Transmission Planning and Cost Management; Joint Federal-State Task Force on Electric Transmission; Notice Inviting Post-Technical Conference Comments, 80533-80537 [2022-28454]
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Federal Register / Vol. 87, No. 250 / Friday, December 30, 2022 / Notices
Comment Date: 5 p.m. ET 2/20/23.
Docket Numbers: ER10–3297–018.
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Comment Date: 5 p.m. ET 1/13/23.
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Filed Date: 12/23/22.
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Filed Date: 12/23/22.
Accession Number: 20221223–5083.
Comment Date: 5 p.m. ET 1/13/23.
The filings are accessible in the
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elibrary.ferc.gov/idmws/search/
fercgensearch.asp) by querying the
docket number.
Any person desiring to intervene or
protest in any of the above proceedings
must file in accordance with Rules 211
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Regulations (18 CFR 385.211 and
385.214) on or before 5:00 p.m. Eastern
time on the specified comment date.
Protests may be considered, but
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eFiling is encouraged. More detailed
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service, and qualifying facilities filings
can be found at: https://www.ferc.gov/
docs-filing/efiling/filing-req.pdf. For
other information, call (866) 208–3676
(toll free). For TTY, call (202) 502–8659.
Dated: December 23, 2022.
Debbie-Anne A. Reese,
Deputy Secretary.
[FR Doc. 2022–28453 Filed 12–29–22; 8:45 am]
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DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
[Docket Nos. AD22–8–000, AD21–15–000]
Transmission Planning and Cost
Management; Joint Federal-State Task
Force on Electric Transmission; Notice
Inviting Post-Technical Conference
Comments
On October 6, 2022, the Federal
Energy Regulatory Commission
(Commission) convened a technical
conference to discuss transmission
planning and cost management for
transmission facilities developed
through local or regional transmission
planning processes.
All interested persons are invited to
file post-technical conference comments
on issues raised during the conference
that they believe would benefit from
further discussion. In particular, parties
are invited to provide comments on the
questions listed below.1 Commenters
need not respond to all topics or
questions asked, and they are not
limited to the topics or questions posed.
Commenters may reference material
previously filed in this docket,
including the technical conference
transcript, but are encouraged to avoid
repetition or replication of previous
material. In addition, commenters are
encouraged, when possible, to provide
examples and quantitative data in
support of their answers. Comments
must be submitted on or before 90 days
from the date of this notice.
Comments may be filed electronically
via the internet.2 Instructions are
available on the Commission’s website
https://www.ferc.gov/docs-filing/
efiling.asp. For assistance, please
contact FERC Online Support at
FERCOnlineSupport@ferc.gov or toll
free at 1–866–208–3676, or for TTY,
(202) 502–8659. Although the
Commission strongly encourages
electronic filing, documents may also be
paper-filed. To paper-file, submissions
sent via the U.S. Postal Service must be
addressed to: Federal Energy Regulatory
Commission, Office of the Secretary,
888 First Street NE, Washington, DC
20426. Submissions sent via any other
carrier must be addressed to: Federal
Energy Regulatory Commission, Office
of the Secretary, 12225 Wilkins Avenue,
Rockville, MD 20852.
For more information about this
Notice, please contact: John Riehl
(Technical Information), Office of
1 Supplemental Notice of Technical Conference,
Docket No. AD22–8–000 (Oct. 4, 2022).
2 See 18 CFR 385.2001(a)(1)(iii) (2021).
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Energy Market Regulation, (202) 502–
6026, John.Riehl@ferc.gov.
Dated: December 23, 2022.
Debbie-Anne A. Reese,
Deputy Secretary.
Post-Technical Conference Questions
for Comment
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Local Transmission Planning Under
Order No. 890 and Planning for Asset
Management 3 Projects
1. In Order No. 890, the Commission
established nine transmission planning
principles, including the coordination,
openness, transparency, and
information exchange principles.4 The
Commission adopted the transmission
planning principles in Order No. 890 to
remedy opportunities for undue
discrimination in expansion of the
transmission system on both a local and
regional level.5
a. Do the existing Order No. 890
transmission planning requirements
provide state regulators and other
stakeholders with sufficient
transparency into and information about
public utility transmission providers’
local transmission planning criteria and
the resulting identification of
transmission system needs? If not,
please explain how the Commission
could revise the coordination, openness,
transparency, and information exchange
principles in Order No. 890 to provide
for enhanced transparency and
information sharing. Further, please
explain what, if any, additional
transparency measures would assist
state regulators and other stakeholders
in understanding how public utility
transmission providers develop their
local transmission planning criteria,
3 Asset Management refers to projects and
activities that ‘‘encompass the maintenance, repair,
and replacement work done on existing
transmission facilities as necessary to maintain a
safe, reliable, and compliant grid based on existing
topology.’’ See So. Cal. Edison Co, 164 FERC
¶ 61,160 at n.55 (2018); Cal. Pub. Util. Comm’n v.
