capacity less than or equal to 1 MW the unit must keep monthly
cumulative recordings of useful thermal output and fossil fuel input
along with the determination of baseline thermal source efficiencies
based on manufacturer data. For CHP units that directly serve on-site
end-use electricity loads, avoided T&D system losses can be assessed as
is commonly practiced with demand-side EE.
(6) For demand-side electricity savings that avoid a transmission
and distribution loss, each EM&V plan must measure the transmission and
distribution loss based on the lesser of 6 percent of the facility- or
premises-level electricity savings measured at the electricity
customer's meter, or the statewide annual average transmission and
distribution loss rate (expressed as a percentage) from the most recent
year that is published in the US EIA State Electricity Profile. No
other transmission and distribution loss factors may be used in
calculating the electricity savings.
(7) Each EM&V plan for an EE program, EE project, or EE measure
must specify how each of the requirements in paragraphs (c)(7)(i)
through (x) of this section will be met in quantifying the electricity
savings from that EE program, EE project, or EE measure.
(i) All electricity savings must be quantified on an ex-post basis,
which means after the electricity savings have occurred, or on a real-
time basis, which means at the time the electricity savings are
occurring. Electricity savings must not be quantified on an ex-ante
basis, which means estimates of MWh savings that are generated prior to
implementing the subject EE program, EE project, or EE measure, and
that are not quantified using EM&V methods and procedures.
(ii) All electricity savings must be quantified and verified based
on methods and procedures detailed in an industry best-practice EM&V
protocol or guideline. Each EM&V plan must include a demonstration of
how the best-practice protocol or guideline was selected and will be
applied to the specific EE program, EE project, or EE measure covered
in the EM&V plan, and an explanation of why that particular protocol or
guideline was selected. Protocols and guidelines are considered to be
best practice if they:
(A) Have gone through a rigorous and credible peer review process
that shows the applicable methods to be valid through empirical
testing; and
(B) Have been accepted and approved for use by identifiable state
regulatory commissions. Examples of such protocols and guidelines that
may be provided in EM&V guidance issued by the Administrator will be
acceptable.
(iii) All electricity savings must be quantified as the difference
between the observed electricity use and a common practice baseline
(CPB), which is the equipment that would typically have been
installed--or that a typical
[[Page 65098]]
consumer or building owner would have continued using--in a given
circumstance (i.e., a given building type, EE program type or delivery
mechanism, and geographic region) at the time of EE implementation.
Examples of CPBs for specific EE programs, EE projects, EE measures,
and for certain EM&V methods that may be provided in EM&V guidance
issued by the Administrator will be acceptable. The EM&V plan must
specify the reason the specific CPB was selected, which must include an
analysis of the appropriateness of that CPB for the EE program, EE
project, or EE measure covered in the EM&V plan, based on:
(A) Characteristics of the EE program, EE project, or EE measure;
(B) The delivery mechanism used to implement the EE program, EE
project, or EE measure (e.g., installed as part of a utility EE program
versus a point-of-sale rebate);
(C) Local consumer and market characteristics;
(D) Applicable building energy codes and standards and average
compliance rates; and
(E) The method applied: Project-based measurement and verification
(PB-MV), comparison group approaches, or deemed savings.
(iv) All electricity savings must be quantified by applying one or
more of the following methods: Project-based measurement and
verification (PB-MV), comparison group approaches, or deemed savings.
(A) If a comparison group approach is used, then the EM&V plan must
quantify electricity savings by taking the difference between a
comparison group's electricity use and the electricity use of EE
program participants. Comparison group approaches may include
randomized control trials and quasi-experimental methods, as described
in industry best-practice protocols and guidelines. Examples of such
protocols and guidelines provided in EM&V guidance that may be issued
by the Administrator will be acceptable.
(B) If deemed savings are used, then the EM&V plan must specify
that the deemed savings values will only be used for the specific EE
measure for which they were derived. The EM&V plan must also specify
the name and Web address of the technical reference manual (TRM) in
which all deemed electricity savings values will be documented. Prior
to use in an EM&V plan, all TRMs must undergo a review process in which
the public, stakeholders, and experts are invited--with adequate
advance notification (via the internet and other social media)--to
provide comment, have at least 2 months to provide comment, and in
which all such comments and associated responses are made publicly
available. All TRMs must also be publicly accessible over the full
period of time in which they are being used in conjunction with an EM&V
plan for the purpose of quantifying savings, and must be subsequently
updated in the same manner at least every 3 years. The TRM must
indicate, for each subject EE measure, the associated electricity
savings value, the conditions under which the value can be applied
(including the climate zone, building type, manner of implementation,
applicable end uses, operating conditions, and effective useful life),
and the manner in which the electricity savings value was quantified,
which must include applicable engineering algorithms, source
documentation, specific assumptions, and other relevant data to support
the quantification of savings from the subject EE measure.
(v) All EE programs, EE projects, or EE measures must be quantified
at time intervals (in years) sufficient to ensure that MWh savings are
accurately and reliably quantified. Such time intervals must be
specified and explained in the EM&V plan. Factors that must be taken
into consideration when determining the appropriate time interval
include the characteristics of the specific EE program, EE project, or
EE measure, expected variability in electricity savings (where greater
variability necessitates more frequent quantification), the expected
scale and magnitude of the electricity savings (where greater
quantities of savings necessitate more frequent quantification), and
the experience implementing and quantifying savings from the resource
(where less experience--for example, with new and innovative EE program
types--necessitates more frequent quantification). The time intervals
must end no sooner than the last day of the effective useful life of
the EE program, EE project, or EE measure, and must last no longer
than:
(A) Every 4-year intervals for building energy codes and product
standards;
(B) Every 1, 2, or 3 years for public or consumer-funded EE
program, EE project, or EE measure, as relevant for the type of EE
program, EE project, or EE measure and factors listed in paragraph
(c)(7)(v) of this section; and
(C) Annually for commercial and industrial projects, unless the
resource provider can provide a reasonable justification in the EM&V
plan for why an annual time interval is not feasible, and can
additionally explain how the accuracy and reliability of savings values
will not be lessened.
(vi) EM&V plans must specify and document how the EM&V components
in paragraphs (c)(7)(vi)(A) through (E) of this section will be
analyzed, considered, or otherwise addressed in the quantification and
verification of electricity savings.
(A) The effects of changes in independent factors on reported
electricity savings (i.e., factors that are not directly related to the
EE measure, such as weather, occupancy, and production levels).
(B) The effective useful life (EUL) or duration of time the EE
measure is anticipated to remain in place and operable with the
potential to save electricity, which must be based on the application
of EM&V methods, an industry best-practice persistence study, deemed
estimates of effective useful life, or a combination of all three.
(1) If deemed estimates of effective useful life are used, then
they must specify the date by which the EE measure will stop saving
electricity.
(2) If industry best-practices persistence studies are used to
modify an effective-useful-life value, then they must be conducted at
least every 5 years.
(C) The potential sources of double counting, and the associated
steps for avoiding and correcting for it, such as:
(1) For an EE program or EE project with identified participants,
track the type and number of EE measures implemented at the utility-
customer level.
(2) For an EE program or EE project without identified
participants, such as point-of-sale rebates and retailer or
manufacturer incentive programs, track applicable vendor, retailer, and
manufacturer data.
(3) For EE programs (such as those implemented by a utility) and EE
projects (such as those implemented by an energy service company) that
both have identified participants, use tracking data to avoid and
correct for double counting that may occur across the two; and
(4) For EE programs with identified participants and those without
(such as retail incentives to purchase energy-efficient equipment), use
EE program tracking data for the former and use applicable vendor,
retailer, and manufacturer data for the latter to avoid and correct for
double counting that may occur across the two.
(D) The EE savings verification approaches for ensuring that EE
measures have been properly installed, are operating as intended, and
therefore have the potential to save electricity,
[[Page 65099]]
including how verification will be carried out within the first year of
implementation of the EE program, EE project, or EE measure using best-
practice approaches, such as physical inspections at a customer's
premises, phone and mail surveys, and reviews of sales receipts and
other documentation. If such approaches are documented in EM&V guidance
issued by the Administrator, they will be treated as acceptable.
(E) The interactive effects of EE programs, EE projects, or EE
measures on electricity usage, which are increases or decreases in
electricity usage at an end-use facility or premises that occurs
outside of specific end-uses(s) targeted by the EE program, EE project,
or EE measure (e.g., lighting retrofits to improve EE can reduce waste
heat to the surrounding conditioned space, and therefore may increase
the required electric heating load in a facility or premises).
(vii) The EM&V plan must specify how the accuracy and reliability
of the electricity savings of the EE program, EE project, or EE measure
will be assessed, and must discuss the rigor of the method selected to
quantify the electricity savings. It must also discuss the approaches
that will be used to control all relevant types of bias and to minimize
the potential for systematic and random error, as well as the program-
or project-specific circumstances in which such bias and error are
likely to arise. Approaches to minimizing bias and error are provided
in the EM&V guidance that may be issued by the Administrator will be
acceptable.
(viii) If sampling will be used to quantify the electricity savings
from an EE program, then the MWh estimates derived from sampling must
have at least 90 percent confidence intervals whose end points are no
more than 10 percent of the estimate, and the statistical
precision of the associated estimates must be specified in the EM&V
plan.
(ix) All data sources and key assumptions used to quantify
electricity savings must be described in the EM&V plan.
(x) Any additional information necessary to demonstrate that the
electricity savings were appropriately quantified and verified.
Approaches to quantifying and verifying savings from several EE program
and EE project types that are provided in EM&V guidance that may be
issued by the Administrator will be acceptable.
(d) You must ensure that any EM&V plan submitted pursuant to this
subpart includes the following certification:
(1) ``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) [Reserved]
Sec. 62.16460 What are the requirements for monitoring and
verification reports for eligible resources?
(a) M&V report requirements. Any M&V report that is submitted, in
support of the issuance of an ERC that can be used in accordance with
Sec. 62.16420, must meet the requirements of this section.
(b) General M&V report criteria. Each M&V report must include the
following:
(1) For the first M&V report submitted, documentation that the
electricity-generating resources, electricity-saving measures, or
practices were installed or implemented consistent with the description
in the approved eligibility application required in Sec. 62.16445(a);
and
(2) For each M&V report submitted:
(i) Identification of the time period covered by the M&V report;
(ii) A description of how relevant quantification methods,
protocols, guidelines, and guidance specified in the EM&V plan were
applied during the reporting period to generate the quantified MWh of
generation or MWh of electricity savings;
(iii) Documentation (including data) of the energy generation and/
or electricity savings from any activity, project, measure, resource,
or program addressed in the EM&V report, quantified and verified in MWh
for the period covered by the M&V report, in accordance with its EM&V
plan, and based on ex-post energy generation or savings;
(iv) Documentation of any change in the energy generation or
savings capability of the eligible resource during the period covered
by the M&V report and the date on which the change occurred, and either
certification that the eligible resource continued to meet all
eligibility requirements during the reporting period covered by the M&V
report or disclosure of any material changes to the eligible resource
from the description of the eligible resource in the approved
eligibility application, which must include any change in the energy
generation (e.g., nameplate MW capacity) or electricity savings
capability of the qualifying eligible resource (including the date of
the change); and
(v) Documentation of any change in ownership interest of the
qualifying eligible resource (including the date of the change).
(c) You must ensure that any M&V report submitted pursuant to this
subpart includes the following certification:
(1) ``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) [Reserved]
Sec. 62.16465 What are the requirements for verification reports?
(a) A verification report included as part of an eligibility
application or an M&V report must meet the requirements of paragraph
(b) of this section (for the eligibility application verification
report) and paragraph (c) of this section (for the M&V report
verification report) and include the following:
(1) A verification statement that sets forth the findings of the
accredited independent verifier, based on the verifier's assessment of
the information and data in the eligibility application or M&V report
that is the subject of the verification report, including an assessment
of whether the eligibility application or M&V report contains any
material misstatements or material data discrepancies, and whether the
submittal conforms with applicable regulatory requirements. The
verification statement must clearly identify how levels of assurance
and materiality are defined as part of the verifier assessment.