Pac. Gas & Elec. Co., 164 FERC ¶ 61,161 at n.119
(2018). Additionally, asset management projects or
activities may result in an incidental increase in
transmission capacity that is not reasonably
severable from the asset management project or
activity, and such incidental increase in
transmission capacity would not render the asset
management project or activity in question a
transmission expansion that is subject to the
transmission planning requirements of Order No.
890. See So. Cal. Edison Co, 164 FERC ¶ 61,160 at
P 33 (2018); Cal. Pub. Util. Comm’n v. Pac. Gas &
Elec. Co., 164 FERC ¶ 61,161 at P 68 (2018).
4 Preventing Undue Discrimination and
Preference in Transmission Service, Order No. 890,
118 FERC ¶ 61,119, at P 444, order on reh’g, Order
No. 890–A, 121 FERC ¶ 61,297 (2007), order on
reh’g, Order No. 890–B, 123 FERC ¶ 61,299 (2008),
order on reh’g, Order No. 890–C, 126 FERC
¶ 61,228, order on clarification, Order No. 890–D,
129 FERC ¶ 61,126 (2009).
5 Id. PP 57–58, 421–422, 425.
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how those criteria drive local
transmission needs, and how public
utility transmission providers consider
local transmission projects to address
those needs.
b. Is there any information beyond
that required under the Order No. 890
transmission planning principles that
the Commission should consider
requiring public utility transmission
providers to provide in their local
transmission planning processes? For
example, should the Commission
require that public utility transmission
providers make available to state
regulators and other stakeholders cost
estimates used during transmission
planning for all transmission facility
alternatives considered to address the
transmission needs, including, but not
limited to, those transmission facilities
that are chosen to address the local
transmission planning criteria, or for a
subset of those facility alternatives?
What would be the advantages and
disadvantages of such a requirement? If
so, how should cost estimates used
during transmission planning for these
transmission facilities be calculated?
c. Are there barriers to state regulators
and other stakeholders accessing the
information that public utility
transmission providers provide through
their local transmission planning
processes (e.g., fees, background checks,
etc.)? Do state regulators and other
stakeholders have access to the
expertise necessary to analyze the
information presented and to evaluate
the public utility transmission
providers’ local transmission planning
decisions? What actions could the
Commission take to reduce any such
barriers?
2. Order No. 890’s requirements apply
to transmission facilities that expand
the transmission system, but do not
apply to asset management projects, as
defined above. However, some public
utility transmission providers have
processes that provide stakeholders
with some transparency into their asset
management decisions. For example,
Pacific Gas & Electric’s Stakeholder
Transmission Asset Review (STAR)
Process and Southern California
Edison’s Stakeholder Review Process
(SRP) provide stakeholders with the
opportunity to engage in a review of
PG&E’s and Southern California
Edison’s five-year plan for capital
transmission projects so that
stakeholders can understand the need
for and anticipated costs of projects that
are not reviewed in the California
Independent System Operator Corp.’s
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(CAISO) transmission planning
process.6
a. Should the Commission require
public utility transmission providers to
provide transparency concerning their
asset management decisions? Are there
any aspects of Pacific Gas & Electric’s
STAR Process or Southern California
Edison’s SRP that would be beneficial to
consider? What other considerations are
relevant to the transparency of asset
management project decisions?
b. Are there barriers to state regulators
and other stakeholders analyzing any
additional information that the
Commission could require public utility
transmission providers to provide
concerning their asset management
projects? For example, do state
regulators and other stakeholders have
access to the expertise necessary to
analyze the information presented?
What actions could the Commission
take to reduce any such barriers?
3. Could additional transparency
facilitated by project-specific disclosure
requirements or standardized filing
requirements help increase the cost
effectiveness of local transmission
planning and asset management
decisions? Examples include additional
transparency and access to local
planning criteria, utilities’ rankings of
their project priorities (subject to CEII
protections), requirements for utilities to
provide either publicly or to the
Commission a standardized disclosure
describing the need for a local
transmission project or asset
management project and why it is a
cost-effective solution to that need
before money is spent on the planned
transmission project (other than any
planning costs incurred), and a
requirement for utilities to provide
advance notice of a project nearing its
end of life, among others. To the extent
that such requirements may be
appropriate, what specific requirements
should the Commission impose? For
example, for a standardized disclosure
described above, should the
Commission require utilities to provide
such information to stakeholders as part
of their local transmission planning
process under Order No. 890, or should
the Commission require utilities to
make a filing with the Commission? At
what point in the transmission planning
process should these filings be made?
Should any such filings be
informational, or should they require
Commission action? In designing any
such requirements, how should the
6 See, e.g., PG&E, TO Tariff, PG&E Electric Tariff
Volume No. 5 (0.0.0), Appendix IX, STAR Process
(0.0.0). See also So. Cal. Ed., Docket No. ER19–
1553–005, at 2 (Dec. 8, 2020) (delegated letter
order).