(2) The following statement, signed by the accredited independent
verifier: ``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
personal knowledge and/or inquiry of those individuals with primary
responsibility
[[Page 65100]]
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) A verification report included as part of an eligibility
application must, at a minimum, describe the review conducted by the
accredited independent verifier and verify each of the following:
(1) The eligibility of the eligible resource to be issued ERCs
pursuant to this regulation, in accordance with Sec. 62.16435 and
Sec. 62.16445(a), including an analysis of the adequacy and validity
of the information submitted by the authorized account representative
to demonstrate that the eligible resource meets each applicable
requirement of Sec. 62.16435 and Sec. 62.16445(a).
(2) The eligible resource is not duplicative of a resource used to
meet emission standards or a state measure in another approved State
plan.
(3) The eligible resource exists or the practice or activity will
be implemented in the manner specified in the eligibility application.
(4) The EM&V plan meets the requirements of Sec. 62.16455.
(5) Disclosure of any mandatory or voluntary programs to which data
is reported relating to the eligible resource (e.g., reporting of
electric generation by a renewable energy resource to a renewable
energy certificate tracking system).
(6) Any other information required by the Administrator or that the
accredited independent verifier finds, in its professional opinion, is
necessary to assess the adequacy and validity of information and data
supplied by the authorized account representative.
(c) A verification report included as part of a M&V report must, at
a minimum, describe the review conducted by the accredited independent
verifier and verify the following:
(1) The adequacy and validity of the information and data submitted
in the submittal by the authorized account representative to quantify
eligible MWh of electric generation or electricity savings during the
period for which the authorized account representative seeks issuance
of ERCs, as well as all supporting information and data identified in
the EM&V plan and M&V report. This analysis must include a quality
assurance and quality control check of the data and ensure that all
generation or savings data are within a technically feasible range for
that specific eligible resource.
(i) For metered generation, the data validity check must compare
reported electricity generation to an engineering estimate of the
maximum generation potential of the qualified renewable energy
resource, based on, at a minimum, its maximum nameplate capacity in MW
and the number of days since the prior cumulative meter reading was
entered in the ERC tracking system. If the data entered exceed the
estimated technically feasible generation, then the reported data and
the estimate must be analyzed in the verification report.
(ii) For all electricity generated or saved, the accredited
independent verifier must describe the likely source of any data
discrepancy and determine in the verification report any MWh generated
or saved.
(2) The M&V report meets the requirements of Sec. 62.16460.
(3) Any other information required by the Administrator or that the
accredited independent verifier finds, in its professional opinion, is
necessary to assess the adequacy and validity of information and data
supplied by the authorized account representative.
Sec. 62.16470 What is the accreditation procedure for independent
verifiers?
(a) Only Administrator-accredited independent verifiers may provide
a verification report for an eligibility application or M&V report.
(b) Applications for accreditation must follow a procedure and form
specified by the Administrator which includes a demonstration by the
verifier that it meets the requirements in paragraph (c) of this
section.
(c) Independent verifiers must meet each of the requirements in
paragraphs (c)(1) through (6) of this section to be accredited.
(1) Independent verifiers must have the skills, experience, and
resources (personnel and otherwise) to provide verification reports,
including the following:
(i) Appropriate technical qualification (professional engineer or
otherwise) to evaluate the eligible resource for which the independent
verifier is seeking accreditation, which may include ANSI accreditation
under ISO 14065 for GHG validation and verification bodies;
(ii) Appropriate auditing and accounting qualifications for
financial and non-financial data monitoring, auditing, and quality
assurance and quality control to evaluate the eligible resource for
which the independent verifier is seeking accreditation;
(iii) Knowledge of the requirements of the Administrator's
CO2 Rate-based Trading Program regulations and related
guidance;
(iv) Knowledge of the eligible resource categories for which the
independent verifier is seeking accreditation, including relevant
aspects of the design, operation, and related energy generation or
electricity savings monitoring and reporting approaches for such
eligible resources; and
(v) Capability to perform key verification activities, such as
development of a verification report; performance of site visits;
review and recalculation of reported data; review of data management
systems; review of quantification methods used in accordance with an
approved EM&V plan; preparation of a verification statement, list of
findings, and verification report; and internal review of the
verification findings and report.
(2) Independent verifiers must document, in the application for
accreditation, the independent verifiers that will provide verification
services, including lead verifiers, key personnel and any contractors
or subcontractors (collectively, accredited independent verification
team) and demonstrate that they meet the requirements of section Sec.
62.16470(d)(1). Once accredited, only the accredited independent
verification team identified in the accreditation application and
accredited by the State may provide a verification report.
(3) An independent verifier must specify the eligible resource
categories for which it is seeking accreditation, and an accredited
independent verifier may only provide verification services related to
an eligible resource category for which it is accredited.
(4) Prospective independent verifiers must meet the requirements of
Sec. 62.16475(d) through (f) and demonstrate that they have in place
adequate systems and protocols to identify, disclose and avoid
potential conflicts of interest.
(5) An accredited independent verifier must not be debarred,
suspended, or proposed for debarment pursuant to the Government-wide
Debarment and Suspension regulations, part 32 of this chapter, or the
Debarment, Suspension and Ineligibility provisions of the Federal
Acquisition Regulations, 48 CFR part 9, subpart 9.4.
(6) An accredited independent verifier must maintain, for its
employees, and ensure the maintenance of, for any parties that it
employs, professional liability insurance, as defined in 31 CFR
50.5(q), through an insurance provider that possesses a financial
strength rating in the top four categories from either
[[Page 65101]]
Standard & Poor's or Moody's, specifically, AAA, AA, A or BBB for
Standard & Poor's, and Aaa, Aa, A, or Baa for Moody's. Any entity
covered by this paragraph must disclose the level of professional
liability insurance they possess when entering into contracts to
provide verification services pursuant to this regulation.
(d) Requirements for maintenance of accreditation status, as
follows:
(1) Accredited independent verifiers must meet the requirements of
Sec. 62.16475 when providing verification services for an authorized
account representative; and
(2) The instances specified in Sec. 62.16475(d) are cause for
revocation of a verifier's accreditation.
Sec. 62.16475 What are the procedures of accredited independent
verifiers must follow to avoid conflict of interest?
(a) Accredited independent verifiers must not provide verification
services for any eligible resource for which it has a conflict of
interest (COI), which means:
(1) Accredited independent verifiers must have, or have had, no
direct or indirect financial interest in, or other financial
relationships with, an eligible resource, or any prospective eligible
resource, for which they seek to provide a verification report;
(2) Accredited independent verifiers must have, or have had, no
direct or indirect organizational or personal relationships with an
eligible resource, that would impact their impartiality in assessing
the validity and accuracy of the information in an eligibility
application or M&V report;
(3) Accredited independent verifiers must have, or have had, no
role in the development and implementation of an eligible resource for
which an authorized account representative seeks issuance of ERCs,
beyond the provision of verification services;
(4) Accredited independent verifiers must not be compensated,
financially or otherwise, directly or indirectly, on the basis of the
content of its verification report (including eligibility approval of
an eligible resource, the quantified and verified MWh in an M&V report,
ERC issuance, or the number of ERCs issued);
(5) Accredited independent verifiers must not own, buy, sell, or
hold ERCs, or other financial derivatives related to ERCs, or have a
financial relationship with other parties that own, buy, sell, or hold
ERCs or other related financial derivatives;
(6) An accredited independent verifier must not be incapable of
providing an impartial verification report for any other reason; and
(7) An accredited independent verifier must ensure that the subject
of any verification report must not have the opportunity to review or
influence any draft or final verification report before its submittal
to the Administrator, and the accredited independent verifier must
share any drafts of its reports with the Administrator at the same time
as it shares them with the subject of the report.
(b) A contract with an eligible resource for the provision of
verification services will not constitute a COI.
(c) Verification reports must include an attestation by the
accredited independent verifier that it evaluated and disclosed to the
Administrator any potential COI related to an eligible resource.
(d) Prior to engaging for the provision of verification services,
an accredited independent verifier must demonstrate that it has no COI
related to the eligible resource, as specified in paragraph (a) of this
section. If a COI is identified for a person or persons within an
accredited independent verifier for a specific subject or verification,
in accordance with paragraphs (e) and (f) of this section, then an
accredited independent verifier may propose to the Administrator steps
that will be taken to eliminate the COI which include prohibiting the
person or persons with the conflict from any involvement in the matter
subject to the conflict, including verification services, access to
information related to the verification services, access to any draft
or final verification reports, any communications with the person(s)
conducting the verification services. In no instance shall an
accredited independent verifier engage in verification services for an
eligible resource without the approval of the Administrator.
(e) Prior to engaging in verification services and writing a
verification report, an accredited independent verifier must disclose
to the Administrator all information necessary for the Administrator to
evaluate a potential COI (including information concerning its
ownership, past and current clients, related entities, as well as any
other facts or circumstances that have the potential to create a COI).
(f) Accredited verifiers have an ongoing obligation to disclose to
the Administrator any facts or circumstances that may give rise to a
COI as defined in paragraph (a) of this section.
(g) The Administrator may reject a verification report from an
accredited independent verifier, if the Administrator determines that
the accredited independent verifier has a COI as defined in paragraph
(a) of this section. If the Administrator rejects an accredited
independent verifier report for such reasons, then the eligibility
application or M&V report submittal shall be deemed incomplete and ERCs
must not be issued pursuant to it.
Sec. 62.16480 What is the process for the revocation of accreditation
status for an independent verifier?
(a) The Administrator may revoke the accreditation of an
independent verifier at any time for cause, including for the reasons
specified in paragraphs (a)(1) through (4) of this section.
(1) Failure to fully disclose any issues that may lead to a COI
with respect to an eligible resource, or other related entity, in
accordance with Sec. 62.16475(d) through (f).
(2) The accredited independent verifier is no longer qualified to
provide verification services.
(3) Negligence in the conduct of verification activities, or
neglect of responsibilities pursuant to the requirements of Sec. Sec.
62.16465, 62.16470, and 62.16475.
(4) Intentional misrepresentation of data in a verification report.
(b) [Reserved]
Designated Representatives
Sec. 62.16485 How are designated representatives and alternate
designated representatives authorized and what role do authorized
designated representatives and alternate designated representatives
play?
(a) Except as provided under Sec. 62.16495, each affected EGU, and
each eligible resource shall have one and only one designated
representative, with regard to all matters under the CO2
Rate-based Trading Program.
(1) The designated representative shall be selected by an agreement
binding on the owners and operators of the affected EGU and must act in
accordance with the certification statement in Sec.
62.16500(a)(4)(iii).
(2) Upon and after receipt by the Administrator of a complete
certificate of representation under Sec. 62.16500:
(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 affected EGU
in all matters pertaining to the CO2 Rate-based Trading
Program, notwithstanding any agreement between the designated
representative and such owners and operators; and
(ii) The owners and operators of the affected EGU shall be bound by
any decision or order issued to the designated representative by the
[[Page 65102]]
Administrator regarding the affected EGU.
(b) Except as provided under Sec. 62.16495, each affected EGU 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 must 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 affected EGU and
must act in accordance with the certification statement in Sec.
62.16500(a)(4)(iii).
(2) Upon and after receipt by the Administrator of a complete
certificate of representation under Sec. 62.16500,
(i) The alternate designated representative must 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 affected EGU shall be bound
by any decision or order issued to the alternate designated
representative by the Administrator regarding any such affected EGU.
(c) Except in this section, Sec. Sec. 62.16490 through 62.16510,
and Sec. 62.16570, whenever the term ``designated representative'' (as
distinguished from the term ``common designated representative'') is
used in this subpart, the term shall be construed to include the
designated representative.
Sec. 62.16490 What responsibilities do designated representatives and
alternate designated representatives hold?
(a) Except as provided under Sec. 62.16510 concerning delegation
of authority to make submissions, each submission under the
CO2 Rate-based Trading Program must be made, signed, and
certified by the designated representative or alternate designated
representative for each affected EGU for which the submission is made.
Each such submission must 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 affected EGU 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
an affected EGU only if the submission has been made, signed, and
certified in accordance with paragraph (a) of this section and Sec.
62.16510.
Sec. 62.16495 What are the processes for changing designated
representatives, alternate designated representatives, owners and
operators, and affected EGUs?
(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. 62.16500. 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 affected EGU.
(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. 62.16500. 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 affected EGU.
(c) Changes in owners and operators. (1) In the event an owner or
operator of an affected EGU is not included in the list of owners and
operators in the certificate of representation under Sec. 62.16500,
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 affected EGU, 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
affected EGU, including the addition or removal of an owner or
operator, the designated representative or any alternate designated
representative must submit a revision to the certificate of
representation under Sec. 62.16500 amending the list of owners and
operators to reflect the change.
(d) Changes in affected EGUs at the source. Within 30 days of any
change in which affected EGUs are located at a source (including the
addition or removal of an affected EGU), the designated representative
or any alternate designated representative must submit a certificate of
representation under Sec. 62.16500 amending the list of affected EGUs
to reflect the change.
(1) If the change is the addition of an affected EGU that operated
(other than for purposes of testing by the manufacturer before initial
installation) before being located at the source, then the certificate
of representation must identify, in a format prescribed by the
Administrator, the entity from whom the affected EGU was purchased or
otherwise obtained (including name, address, telephone number, and
facsimile transmission number (if any)), the date on which the affected
EGU was purchased or otherwise obtained, and the date on which the
affected EGU became located at the source.
(2) If the change is the removal of an affected EGU, then the
certificate of representation must identify, in a format prescribed by
the Administrator, the entity to which the affected EGU was sold or
that otherwise obtained the affected EGU (including name, address,
telephone number, and facsimile transmission number (if any)), the date
on which the affected EGU was sold or otherwise obtained, and the date
on which the affected EGU became no longer located at the source.
Sec. 62.16500 What must be included in a certificate of
representation?
(a) A complete certificate of representation for a designated
representative or an alternate designated representative must include
the elements in paragraphs (a)(1) through (5) of this section in a
format prescribed by the Administrator.
(1) Identification of the affected EGU for which the certificate of
representation is submitted, including names, 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,
[[Page 65103]]
identification number and nameplate capacity (in MWe, rounded to the
nearest tenth) of each generator served by each such affected EGU, net-
summer capacity, actual or projected date of commencement of commercial
operation, and a statement of whether such affected EGU is located in
Indian country. If a projected date of commencement of commercial
operation is provided, then the actual date of commencement of
commercial operation must be provided when such information becomes
available.
(2) The name, address, email 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 affected EGU.
(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 affected
EGU'';
(ii) ``I certify that I have all the necessary authority to carry
out my duties and responsibilities under the CO2 Rate-based
Trading Program on behalf of the owners and operators of the affected
EGU and that each such owner and operator shall be fully bound by my
representations, actions, inactions, or submissions and by any decision
or order issued to me by the Administrator regarding the affected
EGU''; and
(iii) ``Where there are multiple holders of a legal or equitable
title to, or a leasehold interest in, an affected EGU, or where a
utility or industrial customer purchases power from an affected EGU
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 affected EGU; and ERCs and proceeds of transactions
involving CO2 Rate-based Trading Program 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 ERCs by contract, ERCs and proceeds of transactions
involving CO2 Rate-based Trading Program ERCs 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. 62.16505 What is the Administrator's role in objections
concerning designated representatives and alternate designated
representatives?
(a) Once a complete certificate of representation under Sec.
62.16500 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. 62.16500 is received
by the Administrator.
(b) Except as provided in paragraph (a) of this section, no
objection or other communication submitted to the Administrator
concerning the authorization, or any representation, action, inaction,
or submission, of a designated representative or alternate designated
representative shall affect any representation, action, inaction, or
submission of the designated representative or alternate designated
representative or the finality of any decision or order by the
Administrator under the CO2 Rate-based 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 ERC transfers.
Sec. 62.16510 What process must designated representatives and
alternate designated representatives follow to delegate their
authority?
(a) A designated representative may delegate, to one or more
natural persons, his or her authority to make an electronic submission
to the Administrator provided for or required under this subpart.
(b) An alternate designated representative may delegate, to one or
more natural persons, his or her authority to make an electronic
submission to the Administrator provided for or required under this
subpart.
(c) In order to delegate authority to a natural person to make an
electronic submission to the Administrator in accordance with paragraph
(a) or (b) of this section, the designated representative or alternate
designated representative, as appropriate, must submit to the
Administrator a notice of delegation, in a format prescribed by the
Administrator, that includes the following elements:
(1) The name, address, email address, telephone number, and
facsimile transmission number (if any) of such designated
representative or alternate designated representative;
(2) The name, address, email address, telephone number, and
facsimile transmission number (if any) of each such natural person
(referred to in this section as an ``agent'');
(3) For each such natural person, a list of the type or types of
electronic submissions under paragraph (a) or (b) of this section for
which authority is delegated to him or her; and
(4) The following certification statements by such designated
representative or alternate designated representative:
(i) ``I agree that any electronic submission to the Administrator
that is made by an agent identified in this notice of delegation and of
a type listed for such agent in this notice of delegation and that is
made when I am a designated representative or alternate designated
representative, as appropriate, and before this notice of delegation is
superseded by another notice of delegation under Sec. 62.16510(d)
shall be deemed to be an electronic submission by me''; and
(ii) ``Until this notice of delegation is superseded by another
notice of delegation under Sec. 62.16510(d), I agree to maintain an
email account and to notify the Administrator immediately of any change
in my email address unless all delegation of authority by me under
Sec. 62.16510 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
[[Page 65104]]
be deemed to be an electronic submission by the designated
representative or alternate designated representative submitting such
notice of delegation.
Monitoring, Recordkeeping, Reporting
Sec. 62.16515 How are compliance accounts and general accounts
established and used, and how is ERC issuance documentation accessed?
(a) Compliance accounts. (1) Upon receipt of a complete certificate
of representation under Sec. 62.16500, the Administrator will
establish a compliance account for the affected EGU for which the
certificate of representation was submitted, unless the affected EGU
already has a compliance account. The designated representative and any
alternate designated representative of an affected EGU shall be the
authorized account representative and the alternate authorized account
representative, respectively, of the compliance account.
(2) A compliance account will hold ERCs intended for surrender by a
designated representative when demonstrating an affected EGUs
compliance with a CO2 emission standard as applicable in
Sec. 62.16420. A compliance account may be established for a facility
with one or more affected EGUs, provided that the account contains
subaccounts for each affected EGU within the facility.
(b) Retirement accounts. (1) A retirement account, into which ERCs
held in a compliance account for an affected EGU are surrendered by the
owner or operator of an affected EGU, for use in demonstrating
compliance with its emission standards. The retirement account may only
be held by the Administrator, and ERCs deposited into it are
permanently retired. Once an ERC is retired, the ERC shall no longer be
transferable to another account in that ERC tracking system or any
other ERC tracking system.
(2) [Reserved]
(c) General accounts--(1) Application for a general account. (i)
Designated representatives of affected EGUs, authorized account
representatives of eligible resources, and any other person may apply
to open a general account, for the purpose of holding and transferring
ERCs, by submitting to the Administrator a complete application for a
general account. Such application must 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 ERCs held in the
general account.
(B) The agreement by which the alternate authorized account
representative is selected must 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 must include the
following elements in a format prescribed by the Administrator:
(A) Name, mailing address, email 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 ERCs 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 ERCs held in the general account. I certify that I have
all the necessary authority to carry out my duties and responsibilities
under the CO2 Rate-based Trading Program on behalf of such
persons and that each such person shall be fully bound by my
representations, actions, inactions, or submissions and by any decision
or order issued to me by the Administrator regarding the general
account''; and
(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 (c)(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 ERCs held in the
general account in all matters pertaining to the CO2 Rate-
based 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; and
(C) Each person who has an ownership interest with respect to ERCs
held in the general account shall be bound by any decision or order
issued to the authorized account representative or alternate authorized
account representative by the Administrator regarding the general
account.
(ii) Except as provided in paragraph (c)(5) of this section
concerning delegation of authority to make submissions, each submission
concerning the general account must 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 ERCs held in the general account. Each such submission
must 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 ERCs 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,
[[Page 65105]]
including the possibility of fine or imprisonment.''
(iii) Except in this section, whenever the term ``authorized
account representative'' is used in this subpart, the term shall be
construed to include the authorized account representative or any
alternate authorized account representative.
(3) Changing authorized account representative and alternate
authorized account representative; changes in persons with ownership
interest.
(i) The authorized account representative of a general account may
be changed at any time upon receipt by the Administrator of a
superseding complete application for a general account under paragraph
(c)(1) of this section. Notwithstanding any such change, all
representations, actions, inactions, and submissions by the previous
authorized account representative before the time and date when the
Administrator receives the superseding application for a general
account shall be binding on the new authorized account representative
and the persons with an ownership interest with respect to the ERCs in
the general account.
(ii) The alternate authorized account representative of a general
account may be changed at any time upon receipt by the Administrator of
a superseding complete application for a general account under
paragraph (c)(1) of this section. Notwithstanding any such change, all
representations, actions, inactions, and submissions by the previous
alternate authorized account representative before the time and date
when the Administrator receives the superseding application for a
general account shall be binding on the new alternate authorized
account representative, the authorized account representative, and the
persons with an ownership interest with respect to the ERCs in the
general account.
(iii)(A) In the event a person having an ownership interest with
respect to ERCs 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 ERCs in the general account,
including the addition or removal of a person, the authorized account
representative or any alternate authorized account representative must
submit a revision to the application for a general account amending the
list of persons having an ownership interest with respect to the ERCs
in the general account to include the change.
(4) Objections concerning authorized account representative and
alternate authorized account representative.
(i) Once a complete application for a general account under
paragraph (c)(1) of this section has been submitted and received, the
Administrator will rely on the application unless and until a
superseding complete application for a general account under paragraph
(c)(1) of this section is received by the Administrator.
(ii) Except as provided in paragraph (c)(4)(i) of this section, no
objection or other communication submitted to the Administrator
concerning the authorization, or any representation, action, inaction,
or submission of the authorized account representative or any alternate
authorized account representative of a general account shall affect any
representation, action, inaction, or submission of the authorized
account representative or any alternate authorized account
representative or the finality of any decision or order by the
Administrator under the CO2 Rate-based 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 ERCs
transfers.
(5) Delegation by authorized account representative and alternate
authorized account representative.
(i) An authorized account representative of a general account may
delegate, to one or more natural persons, his or her authority to make
an electronic submission to the Administrator provided for or required
under this subpart.
(ii) An alternate authorized account representative of a general
account may delegate, to one or more natural persons, his or her
authority to make an electronic submission to the Administrator
provided for or required under this subpart.
(iii) In order to delegate authority to a natural person to make an
electronic submission to the Administrator in accordance with paragraph
(c)(5)(i) or (ii) of this section, the authorized account
representative or alternate authorized account representative, as
appropriate, must submit to the Administrator a notice of delegation,
in a format prescribed by the Administrator, that includes the
following elements:
(A) The name, address, email address, telephone number, and
facsimile transmission number (if any) of such authorized account
representative or alternate authorized account representative;
(B) The name, address, email address, telephone number, and
facsimile transmission number (if any) of each such natural person
(referred to in this section as an ``agent'');
(C) For each such natural person, a list of the type or types of
electronic submissions under paragraph (c)(5)(i) or (ii) of this
section for which authority is delegated to him or her;
(D) The following certification statement by such authorized
account representative or alternate authorized account representative:
``I agree that any electronic submission to the Administrator that is
made by an agent identified in this notice of delegation and of a type
listed for such agent in this notice of delegation and that is made
when I am an authorized account representative or alternate authorized
representative, as appropriate, and before this notice of delegation is
superseded by another notice of delegation under Sec.