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Commission weigh the administrative
burden of those requirements against
the transparency provided?
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Project Implementation and Variance
Analysis
4. In Order No. 1000, the Commission
required public utility transmission
providers to describe the circumstances
and procedures by which they will
reevaluate the regional transmission
plan to determine if delays in the
development of a regional or
interregional transmission facility
requires evaluation of alternative
transmission solutions (reevaluation
requirement).7 To comply with this
requirement, some public utility
transmission providers voluntarily
adopted a variance analysis process tied
to changes in cost estimates to examine
whether a regional transmission facility
selected in a regional transmission plan
for the purposes of cost allocation
remains the more efficient or costeffective transmission facility if its costs
rise above estimates or if there are
delays in that regional transmission
facility’s development.
a. Given that some RTOs/ISOs have
voluntarily implemented variance
analyses for regional and interregional
transmission planning, are there certain
best practices in regional and
interregional transmission planning
variance analyses that should be more
widely adopted? Conversely, are there
specific elements or characteristics of
variance analyses used by certain public
utility transmission providers that could
be improved? Please describe.
b. What consequences should result if
variance analyses show that a regional
or interregional transmission facility’s
costs have increased above an
established threshold since it was
initially selected in a regional
transmission plan for the purposes of
cost allocation? What consequences
should result if variance analyses show
that a regional or interregional
transmission facility’s estimated
benefits have eroded beyond an
established threshold since it was
initially selected in a regional
transmission plan for the purposes of
cost allocation?
c. Should the Commission require
public utility transmission providers to
perform variance analyses as part of
their regional transmission planning
processes? To what types of regional
transmission projects should such a
requirement apply?
7 Transmission Planning & Cost Allocation by
Transmission Owning and Operating Pub. Utils.,
Order No. 1000, 136 FERC ¶ 61,051, at P 329 (2011).
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d. Could variance analysis or similar
mechanism be applied to facilitate cost
management outside the context of
regional or interregional transmission
facilities subject to cost allocation under
Order No. 1000 and, if so, should the
Commission require it? What legal
rationale would justify the requirement
to use variance analysis? What level of
increased costs or decreased benefits
would merit evaluation through a
variance analysis to determine whether
a transmission project continues to be
cost-effective? Would it be appropriate
to apply a cost or benefits threshold
below which or above which,
respectively, such a requirement would
not apply? Are there any categories of
transmission projects for which this cost
management method is not appropriate?
e. Who should be responsible for
developing the cost estimates used in
the variance analysis? The RTO/ISO, the
public utility transmission provider, an
Independent Transmission Monitor, or
another entity? Should this role vary
between non-RTO/ISO and RTO/ISO
regions, and/or are there general
guidelines with regard to independence
that should be met for any entity
developing cost estimates or
bandwidths?
f. Can or should such an approach be
designed in order to maximize benefits
to consumers, as opposed to focusing
only on reducing costs? For example, a
given project modification might
increase up-front costs of the project,
but lower costs for customers in the
long-run by enhancing project efficiency
and thereby increasing anticipated
economic benefits. Should any variance
analysis mechanism required by the
Commission be designed in a manner
that encourages such investments, or at
minimum does not inadvertently
discourage them? If so, how?
Independent Transmission Monitor
(ITM)
5. During the technical conference,
many panelists argued in favor of an
ITM to review and evaluate a wide
range of elements of the transmission
planning process, including the
transmission planning criteria used to
identify transmission facilities.
However, others expressed concern that
an ITM would be unnecessary or
duplicative in light of other regulatory
agencies or stakeholders. Given the
divergence of views on the potential
roles and responsibilities of an ITM,
please respond to the following:
a. Please provide a concise but
detailed job description for an ITM in
both RTOs/ISOs and non-RTOs/ISOs.
For example, should the ITM serve as a
technical expert that publishes after-the-
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fact reports assessing public utility
transmission providers’ transmission
plans? Should an ITM assist state
regulators and other stakeholder with
evaluating potential transmission
facilities and their costs? Should an ITM
participate in proceedings before the
Commission? Should an ITM develop
and monitor benchmark estimates of
costs using data collected over time?
Should an ITM assess continuing need
for certain transmission projects?
Should an ITM attend local and regional
transmission planning meetings? Please
list specific roles that would be
appropriate for an ITM, and please
explain at which stage of the
transmission planning process those
roles should be leveraged (i.e., inputs
and assumptions, planning study
results, selection, cost allocation, project
development).
b. What are the potential benefits of
an ITM? Please describe with
specificity, and address whether these
benefits are particular to RTO/ISO or
non-RTO/ISO regions, or present in
both.
c. Are there specific challenges,
including how the roles and
responsibilities of the ITM relate to
Commission jurisdiction, regarding the
creation of an ITM, or the
responsibilities that an ITM might have
that the Commission should consider? If
so, please describe.
d. What information would the ITM
need access to in carrying out these
responsibilities? Should the ITM have
access to transmission planning and
cost information, including CEII
information? Please describe with
specificity the information that the ITM
should be able to review.
e. If an ITM were established, should
the Commission periodically review the
need for, role, and/or scope of that
entity?
f. Would the ITM’s functions
potentially overlap with the functions of
a public utility transmission provider,
particularly in an RTO/ISO? If so, where
would the overlap occur? Where should
the ITM be housed, and what are the
pros and cons of that arrangement (e.g.,
internal or external independent entity
similar to or incorporated within IMMs,
an office within the Commission itself,
or some other arrangement)? How
should an ITM be funded?
g. How, if at all, should an ITM’s role
differ between RTO/ISO regions and
non-RTO/ISO regions? What legal
authority (or authorities) could the
Commission rely on in establishing an
ITM, and does that authority differ with
respect to RTO/ISO and non-RTO/ISO
regions? Should the Commission require
an ITM in both RTOs/ISOs and non-
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RTOs/ISOs? If so, please state the legal
justification in both RTOs/ISOs and
non-RTOs/ISOs. What implications does
the Commission’s scope of authority
have with regard to the potential
structure and duties of the ITM?
h. How often and at what stages of the
local and regional transmission
planning processes and interregional
transmission coordination process
should an ITM review and evaluate
transmission facility cost information, if
at all (e.g., during the transmission
planning cycle, during the development
of the transmission facility, or following
the completion of construction of the
transmission facility)? What types of
costs should an ITM review and
evaluate (e.g., capital costs, labor costs,
etc.), if any? What should an ITM do
with the information that is reviewed
and evaluated?
i. Should the Commission establish a
minimum threshold (e.g., costs, voltage,
etc.) for transmission facilities that
would be reviewed by an ITM? If so,
what should that threshold be and why?
In RTO/ISO regions, should an ITM
review only transmission facilities that
address local transmission planning
criteria and asset management
transmission projects?
j. Should an ITM be subject to
standards of conduct or other
professional criteria? If so, what should
those standards be?
khammond on DSKJM1Z7X2PROD with NOTICES
Commission’s Formula Rates and
Prudence Practices
6. Under the MISO Protocol Orders,8
the Commission required public utility
transmission providers to include
safeguards in their transmission formula
rate protocols to provide transparency
in the public utility transmission
providers’ implementation of their
transmission formula rates, to ensure
that input data is correct, and that their
calculations are performed consistent
with the formula.
a. What, if any, specific standard
formula rate protocols that the
Commission requires under the MISO
Protocol Orders and other precedent
should be revised, and how? For
example, should the Commission
require public utility transmission
providers to provide additional time for
state regulators and other stakeholders
to review and respond to annual
8 Midwest Indep. Transmission Sys. Operator,
Inc., 139 FERC ¶ 61,127 at P 9 (2013); see also
Midwest Indep. Transmission Sys. Operator, Inc.,
143 FERC ¶ 61,149 (2013); Midcontinent Indep. Sys.
Operator, Inc., 146 FERC ¶ 61,212 (2014); and
Midcontinent Indep. Sys. Operator, Inc., 150 FERC
¶ 61,025 (2015) (collectively, MISO Protocol
Orders).
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updates before they are submitted to the
Commission?
7. Under the Commission’s current
prudence standard, the Commission
presumes that a public utility
transmission provider’s expenditures
are prudent in the absence of a
challenge casting serious doubt on such
prudence, and establishing serious
doubt regarding prudence requires
‘‘reliable, probative, and substantial
evidence.’’ 9
a. Should the Commission alter the
rebuttable presumption of prudence of
expenditures in certain circumstances,
such as with respect to specific types of
expenditures (e.g., asset management
expenditures), where alternatives to
transmission have not been considered,
or where a state regulator has not
reviewed a project for need and cost? If
so, how should the standard be altered
and in which circumstances?
8. Other than transparency criteria,
are there ways that the Commission
could consider local planning criteria
that utilities use in determining how the
prudence standard is applied to specific
expenditures? For example, with respect
to local transmission and/or asset
management projects, should the
Commission establish certain guidance
for planning such projects and only
apply the rebuttable presumption of
prudence to projects that follow the
Commission-determined guidelines for
planning such projects? What are the
pros and cons of that approach?
Federal and State Regulation of
Transmission Facilities
9. Some panelists at the technical
conference argued that there is a
regulatory gap with regard to ensuring
that a cost-effective mix of local, asset
management, and regional reliability
transmission projects is developed.
Generally speaking, for such projects
they contend that state siting processes,
the formula rate process, and the
Commission’s prudence standard and
existing transparency requirements, may
not provide adequate assurance that
utilities will choose a cost-effective mix
of projects. Do you agree that there is a
regulatory gap for local projects and/or
asset management projects, and if so,
why or why not? Does the presence or
extent of a regulatory gap depend on the
underlying state regulatory framework?