62.16515(c)(5)(iv) shall be deemed to be an electronic submission by
me''; and
(E) The following certification statement by such authorized
account representative or alternate authorized account representative:
``Until this notice of delegation is superseded by another notice of
delegation under Sec. 62.16515(c)(5)(iv), I agree to maintain an email
account and to notify the Administrator immediately of any change in my
email address unless all delegation of authority by me under Sec.
62.16515(c)(5) is terminated.''
(iv) A notice of delegation submitted under paragraph (c)(5)(iii)
of this section shall be effective, with regard to the authorized
account representative or alternate authorized account representative
identified in such notice, upon receipt of such notice by the
Administrator and until receipt by the Administrator of a superseding
notice of delegation submitted by such authorized account
representative or alternate authorized account representative, as
appropriate. The superseding notice of delegation may replace any
previously identified agent, add a new agent, or eliminate entirely any
delegation of authority.
[[Page 65106]]
(v) Any electronic submission covered by the certification in
paragraph (c)(5)(iii)(D) of this section and made in accordance with a
notice of delegation effective under paragraph (c)(5)(iv) of this
section shall be deemed to be an electronic submission by the
authorized account representative or alternate authorized account
representative submitting such notice of delegation.
(6) Closing a general account. (i) The authorized account
representative or alternate authorized account representative of a
general account may submit to the Administrator a request to close the
account. Such request must include a correctly submitted ERC transfer
under Sec. 62.16525 for any ERCs in the account to one or more other
ATCS accounts.
(ii) If a general account has no ERC transfers to or from the
account for a 12-month period or longer and does not contain any ERCs,
then the Administrator may notify the authorized account representative
for the account that the account will be closed 30 days after the
notice is sent. The account will be closed after the 30-day period
unless, before the end of the 30-day period, the Administrator receives
a correctly submitted ERC transfer under Sec. 62.16525 to the account
or a statement submitted by the authorized account representative or
alternate authorized account representative demonstrating to the
satisfaction of the Administrator good cause as to why the account
should not be closed.
(d) Account identification. The Administrator will assign a unique
identifying number to each account established under paragraphs (a)
through (c) of this section.
(e) Responsibilities of authorized account representative and
alternate authorized account representative. After the establishment of
a compliance account or general account, the Administrator will accept
or act on a submission pertaining to the account, including, but not
limited to, submissions concerning the deduction or transfer of ERCs in
the account, only if the submission has been made, signed, and
certified in accordance with Sec. 62.16490(a) and Sec. 62.16510 or
paragraphs (c)(2)(ii) and (5) of this section.
(f) ERC identification information. The Administrator will assign
to each ERC issued in the EPA ERC tracking system a unique serial
identifier that begins with the two digit postal abbreviation of the
State in which it was issued and includes the year it was issued, and
the eligible resource category that generated it.
(g) Records supporting ERC issuance. The Administrator will
maintain in the EPA ERC tracking system records of, for each ERC, all
of the following:
(1) Account holder names and information;
(2) Authorized account representative name and information;
(3) Qualifying eligible resource identification number, name,
State, and contact information including street address, mailing
address, phone number, and email;
(4) Category of qualifying eligible resource, according to the
categories specified in Sec. 62.16435(a)(4);
(5) The date the qualifying eligible resource commenced generation
or saving of energy;
(6) Individual ERCs, each with a unique serial identifier that
meets the requirements of paragraph (f) of this section;
(7) Records of ERC transfers among accounts, including the date of
transfer and the accounts involved in the transfer;
(8) The date an ERC was surrendered for a compliance demonstration;
(9) Date an ERC was retired by the regulatory body; and
(10) Each eligibility application, EM&V plan, M&V report, and
verification report associated with the issuance of each specific ERC,
and each regulatory approval and any documentation that supports the
issuance of each ERC by the Administrator.
(h) Access to records supporting ERC issuance. The Administrator
will provide in the EPA ERC tracking system access and functionality to
allow each ERC to be traceable by the public to the records listed in
paragraph (g) of this section. This information will be accessible via
an electronic, internet-based portal in the ERC tracking system
searchable by, at a minimum, each eligible resource, affected EGU,
eligible resource category, and ERC.
(i) Reports. The Administrator will provide in the EPA ERC tracking
system electronic, internet-based access to enable the generation of at
least the following reports, [for as long as this regulation is
effective] [in perpetuity]:
(1) Account activity reports. By each account holder, reports based
on records of their account activity, including the information listed
in paragraph (g) of this section;
(2) Public reports. By the public, reports that include: All of the
information listed in paragraph (g) of this section; a list of all
registered account holders in the ERC tracking system, including
compliance accounts and general accounts; a list of all eligible
resources (including access to all documentation for such eligible
resources); a list of all accredited independent verifiers; and
aggregate ERC activity statistics on at least an annual basis, for at
least the following: Issuance of ERCs, transfers among accounts,
transfers in or out of the ERC tracking system to/from another approved
ERC tracking system (if relevant), and ERC retirements. The ERC
tracking system shall provide this functionality for as long as this
regulation is effective; and
(3) EPA reports. For the EPA and state regulators, the information
listed in paragraph (g) of this section and any other information
regarding ERC issuance, transfer, surrender, and retirement for purpose
of compliance with this regulation.
(j) Interactions with other ERC tracking systems. If approved in
connection with a State plan, then an ERC tracking system may provide
for transfers of ERCs to/from another ERC tracking system approved in
connection with a State plan by the EPA, or provide for transfers of
ERCs to/from an EPA-administered ERC tracking system used to administer
a federal plan. To transfer ERCs to or from an EPA-administered ERC
tracking system, the state ERC tracking system must be approved under
subpart UUUU of part 60 of this chapter for such use by the EPA.
Sec. 62.16525 How must transfers of ERCs be submitted?
(a) An authorized account representative seeking recordation of an
ERC transfer must submit the transfer to the Administrator.
(b) An ERC transfer is 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 ERC 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 ERC identified by serial number in the
transfer.
Sec. 62.16530 When will ERC transfers be recorded?
(a) Except as provided in paragraph (b) of this section, within
five business days of receiving an ERC transfer that is correctly
submitted under Sec. 62.16525,
[[Page 65107]]
the Administrator will record an ERC transfer by moving each ERC from
the transferor account to the transferee account as specified in the
transfer.
(b) An ERC transfer to or from a compliance account that is
submitted for recordation after the allowance transfer deadline for a
compliance period and that includes any ERCs allocated for any
compliance period before such allowance transfer deadline will not be
recorded until after the Administrator completes the deductions from
such compliance account under Sec. 62.16535 for the compliance period
immediately before such allowance transfer deadline.
(c) Where an ERC transfer is not correctly submitted under Sec.
62.16525, the Administrator will not record such transfer.
(d) Within five business days of recordation of an ERC 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 an ERC transfer that is
not correctly submitted under Sec. 62.16525, 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. 62.16535 How will deductions for compliance with a CO2 emission
standard occur?
For affected EGUs subject to the emission standards listed in Table
1 of this subpart, the owner or operator of an affected EGU must
demonstrate compliance with its CO2 emission standard in
accordance with Sec. 62.16420(c) and incorporate ERCs as listed in
paragraphs (a) through (f) of this section.
(a) Availability for deduction for compliance. ERCs are available
to be deducted from a compliance account and used for compliance with
an affected EGU's CO2 emissions standard for a compliance
period only if the ERCs:
(1) Were allocated for a year in such compliance period or a prior
compliance period; and
(2) Are held in the affected EGU's compliance account as of the
allowance transfer deadline for such compliance period.
(b) Deductions for compliance. After the recordation, in accordance
with Sec. 62.16530, of ERC transfers submitted by the ERC transfer
deadline for a compliance period, the Administrator will deduct from
each affected EGU's compliance account ERCs available under paragraph
(a) of this section in order to determine whether the affected EGU
meets the CO2 emission standard for such compliance period,
as follows:
(1) Until the amount of ERCs deducted and subsequently added to the
total MWh generated by the affected EGU adjusts the affected EGU's
CO2 emission rate to equal the CO2 emission
standard for such compliance period; or
(2) If there are insufficient ERCs to complete the deductions in
paragraph (b)(1) of this section, until no more ERCs available under
paragraph (a) of this section remain in the compliance account.
(c) Identification of ERCs by serial number. The authorized account
representative for an affected EGU's compliance account may request
that specific ERCs, identified by serial number, in the compliance
account be deducted for emissions or excess emissions for a compliance
period in accordance with paragraph (b) or (e) of this section. In
order to be complete, such request must be submitted to the
Administrator by the ERC transfer deadline for such compliance period
and include, in a format prescribed by the Administrator, the
identification of the affected EGU and the appropriate serial numbers.
(d) First-in, first-out. The Administrator will deduct ERCs under
paragraph (b) or (e) of this section from the affected EGU'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 ERCs in such request, on a
first-in, first-out accounting basis.
(e) Deductions for exceeding the emission standard. After making
the deductions for compliance under paragraph (b) of this section for a
compliance period in a year in which the affected EGU has exceeded its
CO2 emission standard, the Administrator will deduct from
the affected EGU's compliance account an amount of ERCs, allocated for
a compliance period in a prior year or the compliance period in the
year of the excess emissions or in the immediately following year,
equal to two times the number of ERCs of the affected EGU's excess
emissions.
(f) Recordation of deductions. The Administrator will record in the
appropriate compliance account all deductions from such an account
under paragraphs (b) and (e) of this section.
Sec. 62.16540 What monitoring requirements must I comply with?
(a) You must follow the requirements described in paragraphs (a)(1)
through (8) of this section to monitor emissions and net energy output
at your affected EGU.
(1) The owner of operator of an affected EGU required to meet an
emission standard must prepare a monitoring plan in accordance with the
applicable provisions in Sec. 75.53(g) and (h) of this chapter, unless
such a plan is already in place under another program that requires
CO2 mass emissions to be monitored and reported according to
part 75 of this chapter.
(2) Each compliance period shall include only ``valid operating
hours'' in the compliance period, i.e., operating hours for which:
(i) ``Valid data'' (as defined in Sec. 62.16570) are obtained for
all of the parameters used to determine the hourly CO2 mass
emissions (lbs). For the purposes of this subpart, substitute data
recorded under part 75 of this chapter are not considered to be valid
data; and
(ii) The corresponding hourly net energy output value is also valid
data (Note: for hours with no useful output, zero is considered to be a
valid value).
(3) The owner or operator of an affected EGU must measure and
report the hourly CO2 mass emissions (lbs) from each
affected unit using the procedures in paragraphs (a)(3)(i) through
(vii) of this section, except as provided in paragraph (a)(4) of this
section.
(i) The owner or operator of an affected EGU must install, certify,
operate, maintain, and calibrate a CO2 continuous emissions
monitoring system (CEMS) to directly measure and record CO2
concentrations in the affected EGU exhaust gases emitted to the
atmosphere and an exhaust gas flow rate monitoring system according to
Sec. 75.10(a)(3)(i) of this chapter. As an alternative to direct
measurement of CO2 concentration, the owner or operator of
an affected EGU may use data from a certified oxygen (O2)
monitor to calculate hourly average CO2 concentrations, in
accordance with Sec. 75.10(a)(3)(iii) of this chapter. If
CO2 concentration is measured on a dry basis, then you must
also install, certify, operate, maintain, and calibrate a continuous
moisture monitoring system, according to Sec. 75.11(b) of this
chapter. Alternatively, you may either use an appropriate fuel-specific
default moisture value from Sec. 75.11(b) or submit a petition to the
Administrator under Sec. 75.66 of this chapter for a site-specific
default moisture value.