If so, how? If you agree that one or more
regulatory gaps exist, how should the
Commission address these gaps? For
example, should the Commission
modify the prudence standard and/or
9 Delmarva Power & Light Co., 172 FERC ¶ 61,175,
at P 15 (2020) (citing New Eng. Power Co., Opinion
No. 231, 31 FERC ¶ 61,047 (1985)).
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formula rate protocols for transmission
or asset management projects falling
within such a regulatory gap? Should
the Commission establish new
transmission planning requirements to
help ensure that such projects are costeffective? In your response, please
discuss whether the Commission’s
approach should depend on the
underlying state regulatory framework.
Also please discuss the extent to which
your recommended reforms, standing
alone, will address the perceived gaps,
or whether they should or must be
coupled with other solutions.
10. Some panelists argued that certain
types of projects do not receive adequate
state, regional, or federal scrutiny with
regard to project prudence/need. For
example, the Commission has held that
asset management and end-of-life
decisions are not subject to Order No.
890 planning requirements, and
panelists highlighted that in some states
such projects do not require a certificate
of public convenience and necessity. Do
you agree that some projects are not
subject to adequate review, and if so,
why or why not? What particular types
of projects do not receive adequate
scrutiny (if any), and should there be
some form of heightened scrutiny for
them? If so, what kind of heightened
scrutiny would be appropriate, and how
would that scrutiny be applied?
11. The Commission has authority
over the justness and reasonableness of
the rates for wholesale transmission
service, including recovery of the costs
of transmission facilities used in
providing transmission service and the
prudence of those expenditures, and has
approved public utility transmission
provider proposals to recover their costs
of providing transmission service
through formula rates. Under a formula
rate, the Commission reviews and
accepts as the rate a formula for
calculating the utility’s cost of service,
including clear definitions of inputs to
that formula and a process for updating
rates every year as the utility’s costs
change. State regulators typically have
authority to evaluate whether certain
transmission facilities to be built within
their state may be constructed (i.e.,
whether to grant the proposed facility a
Certificate of Public Convenience and
Necessity (CPCN)), which may involve
evaluation of the need for, and projected
costs of, a proposed transmission
facility.
a. Are there differences among the
states’ CPCN authorities and processes,
and what is the extent of those
differences?
b. Should the Commission consider
relying on a state regulator’s
determination in a CPCN proceeding
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Federal Register / Vol. 87, No. 250 / Friday, December 30, 2022 / Notices
khammond on DSKJM1Z7X2PROD with NOTICES
that a proposed transmission facility is
in the public convenience and necessity
when considering whether the costs of
that transmission facility may be
recovered through a formula rate?
Should the Commission prohibit the
recovery of transmission project costs
through a formula rate if those projects
have not been subject to a robust state
CPCN process? Why or why not? Should
the Commission accept as self-proving
an attestation from state regulators that
such a robust CPCN process is used in
their state? If yes, are there specific
factors or features of a state regulator’s
CPCN process that indicate whether a
potential transmission facility has been
robustly evaluated for need and cost? If
not, are there other indicators (e.g.,
other regulatory determinations, thirdparty analyses, legislative reports, etc.)
that demonstrate that the need for and
costs of a potential transmission facility
have been robustly reviewed? What are
the advantages and disadvantages of this
approach?
c. If formula rate treatment is not
permitted, how should costs related to
the new transmission project or
transmission facility be separated out
for recovery in a stated rate proceeding
(e.g., should all costs related to the
transmission facility be excluded from
formula rate recovery, or only capital
costs)? How could the timing of the state
regulatory proceeding impact a public
utility transmission provider’s ability to
file for cost recovery of proposed
transmission facilities subject to CPCN
review? How, if at all, would the
inability to recover the costs of certain
transmission facilities through a public
utility transmission provider’s formula
rate impact its annual formula rate
proceedings?
d. If the Commission determines that
a potential transmission facility has not
been robustly evaluated at the state level
for need and cost, are there other
regulatory requirements that the
Commission could impose short of
requiring a transmission facility’s costs
to be recovered through stated rates
rather than formula rates? If so, what
options are available and what are the
pros and cons of those options?
Other Questions
12. Some panelists argued that the
timing of cost management or oversight
mechanisms is relevant to ensuring cost
effectiveness, contending that cost
scrutiny must be applied to decisions
during the local or regional transmission
planning phase in order to influence
those decisions. Do you agree, and if so
why or why not? What are the
possibilities for facilitating timely cost
management before money is spent on
VerDate Sep<11>2014
17:08 Dec 29, 2022
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transmission projects (aside from
planning costs)?
[FR Doc. 2022–28454 Filed 12–29–22; 8:45 am]
BILLING CODE 6717–01–P
ENVIRONMENTAL PROTECTION
AGENCY
80537
DEPARTMENT OF HEALTH AND
HUMAN SERVICES
Agency for Healthcare Research and
Quality
Patient Safety Organizations:
Voluntary Relinquishment for the
Zephcare PSO
Agency for Healthcare Research
and Quality (AHRQ), Department of
Health and Human Services (HHS).