[[Page 65108]]
(ii) For each ``valid operating hour'', calculate the hourly
CO2 mass emission rate (tons/hr), either from Equation F-11
in Appendix F to part 75 of this chapter (if CO2
concentration is measured on a wet basis), or by following the
procedure in section 4.2 of Appendix F to part 75 of this chapter (if
CO2 concentration is measured on a dry basis).
(iii) Next, multiply each hourly CO2 mass emission rate
by the affected EGU or stack operating time in hours (as defined in
Sec. 72.2 of this chapter), to convert it to tons of CO2.
Multiply the result by 2000 lb/ton to convert it to lb.
(iv) The hourly CO2 tons/hr values and affected EGU (or
stack) operating times used to calculate CO2 mass emissions
are required to be recorded under Sec. 75.57(e) of this chapter and
must be reported electronically under Sec. 75.64(a)(6). You must use
these data to calculate the hourly CO2 mass emissions.
(v) Sum all of the hourly CO2 mass emissions values that
were calculated according to procedures specified in paragraph
(a)(3)(ii) of this section over the entire compliance period.
(vi) For each continuous monitoring system used to determine the
CO2 mass emissions from an affected EGU, the monitoring
system must meet the applicable certification and quality assurance
procedures in Sec. 75.20 of this chapter and Appendices A and B to
part 75 of this chapter.
(vii) The owner operator of an affected EGU must use only
unadjusted exhaust gas volumetric flow rates to determine the hourly
CO2 mass emissions from the affected EGU; the owner or
operator of an affected EGU must not apply the bias adjustment factors
described in section 7.6.5 of Appendix A to part 75 of this chapter to
the exhaust gas flow rate data.
(4) The owner or operator of an affected EGU that exclusively
combusts liquid fuel and/or gaseous fuel may, as an alternative to
complying with paragraph (a)(3) of this section, determine the hourly
CO2 mass emissions according to paragraphs (a)(4)(i) through
(vi) of this section.
(i) Implement the applicable procedures in appendix D to part 75 of
this chapter to determine hourly affected EGU heat input rates (MMBtu/
h), based on hourly measurements of fuel flow rate and periodic
determinations of the gross calorific value (GCV) of each fuel
combusted.
(ii) For each measured hourly heat input rate, use Equation G-4 in
Appendix G to part 75 of this chapter to calculate the hourly
CO2 mass emission rate (tons/hr).
(iii) For each valid operating hour (as defined in paragraph (a)(2)
of this section, determine the hourly CO2 mass emission rate
(tons/hr) using the procedures specified in paragraph (a)(4)(ii) of
this section and multiply it by the affected EGU or stack operating
time in hours (as defined in Sec. 72.2 of this chapter), to convert to
tons of CO2. Then, multiply the result by 2000 lb/ton to
convert to lb.
(iv) The hourly CO2 tons/hr values and affected EGU (or
stack) operating times used to calculate CO2 mass emissions
are required to be recorded under Sec. 75.57(e) of this chapter and
must be reported electronically under Sec. 75.64(a)(6). You must use
these data to calculate the hourly CO2 mass emissions.
(v) Sum all of the hourly CO2 mass emissions values that
were calculated according to procedures specified in paragraph
(a)(4)(iii) of this section over the entire compliance period.
(vi) The owner or operator of an affected EGU may determine site-
specific carbon-based F-factors (Fc) using Equation F-7b in
section 3.3.6 of appendix F to part 75 of this chapter, and may use
these Fc values in the emissions calculations instead of
using the default Fc values in the Equation G-4
nomenclature.
(5) The owner or operator of an affected EGU must install,
calibrate, maintain, and operate a sufficient number of watt meters to
continuously measure and record on an hourly basis net electric output.
Measurements must be performed using 0.2 accuracy class electricity
metering instrumentation and calibration procedures as specified under
ANSI Standards No. C12.20. Further, the owner or operator of an
affected EGU that is a combined heat and power facility must install,
calibrate, maintain and operate equipment to continuously measure and
record on an hourly basis useful thermal output and, if applicable,
mechanical output, which are used with net electric output to determine
net energy output. The owner or operator must calculate net energy
output according to paragraph (a)(5)(i) of this section.
(i) For each valid operating hour of a compliance period that was
used in paragraph (a)(3) or (4) of this section to calculate the total
CO2 mass emissions, you must determine Pnet (the
corresponding hourly net energy output in MWh) according to the
procedures in paragraphs (a)(5)(i)(A) and (B) of this section, as
appropriate for the type of affected EGU(s). For an operating hour in
which a valid CO2 mass emissions value is determined
according to paragraph (a)(3) or (4) of this section, if there is no
gross or net electrical output, but there is mechanical or useful
thermal output, then you must still determine the net energy output for
that hour. In addition, for an operating hour in which a valid
CO2 mass emissions value is determined according to
paragraph (a)(3) or (4) of this section, but there is no (i.e., zero)
gross electrical, mechanical, or useful thermal output, you must use
that hour in the compliance determination. For hours or partial hours
where the gross electric output is equal to or less than the auxiliary
loads, net electric output shall be counted as zero for this
calculation.
(A) Calculate Pnet for your affected EGU using the
following equation. All terms in the equation must be expressed in
units of megawatt-hours (MWh). To convert each hourly net energy output
value reported under part 75 of this chapter to MWh, multiply by the
corresponding EGU or stack operating time.
[GRAPHIC] [TIFF OMITTED] TP23OC15.014
Where:
Pnet = Net energy output of your affected EGU for each
valid operating hour (as defined in paragraph (a)(2) of this
section) in MWh.
(Pe)ST = Electric energy output plus mechanical energy
output (if any) of steam turbines in MWh.
(Pe)CT = Electric energy output plus mechanical energy
output (if any) of stationary combustion turbine(s) in MWh.
(Pe)IE = Electric energy output plus mechanical energy
output (if any) of your affected EGU's integrated equipment that
provides electricity or mechanical energy to the affected EGU or
auxiliary equipment in MWh.
(Pe)A = Electric energy used for any auxiliary loads in
MWh.
(Pt)PS = Useful thermal output of steam (measured
relative to SATP conditions as defined in Sec. 62.16570, as
applicable) that is used for applications that do not
[[Page 65109]]
generate additional electricity, produce mechanical energy output,
or enhance the performance of the affected EGU. This is calculated
using the equation specified in paragraph (a)(5)(i)(B) of this
section in MWh.
(Pt)HR = Non steam useful thermal output (measured
relative to SATP conditions as defined in Sec. 62.16570, as
applicable) from heat recovery that is used for applications other
than steam generation or performance enhancement of the affected EGU
in MWh.
(Pt)IE = Useful thermal output (relative to SATP
conditions, as applicable as defined in Sec. 62.16570) from any
integrated equipment is used for applications that do not generate
additional steam, electricity, produce mechanical energy output, or
enhance the performance of the affected EGU in MWh.
TDF = Electric Transmission and Distribution Factor of 0.95 for a
combined heat and power affected EGU where at least on an annual
basis 20.0 percent of the total net energy output consists of
electric or direct mechanical output and 20.0 percent of the total
net energy output consists of useful thermal output on a 12-
operating month rolling average basis, or 1.0 for all other affected
EGUs.
(B) If applicable to your affected EGU (for example, for combined
heat and power), then you must calculate (Pt)PS using the
following equation:
[GRAPHIC] [TIFF OMITTED] TP23OC15.015
Where:
(Pt)ps = Useful thermal output of steam (measured
relative to SATP conditions as defined in Sec. 62.16570, as
applicable) that is used for applications that do not generate
additional electricity, produce mechanical energy output, or enhance
the performance of the affected EGU.
Qm = Measured steam flow in kilograms (kg) (or pounds
(lb)) for the operating hour.
H = Enthalpy of the steam at measured temperature and pressure
(relative to SATP conditions as defined in Sec. 62.16570 or the
energy in the condensate return line, as applicable) in Joules per
kilogram (J/kg) (or Btu/lb).
CF = Conversion factor of 3.6 x 10 \9\ J/MWh or 3.413 x 10 \6\ Btu/
MWh.
(C) Sum all of the values of Pnet over the entire
compliance period. Then, divide the total CO2 mass emissions
from paragraph (a)(3)(v) or (a)(4)(v) of this section, as applicable,
by the sum of the Pnet values to determine the
CO2 emission rate (lb/net MWh) for the compliance period.
(ii) [Reserved]
(6) In accordance with Sec. 60.13(g) of this chapter, if two or
more affected EGUs implementing the continuous emissions monitoring
provisions in paragraph (a)(2) of this section share a common exhaust
gas stack and are subject to the same emission standard, then the owner
or operator may monitor the hourly CO2 mass emissions at the
common stack in lieu of monitoring each EGU separately. If an owner or
operator of an affected EGU chooses this option, then the hourly net
electric output for the common stack must be the sum of the hourly net
electric output of the individual affected EGUs and the operating time
must be expressed as ``stack operating hours'' (as defined in Sec.
72.2 of this chapter).
(7) In accordance with Sec. 60.13(g) of this chapter, if the
exhaust gases from an affected EGU implementing the continuous
emissions monitoring provisions in paragraph (a)(3)(i) of this section
are emitted to the atmosphere through multiple stacks (or if the
exhaust gases are routed to a common stack through multiple ducts and
you elect to monitor in the ducts), then the hourly CO2 mass
emissions and the ``stack operating time'' (as defined in Sec. 72.2 of
this chapter) at each stack or duct must be monitored separately. In
this case, the owner or operator of an affected EGU must determine
compliance with an applicable emission standard by summing the
CO2 mass emissions measured at the individual stacks or
ducts and dividing by the net energy output for the affected EGU.
(8) If two or more affected EGUs serve a common electric generator,
then you must apportion the combined hourly net energy output to the
individual affected EGUs according to the fraction of the total steam
load contributed by each EGU. Alternatively, if the affected EGUs are
identical, then you may apportion the combined hourly net electrical
load to the individual EGUs according to the fraction of the total heat
input contributed by each EGU.
(b) [Reserved]
Sec. 62.16545 May I bank CO2 ERCs for future use or transfer?
(a) An ERC 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 ERC that is held in a compliance account or a general
account will remain in such account unless and until the ERC is
deducted or transferred under Sec. Sec. 62.16530, 62.16535, 62.16550,
or 62.16565.
Sec. 62.16550 How does the Administrator process account errors?
The Administrator may, at his or her sole discretion and on his or
her own motion, correct any error in any ATCS account. Within 10
business days of making such correction, the Administrator will notify
the authorized account representative for the account.
Sec. 62.16555 What are my reporting, notification and submission
requirements?
You must prepare and submit reports according to paragraphs (a)
through (g) of this section, as applicable.
(a)(1) You must meet all applicable reporting requirements and
submit reports as required under subpart G of part 75 of this chapter
and you must include the following information, as applicable in the
quarterly reports:
(i) The percentage of valid operating hours in each quarter
described Sec. 62.16540(a)(2) (i.e., the total number of valid
operating hours) in that period divided by the total number of
operating hours in that period, multiplied by 100 percent);
(ii) The hourly CO2 mass emission rate values (tons/hr)
and unit (or stack) operating times, (as monitored and reported
according to part 75 of this chapter), for each valid operating hour in
the compliance period;
(iii) The net electric output and the net energy output
(Pnet) values for each valid operating hour in the
compliance period;
(iv) The calculated CO2 mass emissions (lb) for each
valid operating hour in the compliance period;
(v) The sum of the hourly net energy output values and the sum of
the hourly CO2 mass emissions values, for all of the valid
operating hours in the compliance period;
(vi) ERC replacement generation (if any), properly justified (see
paragraph (a)(1)(viii) of this section);
(vii) The calculated CO2 mass emission rate for the
compliance period (lb/net MWh); and
(viii) If the report covers the final quarter of a compliance
period, then you must include the CO2 emission standard (as
identified in Table 1 of this subpart) with which your affected EGU
must comply, your CO2 emission rate calculated according to
Sec. 62.16420(c), and if an affected EGU is complying with an emission
standard by using ERCs, then the designated representative must also
include in the report a list of all unique ERC serial numbers retired
in the compliance period, and, for each ERC, the date an ERC was
surrendered and retired and eligible resource identification
information sufficient to demonstrates that it meets the requirements
of Sec. 62.16435 and qualifies to be issued ERCs (including location,
type of qualifying generation or savings, date commenced generating or
saving, and date of generation or savings for which the ERC was
issued).