ACTION: Notice of delisting.
AGENCY:
[FRL OP–OFA–050]
Environmental Impact Statements;
Notice of Availability
Responsible Agency: Office of Federal
Activities, General Information 202–
564–5632 or https://www.epa.gov/nepa.
Weekly receipt of Environmental Impact
Statements (EIS) Filed December 19,
2022 10 a.m. EST Through December
23, 2022 10 a.m. EST Pursuant to 40
CFR 1506.9.
Notice
Section 309(a) of the Clean Air Act
requires that EPA make public its
comments on EISs issued by other
Federal agencies. EPA’s comment letters
on EISs are available at: https://
cdxapps.epa.gov/cdx-enepa-II/public/
action/eis/search.
EIS No. 20220193, Final, FEMA, NJ,
ADOPTION—Rebuild by Design—
Hudson River (RBD–HR), Review
Period Ends: 01/30/2023, Contact:
John McKee 202–704–7160.
The Federal Emergency Management
Agency (FEMA) has adopted the
Department of Housing and Urban
Development’s Final EIS No. 20170101,
filed 6/8/2017 with the Environmental
Protection Agency. The FEMA was not
a cooperating agency on this project.
Therefore, republication of the
document is necessary under Section
1506.3(c) of the CEQ regulations.
Amended Notice
EIS No. 20220175, Draft, BIA, DOI, OR,
Coquille Indian Tribe Fee to Trust
Gaming Facility Project, Comment
Period Ends: 02/23/2023, Contact:
Tobiah Mogavero 435–210–0509.
Revision to FR Notice Published 11/
25/2022; Extending the Comment Period
from 01/09/2023 to 02/23/2023.
Dated: December 23, 2022.
Cindy S. Barger,
Director, NEPA Compliance Division, Office
of Federal Activities.
[FR Doc. 2022–28438 Filed 12–29–22; 8:45 am]
BILLING CODE 6560–50–P
PO 00000
Frm 00016
Fmt 4703
Sfmt 4703
The Patient Safety and
Quality Improvement Final Rule
(Patient Safety Rule) authorizes AHRQ,
on behalf of the Secretary of HHS, to list
as a patient safety organization (PSO) an
entity that attests that it meets the
statutory and regulatory requirements
for listing. A PSO can be ‘‘delisted’’ by
the Secretary if it is found to no longer
meet the requirements of the Patient
Safety and Quality Improvement Act of
2005 (Patient Safety Act) and Patient
Safety Rule, when a PSO chooses to
voluntarily relinquish its status as a
PSO for any reason, or when a PSO’s
listing expires. AHRQ accepted a
notification of proposed voluntary
relinquishment from the Zephcare PSO,
PSO number P0200, of its status as a
PSO, and has delisted the PSO
accordingly.
SUMMARY:
The delisting was effective at
12:00 Midnight ET (2400) on December
8, 2022.
ADDRESSES: The directories for both
listed and delisted PSOs are ongoing
and reviewed weekly by AHRQ. Both
directories can be accessed
electronically at the following HHS
website: https://www.pso.ahrq.gov/
listed.
DATES:
FOR FURTHER INFORMATION CONTACT:
Cathryn Bach, Center for Quality
Improvement and Patient Safety, AHRQ,
5600 Fishers Lane, MS 06N100B,
Rockville, MD 20857; Telephone (toll
free): (866) 403–3697; Telephone (local):
(301) 427–1111; TTY (toll free): (866)
438–7231; TTY (local): (301) 427–1130;
Email: pso@ahrq.hhs.gov.
SUPPLEMENTARY INFORMATION:
Background
The Patient Safety Act, 42 U.S.C.
299b–21 to 299b–26, and the related
Patient Safety Rule, 42 CFR part 3,
published in the Federal Register on
November 21, 2008 (73 FR 70732–
70814), establish a framework by which
individuals and entities that meet the
definition of provider in the Patient
Safety Rule may voluntarily report
information to PSOs listed by AHRQ, on
E:\FR\FM\30DEN1.SGM
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]]>Agencies
[Federal Register Volume 87, Number 250 (Friday, December 30, 2022)]
[Notices]
[Pages 80533-80537]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2022-28454]
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DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
[Docket Nos. AD22-8-000, AD21-15-000]
Transmission Planning and Cost Management; Joint Federal-State
Task Force on Electric Transmission; Notice Inviting Post-Technical
Conference Comments
On October 6, 2022, the Federal Energy Regulatory Commission
(Commission) convened a technical conference to discuss transmission
planning and cost management for transmission facilities developed
through local or regional transmission planning processes.
All interested persons are invited to file post-technical
conference comments on issues raised during the conference that they
believe would benefit from further discussion. In particular, parties
are invited to provide comments on the questions listed below.\1\
Commenters need not respond to all topics or questions asked, and they
are not limited to the topics or questions posed.
---------------------------------------------------------------------------
\1\ Supplemental Notice of Technical Conference, Docket No.