[[Page 65110]]
(b) If any required monitoring system has not been provisionally
certified by the applicable date on which emissions data reporting is
required to begin under paragraph (a) of this section, then the maximum
(or in some cases, minimum) potential value for the parameter measured
by the monitoring system shall be reported until the required
certification testing is successfully completed, in accordance with
Sec. 75.4(j) of this chapter, Sec. 75.37(b) of this chapter, or
section 2.4 of appendix D to part 75 of this chapter (as applicable).
Operating hours in which CO2 mass emission rates are
calculated using maximum potential values are not ``valid operating
hours'' (as defined in Sec. 62.16540(a)), and shall not be used in the
compliance determinations.
(c) The designated representative of each affected EGU at the
facility must make all submissions required under the CO2
Rate-based Trading Program, except as provided in Sec. 62.16510. 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.
(d) You must submit all electronic reports required under paragraph
(a) of this section using the Emissions Collection and Monitoring Plan
System (ECMPS) Client Tool provided by the Clean Air Markets Division
in the Office of Atmospheric Programs of EPA.
(e) For affected EGUs under this subpart that are not in the Acid
Rain Program, you must also meet the reporting requirements and submit
reports as required under subpart G of part 75 of this chapter, to the
extent that those requirements and reports provide applicable data for
the compliance demonstrations required under this subpart.
(f) If your affected EGU captures CO2 to meet the
applicable emission standard, then you must report in accordance with
the requirements of part 98, subpart PP, of this chapter and either:
(1) Report in accordance with the requirements of part 98, subpart
RR, of this chapter, if injection occurs on-site; or
(2) Transfer the captured CO2 to an affected EGU or
facility that reports in accordance with the requirements of part 98,
subpart RR, of this chapter, if injection occurs off-site.
(g) You must prepare and submit notifications specified in Sec.
75.61 of this chapter, as applicable to your affected EGUs.
Sec. 62.16560 What are my recordkeeping requirements?
(a) The owner or operator of each affected EGU must maintain the
records, as described in paragraph (a)(1) of this section, for at least
5 years following the date of each compliance period, occurrence,
measurement, maintenance, corrective action, report, or record.
(1) Unless otherwise provided, the owner or operator of an affected
EGU must maintain the following records on site for at least 2 years
after the date of each compliance period, compliance true-up period,
occurrence, measurement, maintenance, corrective action, report, or
record, whichever is latest, according to Sec. 60.7 of this chapter.
The owner or operator of an affected EGU may maintain the records off
site and electronically for the remaining year(s). 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. 62.16500 for the
designated representative for each affected EGU and all documents that
demonstrate the truth of the statements in the certificate of
representation; provided that the certificate and documents must be
retained on site at the affected EGU beyond such 5-year period until
such certificate of representation and documents are superseded because
of the submission of a new certificate of representation under Sec.
62.16500 changing the designated representative.
(ii) All emissions monitoring information, in accordance with this
subpart.
(iii) Copies of all reports, compliance certifications, documents,
data files, calculations and methods, other submissions and all records
made or required under, or to demonstrate compliance with an affected
EGU's emission standard under Sec. 62.16420 and any other requirements
of the CO2 Rate-based Trading Program.
(iv) Data that are required to be recorded by part 75, subpart F,
of this chapter.
(v) Data with respect to any ERCs generated by the affected EGU or
used by the affected EGU in its compliance demonstration including the
information in paragraphs (a)(1)(v)(A) and (B) of this section.
(A) All documents related to any ERCs used in a compliance
demonstration, including each eligibility application, EM&V plan, M&V
report, and independent verifier verification report associated with
the issuance of each specific ERC, and each regulatory approval and any
documentation that supports the issuance of each ERC by the
Administrator.
(B) All records and reports relating to the surrender and
retirement of ERCs for compliance with this regulation, including the
date each individual ERC with a unique serial identification number was
surrendered and/or retired.
(2) [Reserved]
(b) [Reserved]
Sec. 62.16565 What actions may the Administrator take on submissions?
(a) The Administrator may review and conduct independent audits
concerning any submission under the CO2 Rate-based Trading
Program and make appropriate adjustments of the information in the
submission.
(b) The Administrator may deduct ERCs from or transfer ERCs to a
compliance account, based on the information in a submission, as
adjusted under paragraph (a) of this section, and record such
deductions and transfers.
Definitions
Sec. 62.16570 What definitions apply to this subpart?
The terms used in this subpart 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 his or her delegate, or the
authorized state official under an approved state plan that
incorporates this subpart.
Affected electric generating unit or Affected EGU means any steam
generating unit, IGCC, or stationary combustion turbine that meets the
applicability requirements in Sec. Sec. 60.5840(b) and 60.5845 of this
chapter. An affected EGU is not an eligible resource.
Allowable CO2 emission rate means, for an affected EGU,
the most stringent State or federal CO2 emission rate limit
(in lb/MWh or, if in lb/mmBtu, converted to lb/MWh by multiplying it by
the affected EGU's heat rate in mmBtu/MWh) that is applicable to the
affected EGU and covers the longest averaging period not exceeding 1
year.
Allowance system means a control program under which the owner or
operator of each affected EGU is required to hold an authorization for
each specified unit of carbon dioxide emitted from that facility during
a specified period and which limits the total amount of such
authorizations
[[Page 65111]]
available to be held for carbon dioxide for a specified period and
allows the transfer of such authorizations not used to meet the
authorization-holding requirement.
Allowance Tracking and Compliance System (ATCS) means the system by
which the Administrator records allocations, deductions, and transfers
of ERCs under the CO2 Rate-based Trading Program. Such
allowances are allocated, recorded, held, deducted, or transferred only
as whole ERCs.
Alternate designated representative means, for a CO2
Rate-based Trading affected EGU and each affected EGU at the facility,
the natural person who is authorized by the owners and operators of the
affected EGU and all such affected EGUs at the affected EGU, in
accordance with this subpart, to act on behalf of the designated
representative in matters pertaining to the CO2 Rate-based
Trading Program. If the affected EGU is also subject to the Acid Rain
Program, TR NOX Annual Trading Program, TR NOX
Ozone Season Trading Program, TR SO2 Group 1 Trading
Program, or TR SO2 Group 2 Trading Program, then this
natural person shall be the same natural person as the alternate
designated representative, as defined in the respective program.
Annual capacity factor means the ratio between the actual heat
input to an EGU during a calendar year and the potential heat input to
the EGU had it been operated for 8,760 hours during a calendar year at
the base load rating. Also see capacity factor.
Authorized account representative means, for a general account, the
natural person who is authorized, in accordance with this subpart, to
transfer and otherwise dispose of ERCs held in the general account and,
for a CO2 Rate-based Trading Program affected EGU's, the
designated representative of the affected EGU is the authorized account
representative.
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.
Base load rating means the maximum amount of heat input (fuel) that
an EGU can combust on a steady state basis, as determined by the
physical design and characteristics of the EGU at ISO conditions. For a
stationary combustion turbine, base load rating includes the heat input
from duct burners.
Baseline means the electricity use that would have occurred without
implementation of a specific EE measure.
Biomass means biologically based material that is living or dead
(e.g., trees, crops, grasses, tree litter, roots) above and
belowground, and available on a renewable or recurring basis. Materials
that are biologically based include non-fossilized, biodegradable
organic material originating from modern or contemporarily grown
plants, animals, or microorganisms (including plants, products,
byproducts and residues from agriculture, forestry, and related
activities and industries, as well as the non-fossilized and
biodegradable organic fractions of industrial and municipal wastes,
including gases and liquids recovered from the decomposition of non-
fossilized and biodegradable organic material).
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.
Business day means a day that does not fall on a weekend or a
federal holiday.
Capacity factor means, as used for the output based set-aside, the
ratio of the net electrical energy produced by a generating unit for
the period of time considered to the electrical energy that could have
been produced at continuous net summer capacity during the same period.
Certifying official means a natural person who is:
(1) For a corporation, a president, secretary, treasurer, or vice-
president of the corporation in charge of a principal business function
or any other person who performs similar policy- or decision-making
functions for the corporation;
(2) For a partnership or sole proprietorship, a general partner or
the proprietor respectively; or
(3) For a local government entity or State, federal, or other
public agency, a principal executive officer or ranking elected
official.
Clean Air Act means the Clean Air Act, 42 U.S.C. 7401, et seq.
CO2 emissions limitation means the tonnage of
CO2 emissions authorized in a compliance period in a given
year by the CO2 allowances available for deduction for the
affected EGU under Sec. 62.16535(a) for such compliance period.
CO2 Rate-Based Trading Program means a multi-state
CO2 air pollution control and emission reduction program
established in accordance with this subpart and subpart UUUU of part 60
of this chapter (including such a program that is revised in a State
plan or state allowance distribution methodology, or by the
Administrator under subpart UUUU of part 60 of this chapter), as a
means of controlling CO2 emissions.
Coal means the definition as defined in subpart TTTT of part 60 of
this chapter.
Combined cycle unit means an electric generating unit that uses a
stationary combustion turbine from which the heat from the turbine
exhaust gases is recovered by a heat recovery steam generating unit to
generate additional electricity.
Combined heat and power unit or CHP unit, (also known as
``cogeneration'') means an electric generating unit that uses a steam-
generating unit or stationary combustion turbine to simultaneously
produce both electric (or mechanical) and useful thermal output from
the same primary energy affected EGU.
Common practice baseline or CPB means a baseline derived based on a
default technology or condition that would have been in place at the
time of implementation of an EE measure in the absence of the EE
measure (for example, the standard or market-average or pre-existing
equipment that a typical consumer/building owner would have continued
to use or would have installed at the time of project implementation in
a given circumstance, such as a given building type, EE program type or
delivery mechanism, and geographic region).
Common stack means a single flue through which emissions from two
or more units are exhausted.
Compliance account means an Allowance Transfer and Compliance
System account, established by the Administrator for an affected EGU
under this subpart, in which any ERC allocations to the affected EGUs
at the affected EGU are recorded and in which are held any
CO2 allowances available for use for a compliance period in
a given year in complying with the affected EGU's CO2
emission standard in accordance with Sec. Sec. 62.16420 and 62.16535.
Compliance period means the multi-year periods starting January 1
of the first calendar year of the period, except as provided in Sec.
62.16420(c)(3), and ending on December 31 of the last calendar year,
inclusive:
(1) Compliance Period 1 means the period of 3 calendar years from
January 1, 2022 to December 31, 2024;
[[Page 65112]]
(2) Compliance Period 2 means the period of 3 calendar years from
January 1, 2025 to December 31, 2027; and
(3) Compliance Period 3 means the period of 2 calendar years from
January 1, 2028 to December 31, 2029.
Conservation voltage regulation (or reduction) (CVR) means an EE
measure that produces electricity savings by reducing (or regulating)
voltage at the electrical feeder level.
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 CO2 emissions, stack gas volumetric flow rate,
stack gas moisture content, and O2 concentration (as
applicable), in a manner consistent with part 75 of this chapter and
Sec. 62.16540(a)(3). 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;
(2) 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;
(3) 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
(4) 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 area operator means an electric system or systems, bounded
by interconnection metering and telemetry, capable of controlling
generation to maintain its interchange schedule with other control
areas and contributing to frequency regulation of the interconnection.