AD22-8-000 (Oct. 4, 2022).
---------------------------------------------------------------------------
Commenters may reference material previously filed in this docket,
including the technical conference transcript, but are encouraged to
avoid repetition or replication of previous material. In addition,
commenters are encouraged, when possible, to provide examples and
quantitative data in support of their answers. Comments must be
submitted on or before 90 days from the date of this notice.
Comments may be filed electronically via the internet.\2\
Instructions are available on the Commission's website https://www.ferc.gov/docs-filing/efiling.asp. For assistance, please contact
FERC Online Support at [email protected] or toll free at 1-
866-208-3676, or for TTY, (202) 502-8659. Although the Commission
strongly encourages electronic filing, documents may also be paper-
filed. To paper-file, submissions sent via the U.S. Postal Service must
be addressed to: Federal Energy Regulatory Commission, Office of the
Secretary, 888 First Street NE, Washington, DC 20426. Submissions sent
via any other carrier must be addressed to: Federal Energy Regulatory
Commission, Office of the Secretary, 12225 Wilkins Avenue, Rockville,
MD 20852.
---------------------------------------------------------------------------
\2\ See 18 CFR 385.2001(a)(1)(iii) (2021).
---------------------------------------------------------------------------
For more information about this Notice, please contact: John Riehl
(Technical Information), Office of
[[Page 80534]]
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Energy Market Regulation, (202) 502-6026, [email protected].
Dated: December 23, 2022.
Debbie-Anne A. Reese,
Deputy Secretary.
Post-Technical Conference Questions for Comment
Local Transmission Planning Under Order No. 890 and Planning for Asset
Management 3 Projects
---------------------------------------------------------------------------
\3\ Asset Management refers to projects and activities that
``encompass the maintenance, repair, and replacement work done on
existing transmission facilities as necessary to maintain a safe,
reliable, and compliant grid based on existing topology.'' See So.
Cal. Edison Co, 164 FERC ] 61,160 at n.55 (2018); Cal. Pub. Util.
Comm'n v. Pac. Gas & Elec. Co., 164 FERC ] 61,161 at n.119 (2018).
Additionally, asset management projects or activities may result in
an incidental increase in transmission capacity that is not
reasonably severable from the asset management project or activity,
and such incidental increase in transmission capacity would not
render the asset management project or activity in question a
transmission expansion that is subject to the transmission planning
requirements of Order No. 890. See So. Cal. Edison Co, 164 FERC ]
61,160 at P 33 (2018); Cal. Pub. Util. Comm'n v. Pac. Gas & Elec.
Co., 164 FERC ] 61,161 at P 68 (2018).
---------------------------------------------------------------------------
1. In Order No. 890, the Commission established nine transmission
planning principles, including the coordination, openness,
transparency, and information exchange principles.\4\ The Commission
adopted the transmission planning principles in Order No. 890 to remedy
opportunities for undue discrimination in expansion of the transmission
system on both a local and regional level.\5\
---------------------------------------------------------------------------
\4\ Preventing Undue Discrimination and Preference in
Transmission Service, Order No. 890, 118 FERC ] 61,119, at P 444,
order on reh'g, Order No. 890-A, 121 FERC ] 61,297 (2007), order on
reh'g, Order No. 890-B, 123 FERC ] 61,299 (2008), order on reh'g,
Order No. 890-C, 126 FERC ] 61,228, order on clarification, Order
No. 890-D, 129 FERC ] 61,126 (2009).
\5\ Id. PP 57-58, 421-422, 425.
---------------------------------------------------------------------------
a. Do the existing Order No. 890 transmission planning requirements
provide state regulators and other stakeholders with sufficient
transparency into and information about public utility transmission
providers' local transmission planning criteria and the resulting
identification of transmission system needs? If not, please explain how
the Commission could revise the coordination, openness, transparency,
and information exchange principles in Order No. 890 to provide for
enhanced transparency and information sharing. Further, please explain
what, if any, additional transparency measures would assist state
regulators and other stakeholders in understanding how public utility
transmission providers develop their local transmission planning
criteria, how those criteria drive local transmission needs, and how
public utility transmission providers consider local transmission
projects to address those needs.
b. Is there any information beyond that required under the Order
No. 890 transmission planning principles that the Commission should
consider requiring public utility transmission providers to provide in
their local transmission planning processes? For example, should the
Commission require that public utility transmission providers make
available to state regulators and other stakeholders cost estimates
used during transmission planning for all transmission facility
alternatives considered to address the transmission needs, including,
but not limited to, those transmission facilities that are chosen to
address the local transmission planning criteria, or for a subset of
those facility alternatives? What would be the advantages and
disadvantages of such a requirement? If so, how should cost estimates
used during transmission planning for these transmission facilities be
calculated?
c. Are there barriers to state regulators and other stakeholders
accessing the information that public utility transmission providers
provide through their local transmission planning processes (e.g.,
fees, background checks, etc.)? Do state regulators and other
stakeholders have access to the expertise necessary to analyze the
information presented and to evaluate the public utility transmission
providers' local transmission planning decisions? What actions could
the Commission take to reduce any such barriers?