Deemed savings means estimates of average annual electricity
savings for a single unit of an installed demand-side EE measure that:
has been developed from data sources (such as prior metering studies)
and analytical methods widely considered acceptable for the measure;
and is applicable to the situation and conditions in which the measure
is implemented. Individual parameters or calculation methods also can
be deemed, including EUL values. Common sources of deemed savings
values are previous evaluations and studies that involved actual
measurements and analyses. Deemed savings values are applicable for
specific demand-side EE measures. A single deemed savings value may not
be used for a program as a whole, nor for a multi-measure project,
because of the degree of variation in how systems are used in different
building types or market segments.
Demand-side energy efficiency or demand-side EE means an installed
piece of equipment or system, a modification of existing equipment or
system, or a strategy intended to affect consumer electricity-use
behavior, that results in a reduction in electricity use (in MWh) at an
end-use facility, premises, or equipment connected to the electricity
grid. Demand-side EE is implemented through energy efficiency
activities, projects, programs or measures
Derate means a decrease in the available capacity of an electric
generating unit, due to a system or equipment modification or to
discounting a portion of a generating unit's capacity for planning
purposes.
Designated representative means, for a CO2 Rate-based
Trading affected EGU and each affected EGU at the affected EGU, the
natural person who is authorized by the owners and operators of the
affected EGU and all such affected EGUs at the affected EGU, in
accordance with this subpart, to represent and legally bind each owner
and operator in matters pertaining to the CO2 Rate-based
Trading Program. If the CO2 Rate-based Trading affected EGU
is also subject to the Acid Rain Program, TR NOX Annual
Trading Program, TR NOX Ozone Season Trading Program, TR
SO2 Group 1 Trading Program, or TR SO2 Group 2
Trading Program, then this natural person shall be the same natural
person as the designated representative, as defined in the respective
program.
Design efficiency means the rated overall net efficiency (e.g.,
electric plus thermal output) on a higher heating value basis of the
EGU at the base load rating and ISO conditions.
Distillate oil means the definition as defined in subpart TTTT of
part 60 of this chapter.
Effective useful life (EUL) means the duration over which
electricity savings from an EE measure occur, reported in years. EUL
values are typically specific to individual EE projects but also may be
specified by an EE program.
Electricity savings means the savings that results from a change in
electricity use resulting from the implementation of demand-side EE.
Eligible resource means a resource that meets the requirements of
Sec. 62.16435 and has been registered with the EPA-administered ERC
tracking system or an ERC tracking system approved in a State plan by
the EPA. An eligible resource is not an affected EGU.
EM&V plan means an evaluation measurement and verification plan
that meets the requirements of Sec. 62.16455.
Emissions means air pollutants exhausted from an affected EGU into
the atmosphere; emissions must be measured, recorded, and reported to
the Administrator by the designated representative, and as modified by
the Administrator:
(1) In accordance with this subpart; and
(2) With regard to a period before the affected EGU or facility is
required to measure, record, and report such air pollutants in
accordance with this subpart, in accordance with part 75 of this
chapter.
Emission rate credit (ERC) means a tradable compliance instrument
that meets the requirements of Sec. 60.5790(c) of this chapter.
ERC deduction or deduct ERCs means the permanent withdrawal of ERCs
by the Administrator from a compliance account (e.g., in order to
account for compliance with the applicable CO2 emission
standard).
Energy efficiency program or EE program means organized activities
sponsored and funded by a particular entity to promote the adoption of
one or more EE project or EE measure for the purpose of reducing
electricity use.
Energy efficiency project or EE project means a combination of
multiple technologies, energy-use practices or behaviors implemented at
a single facility or premises for the purpose of reducing electricity
use; EE projects may be implemented as part of an EE program or as an
independent privately-funded action.
Energy efficiency measure or EE measure means a single technology,
energy-use practice or behavior that, once implemented or adopted,
reduces electricity use of a particular end-use, facility, or premises;
EE measures may be implemented as part of an EE program or as an
independent privately-funded action.
ERC held or hold ERCs means the ERCs treated as included in an ATCS
account as of a specified point in time because at that time they:
[[Page 65113]]
(1) Have been recorded by the Administrator in the account or
transferred into the account by a correctly submitted, but not yet
recorded, ERC transfer in accordance with this subpart; and
(2) Have not been transferred out of the account by a correctly
submitted, but not yet recorded, ERC transfer in accordance with this
subpart.
ERC transfer deadline means, for a compliance period in a given
year, 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 compliance period and is the deadline by
which an ERC transfer must be submitted for recordation in a affected
EGU's compliance account in order to be available for use in complying
with the affected EGU's CO2 emission standard for such
compliance period in accordance with Sec. Sec. 62.16420 and 62.16535.
Essential generating characteristics means any characteristic that
affects the eligibility of the qualifying energy generating resource
for generating ERCs pursuant to this regulation, including the type of
resource.
Excess emissions means any ton of emissions from the affected EGUs
at an affected EGU during a compliance period that exceeds the
CO2 emissions limitation for the affected EGU for such
compliance period.
Existing state program, requirement, or measure means, in the
context of a State plan, a regulation, requirement, program, or measure
administered by a state, utility, or other entity that is currently
established. This may include a regulation or other legal requirement
that includes past, current, and future obligations, or current
programs and measures that are in place and are anticipated to be
continued or expanded in the future, in accordance with established
plans. An existing state program, requirement, or measure may have
past, current, and future impacts on EGU CO2 emissions.
Facility 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.
Final compliance period means a compliance period within the final
period, each being 2 calendar years (with a calendar year beginning on
January 1 and ending on December 31), and the first final compliance
period beginning on January 1, 2030 and ending December 31, 2031.
Final period means the period that begins on January 1, 2030 and
continues thereafter. The final period is comprised of final compliance
periods, each of which is 2 calendar years (with a calendar year
beginning on January 1 and ending on December 31).
Fossil fuel means the definition as defined in subpart TTTT of part
60 of this chapter.
Fossil-fuel-fired means, with regard to an affected EGU, combusting
any amount of fossil fuel.
Gaseous fuel means the definition as defined in subpart TTTT of
part 60 of this chapter.
General account means an ATCS account established under this
subpart that is not a compliance account.
Generator means a device that produces electricity.
Gross electrical output means, for an affected EGU, 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
affected EGU and any on-site emission controls).
GS-ERC means an ERC issued for net energy output MWh of gas shift
to, but which may not be used for compliance by, an affected EGU that
is a stationary combustion turbine. Aside from this restriction on use
for compliance, GS-ERCs are subject to all other provisions of this
subpart related to ERCs.
Heat input means, for an affected EGU for a specified period of
time, the product (in mmBtu/time) of the gross calorific value of the
fuel (in mmBtu/lb) fed into the affected EGU multiplied by the fuel
feed rate (in lb of fuel/time), as measured, recorded, and reported to
the Administrator by the designated representative and as modified by
the Administrator in accordance with this subpart and excluding the
heat derived from preheated combustion air, recirculated flue gases, or
exhaust.
Heat input rate means, for an affected EGU, the amount of heat
input (in mmBtu) divided by affected EGU operating time (in hr) or, for
an affected EGU and a specific fuel, the amount of heat input
attributed to the fuel (in mmBtu) divided by the affected EGU operating
time (in hr) during which the affected EGU combusts the fuel.
Heat rate means, for an affected EGU, the affected EGU's maximum
design heat input (in Btu/hr), divided by the product of 1,000,000 Btu/
mmBtu and the affected EGU's maximum hourly load.
Heat recovery steam generating unit (HRSG) means a unit in which
hot exhaust gases from the combustion turbine engine are routed in
order to extract heat from the gases and generate useful output. Heat
recovery steam generating units can be used with or without duct
burners.
Indian country means ``Indian country'' as defined in 18 U.S.C.
1151.
Integrated gasification combined cycle facility or IGCC facility
means a combined cycle facility that is designed to burn fuels
containing 50 percent (by heat input) or more solid-derived fuel not
meeting the definition of natural gas plus any integrated equipment
that provides electricity or useful thermal output to either the
affected facility or auxiliary equipment. The Administrator may waive
the 50 percent solid-derived fuel requirement during periods of the
gasification system construction, startup and commissioning, shutdown,
or repair. No solid fuel is directly burned in the unit during
operation.
Interim period means the period of 8 calendar years from January 1,
2022 to December 31, 2029. The interim period is comprised of three
compliance periods, compliance period 1, compliance period 2, and
compliance period 3.
ISO conditions means 288 Kelvin (15 [deg]C), 60 percent relative
humidity and 101.3 kilopascals pressure.
Liquid fuel means the definition as defined in subpart TTTT of part
60 of this chapter.
M&V report means a monitoring and verification report that meets
the requirements of Sec. 62.16460.
Maximum design heat input means, for an affected EGU, the maximum
amount of fuel per hour (in Btu/hr) that the affected EGU is capable of
combusting on a steady state basis as of the initial installation of
the affected EGU as specified by the manufacturer of the affected EGU.
Mechanical output means the useful mechanical energy that is not
used to operate the affected facility, generate electricity and/or
thermal output, or to enhance the performance of the affected facility.
Mechanical energy measured in horsepower hour should be converted into
MWh by multiplying it by 745.7 then dividing by 1,000,000.
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
[[Page 65114]]
generating output (in MWe, rounded to the nearest tenth) that the
generator is capable of producing on a steady state basis and during
continuous operation (when not restricted by seasonal or other
deratings) of such installation as specified by the manufacturer of the
generator or, starting from the completion of any subsequent physical
change in the generator resulting in an increase in the maximum
electrical generating output that the generator is capable of producing
on a steady state basis and during continuous operation (when not
restricted by seasonal or other deratings), such increased maximum
amount (in MWe, rounded to the nearest tenth) of such completion as
specified by the person conducting the physical change.
Natural gas means the definition as defined in subpart TTTT of part
60 of this chapter.
Net-electric output means the amount of gross generation the
generator(s) produce (including, but not limited to, output from steam
turbine(s), combustion turbine(s), and gas expander(s)), as measured at
the generator terminals, less the electricity used to operate the plant
(i.e., auxiliary loads); such uses include fuel handling equipment,
pumps, fans, pollution control equipment, other electricity needs, and
transformer losses as measured at the transmission side of the step up
transformer (e.g., the point of sale).
Net energy output means:
(1) The net electric or mechanical output from the affected
facility, plus 100 percent of the useful thermal output measured
relative to SATP conditions that is not used to generate additional
electric or mechanical output or to enhance the performance of the
affected EGU (e.g., steam delivered to an industrial process for a
heating application); and
(2) For combined heat and power facilities where at least 20.0
percent of the total net energy output consists of electric or direct
mechanical output and at least 20.0 percent of the total net energy
output consists of useful thermal output on a 12-operating month
rolling average basis, the net electric or mechanical output from the
affected EGU divided by 0.95, plus 100 percent of the useful thermal
output (e.g., steam delivered to an industrial process for a heating
application).
Net summer capacity means the maximum output, commonly expressed in
megawatts (MW), that generating equipment can supply to system load, as
demonstrated by a multi-hour test, at the time of summer peak demand
(period of June 1 through September 30.) This output reflects a
reduction in capacity due to electricity use for station service or
auxiliaries.
Operate or operation means, with regard to an affected EGU, to
combust fuel.
Operator means, for a CO2 Rate-based Trading affected
EGU or an affected EGU at an affected EGU respectively, any person who
operates, controls, or supervises an affected EGU at the affected EGU
or the affected EGU and includes, but is not limited to, any holding
company, utility system, or plant manager of such affected EGU or
affected EGU.
Owner means, for a CO2 Rate-based Trading affected EGU
or an affected EGU at an affected EGU respectively, any of the
following persons:
(1) Any holder of any portion of the legal or equitable title in an
affected EGU at the affected EGU or the affected EGU;
(2) Any holder of a leasehold interest in an affected EGU at the
affected EGU or the affected EGU, 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 affected EGU; and
(3) Any purchaser of power from a affected EGU at the affected EGU
or the affected EGU under a life-of-the-unit, firm power contractual
arrangement.
Permanently retired means, with regard to an affected EGU, that an
affected EGU is unavailable for service and the affected EGU's owners
and operators: have taken on as enforceable obligations in the
operating permit that covers the affected EGU the conditions of Sec.
62.16415; or rescinded or otherwise terminated all permits required for
construction or operation of the affected EGU under the Clean Air Act.
Cessations in operations that do not meet this definition do not
constitute permanent retirements.
Petroleum means the definition as defined in subpart TTTT of part
60 of this chapter.
Qualified biomass means a biomass feedstock that is demonstrated to
qualify as a method to control increases of CO2 levels in
the atmosphere.
Random error means errors occurring by chance that may cause
electricity savings values to be inconsistently overestimated or
underestimated, and may result from a change in electricity use due to
unaccounted-for factors that affect electricity use. The magnitude of
random error can be quantified based on the variations observed across
different units.
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 ERCs, the
moving of ERCs by the Administrator into, out of, or between ATCS
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 an affected
EGU, the demolishing of an affected EGU, or the permanent retirement
and permanent disabling of an affected EGU, and the construction of
another affected EGU (the replacement affected EGU) to be used instead
of the demolished or retired affected EGU (the replaced affected EGU).
Solid fuel means the definition as defined in subpart TTTT of part
60 of this chapter.
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.
Standard ambient temperature and pressure (SATP) conditions means
298.15 Kelvin (25 [deg]C, 77 [deg]F) and 100.0 kilopascals (14.504 psi,
0.987 atm) pressure. The enthalpy of water at SATP conditions is 50
Btu/lb.
State agent means an entity acting on behalf of the State, with the
legal authority of the State.
State measures means measures that the State adopts and implements
as a matter of state law. Such measures are enforceable only per state
law, and are not included in and codified as part of the federally
enforceable State plan.
Stationary combustion turbine means all equipment, including but
not limited to the turbine engine, the fuel, air, lubrication and
exhaust gas systems, control systems (except emissions control
equipment), heat recovery system, fuel compressor, heater, and/or pump,
post-combustion emissions control technology, and any ancillary
components and sub-components comprising any simple cycle stationary
combustion turbine, any combined
[[Page 65115]]
cycle combustion turbine, and any combined heat and power combustion
turbine based system plus any integrated equipment that provides
electricity or useful thermal output to the combustion turbine engine,
heat recovery system or auxiliary equipment. Stationary means that the
combustion turbine is not self-propelled or intended to be propelled
while performing its function. It may, however, be mounted on a vehicle
for portability. If a stationary combustion turbine burns any solid
fuel directly then it is considered a steam generating unit.
Steam generating unit means any furnace, boiler, or other device
used for combusting fuel and producing steam (nuclear steam generators
are not included) plus any integrated equipment that provides
electricity or useful thermal output to the affected facility or
auxiliary equipment.
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.
Systematic error means inaccuracies in the same direction, causing
electricity savings values to be consistently either overestimated or
underestimated, and may result from factors such as incorrect
assumptions, a methodological issue, or a flawed reporting system.
Transmission and distribution loss means the difference between the
quantity of electricity that serves a load (measured at the busbar of
the generator) and the actual electricity use at the final distribution
location (measured at the on-site meter).
Transmission and distribution measures or T&D measures means EE
measures intended to improve the efficiency of the electrical
transmission and distribution system by decreasing electricity loses on
the system.
Unit operating day means, with regard to an affected EGU, a
calendar day in which the affected EGU combusts any fuel.
Unit operating hour or hour of unit operation means, with regard to
an affected EGU, an hour in which the affected EGU combusts any fuel.
Uprate means an increase in available electric generating unit
power capacity due to a system or equipment modification.
Useful thermal output means the thermal energy made available for
use in any heating application (e.g., steam delivered to an industrial
process for a heating application, including thermal cooling
applications) that is not used for electric generation, mechanical
output at the affected EGU, to directly enhance the performance of the
affected EGU (e.g., economizer output is not useful thermal output, but
thermal energy used to reduce fuel moisture is considered useful
thermal output), or to supply energy to a pollution control device at
the affected EGU. Useful thermal output for affected EGU(s) with no
condensate return (or other thermal energy input to the affected
EGU(s)) or where measuring the energy in the condensate (or other
thermal energy input to the affected EGU(s)) would not meaningfully
impact the emission rate calculation is measured against the energy in
the thermal output at SATP conditions. Affected EGU(s) with meaningful
energy in the condensate return (or other thermal energy input to the
affected EGU) must measure the energy in the condensate and subtract
that energy relative to SATP conditions from the measured thermal
output.
Utility power distribution system means the portion of an
electricity grid owned or operated by a utility and dedicated to
delivering electricity to customers.
Valid data means quality-assured data generated by continuous
monitoring systems that are installed, operated, and maintained
according to part 75 of this chapter. For CEMS, the initial
certification requirements in Sec. 75.20 of this chapter and appendix
A to part 75 of this chapter must be met before quality-assured data
are reported under this subpart; for on-going quality assurance, the
daily, quarterly, and semiannual/annual test requirements in sections
2.1, 2.2, and 2.3 of appendix B to part 75 of this chapter must be met
and the data validation criteria in sections 2.1.5, 2.2.3, and 2.3.2 of
appendix B to part 75 of this chapter apply. For fuel flow meters, the
initial certification requirements in section 2.1.5 of appendix D to
part 75 of this chapter must be met before quality-assured data are
reported under this subpart (except for qualifying commercial billing
meters under section 2.1.4.2 of appendix D), and for on-going quality
assurance, the provisions in section 2.1.6 of appendix D to part 75 of
this chapter apply (except for qualifying commercial billing meters).
Verification report means a report that meets the requirements of
Sec. 62.16465.
Waste-to-Energy means a process or unit (e.g., solid waste
incineration unit) that recovers energy from the conversion or
combustion of waste stream materials, such as municipal solid waste, to
generate electricity and/or heat.
Sec. 62.16575 What measurements, abbreviations, and acronyms apply to
this subpart?
The measurements, abbreviations, and acronyms used in this subpart
are defined as follows:
ADR--alternated designated representative
Btu--British thermal unit
CPP--clean power plan
CO2--carbon dioxide
COI--conflict of interest
CVR--conservative voltage regulation
DR--designated representative
EE--energy efficiency
EGU--electric generating unit
EM&V--evaluation, measurement, and verification
ERC--emission rate credit
GCV--gross calorific value
GJ--giga joule
H2O--water
hr--hour
IGCC--integrated gasification combined cycle
kg--kilogram
kW--kilowatt electrical
kWh--kilowatt hour
lb--pound
M&V--measurement and verification
mmBtu--million Btu
MWe--megawatt electrical
MWh--megawatt hour
T&D--transmission and distribution
O2--oxygen
PSD--prevention of significant deterioration
yr--year
[[Page 65116]]
Table 1 to Subpart NNN of Part 62--CO2 Emission Standards (Pounds of CO2
Per Net MWh)
------------------------------------------------------------------------
Affected steam
generating unit or
integrated Affected stationary
Compliance period gasification combustion turbine
combined cycle emission standard
(IGCC) emission
standards
------------------------------------------------------------------------
Compliance Period 1 (2022- 1,671 877
2024)......................
Compliance Period 2 (2025- 1,500 817
2027)......................
Compliance Period 3 (2028- 1,380 784
2029)......................
Final Compliance Periods.... 1,305 771
------------------------------------------------------------------------
Table 2 to Subpart NNN of Part 62--Incremental Generation Factor for
Emission Rate Credits (Dimensionless)
------------------------------------------------------------------------
Incremental
Compliance period Generation
Factor
------------------------------------------------------------------------
Compliance Period 1 (2022-2024)......................... .22
Compliance Period 2 (2025-2027)......................... .32
Compliance Period 3 (2028-2029)......................... .28
Final Compliance Periods................................ .26
------------------------------------------------------------------------
PART 78--APPEAL PROCEDURES
0
6. The authority citation for Part 78 continues to read as follows:
Authority: 42 U.S.C. 7401, 7403, 7410, 7411, 7426, 7601, and
7651 et seq.
0
7. Section 78.1 is amended by revising paragraph (a)(1) and adding
paragraphs (b)(18) and (19) to read as follows:
Sec. 78.1 Purpose and scope.
(a)(1) This part shall govern appeals of any final decision of the
Administrator under subparts MMM and NNN of part 62 of this chapter,
part 72, 73, 74, 75, 76, or 77 of this chapter, subparts AA through II
of part 96 of this chapter or State regulations approved under Sec.
51.123(o)(1) or (2) of this chapter, subparts AAA through III of part
96 of this chapter or State regulations approved under Sec.
51.124(o)(1) or (2) of this chapter, subparts AAAA through IIII of part
96 of this chapter or State regulations approved under Sec.
51.123(aa)(1) or (2) of this chapter, part 97 of this chapter, or
subpart RR of part 98 of this chapter; provided that matters listed in
Sec. 78.3(d) and preliminary, procedural, or intermediate decisions,
such as draft Acid Rain permits, may not be appealed. All references in
paragraph (b) of this section and in Sec. 78.3 to subparts AA through
II of part 96 of this chapter, subparts AAA through III of part 96 of
this chapter, and subparts AAAA through IIII of part 96 of this chapter
shall be read to include the comparable provisions in State regulations
approved under Sec. 51.123(o)(1) or (2) of this chapter, Sec.
51.124(o)(1) or (2) of this chapter, and Sec. 51.123(aa)(1) or (2) of
this chapter, respectively.
* * * * *
(b) * * *
(18) Under subpart MMM of part 62 of this chapter,
(i) The decision on allocation of CO2 allowances under
Sec. 62.16240 of this chapter.
(ii) The decision on allocation of CO2 allowances from
set-asides under Sec. 62.16245 of this chapter.
(iii) The decision on the transfer of CO2 allowances
under Sec. 62.16330 of this chapter.
(iv) The decision on the deduction of CO2 allowances
under Sec. 62.16340 of this chapter.
(v) The correction of an error in an ATCS account under Sec.
62.16355 of this chapter.
(vi) The adjustment of information in a submission and the decision
on the deduction and transfer of CO2 allowances based on the
information as adjusted under Sec. 62.16370 of this chapter.
(vii) The finalization of compliance period emissions data,
including retroactive adjustment based on audit.
(19) Under subpart NNN of part 62 of this chapter,
(i) The decision on emission rate credit issuance, adjustment, and
revocation under Sec. 62.16435.
(ii) The decision on qualification status of eligible resources to
receive emission rate credits under Sec. 62.16460.
(iii) The decision on revocation of qualification status of an
eligible resource under Sec. 62.16440.
(iv) The decision on Adjustments for error or misstatement,
suspension of ERC issuance under Sec. 62.16450.
(v) The decision on accreditation of independent verifiers under
Sec. 62.16470.
(vi) The decision on revocation of accreditation status under Sec.
62.16480.
(vii) The decision on the transfer of emission rate credits under
Sec. 62.16530 of this chapter.
(viii) The decision on the deduction of emission rate credits under
Sec. 62.16535 of this chapter.
(ix) The correction of an error in an ATCS account under Sec.
62.16550 of this chapter.
(x) The adjustment of information in a submission and the decision
on the deduction and transfer of emission rate credits based on the
information as adjusted under Sec. 62.16565 of this chapter.
(xi) The finalization of compliance period emissions data,
including retroactive adjustment based on audit.
* * * * *
[FR Doc. 2015-22848 Filed 10-22-15; 8:45 am]
BILLING CODE 6560-50-P