2. Order No. 890's requirements apply to transmission facilities
that expand the transmission system, but do not apply to asset
management projects, as defined above. However, some public utility
transmission providers have processes that provide stakeholders with
some transparency into their asset management decisions. For example,
Pacific Gas & Electric's Stakeholder Transmission Asset Review (STAR)
Process and Southern California Edison's Stakeholder Review Process
(SRP) provide stakeholders with the opportunity to engage in a review
of PG&E's and Southern California Edison's five-year plan for capital
transmission projects so that stakeholders can understand the need for
and anticipated costs of projects that are not reviewed in the
California Independent System Operator Corp.'s (CAISO) transmission
planning process.\6\
---------------------------------------------------------------------------
\6\ See, e.g., PG&E, TO Tariff, PG&E Electric Tariff Volume No.
5 (0.0.0), Appendix IX, STAR Process (0.0.0). See also So. Cal. Ed.,
Docket No. ER19-1553-005, at 2 (Dec. 8, 2020) (delegated letter
order).
---------------------------------------------------------------------------
a. Should the Commission require public utility transmission
providers to provide transparency concerning their asset management
decisions? Are there any aspects of Pacific Gas & Electric's STAR
Process or Southern California Edison's SRP that would be beneficial to
consider? What other considerations are relevant to the transparency of
asset management project decisions?
b. Are there barriers to state regulators and other stakeholders
analyzing any additional information that the Commission could require
public utility transmission providers to provide concerning their asset
management projects? For example, do state regulators and other
stakeholders have access to the expertise necessary to analyze the
information presented? What actions could the Commission take to reduce
any such barriers?
3. Could additional transparency facilitated by project-specific
disclosure requirements or standardized filing requirements help
increase the cost effectiveness of local transmission planning and
asset management decisions? Examples include additional transparency
and access to local planning criteria, utilities' rankings of their
project priorities (subject to CEII protections), requirements for
utilities to provide either publicly or to the Commission a
standardized disclosure describing the need for a local transmission
project or asset management project and why it is a cost-effective
solution to that need before money is spent on the planned transmission
project (other than any planning costs incurred), and a requirement for
utilities to provide advance notice of a project nearing its end of
life, among others. To the extent that such requirements may be
appropriate, what specific requirements should the Commission impose?
For example, for a standardized disclosure described above, should the
Commission require utilities to provide such information to
stakeholders as part of their local transmission planning process under
Order No. 890, or should the Commission require utilities to make a
filing with the Commission? At what point in the transmission planning
process should these filings be made? Should any such filings be
informational, or should they require Commission action? In designing
any such requirements, how should the
[[Page 80535]]
Commission weigh the administrative burden of those requirements
against the transparency provided?
Project Implementation and Variance Analysis
4. In Order No. 1000, the Commission required public utility
transmission providers to describe the circumstances and procedures by
which they will reevaluate the regional transmission plan to determine
if delays in the development of a regional or interregional
transmission facility requires evaluation of alternative transmission
solutions (reevaluation requirement).\7\ To comply with this
requirement, some public utility transmission providers voluntarily
adopted a variance analysis process tied to changes in cost estimates
to examine whether a regional transmission facility selected in a
regional transmission plan for the purposes of cost allocation remains
the more efficient or cost-effective transmission facility if its costs
rise above estimates or if there are delays in that regional
transmission facility's development.
---------------------------------------------------------------------------
\7\ Transmission Planning & Cost Allocation by Transmission
Owning and Operating Pub. Utils., Order No. 1000, 136 FERC ] 61,051,
at P 329 (2011).
---------------------------------------------------------------------------
a. Given that some RTOs/ISOs have voluntarily implemented variance
analyses for regional and interregional transmission planning, are
there certain best practices in regional and interregional transmission
planning variance analyses that should be more widely adopted?
Conversely, are there specific elements or characteristics of variance
analyses used by certain public utility transmission providers that
could be improved? Please describe.
b. What consequences should result if variance analyses show that a
regional or interregional transmission facility's costs have increased
above an established threshold since it was initially selected in a
regional transmission plan for the purposes of cost allocation? What
consequences should result if variance analyses show that a regional or
interregional transmission facility's estimated benefits have eroded
beyond an established threshold since it was initially selected in a
regional transmission plan for the purposes of cost allocation?
c. Should the Commission require public utility transmission
providers to perform variance analyses as part of their regional
transmission planning processes? To what types of regional transmission
projects should such a requirement apply?
d. Could variance analysis or similar mechanism be applied to
facilitate cost management outside the context of regional or
interregional transmission facilities subject to cost allocation under
Order No. 1000 and, if so, should the Commission require it? What legal
rationale would justify the requirement to use variance analysis? What
level of increased costs or decreased benefits would merit evaluation
through a variance analysis to determine whether a transmission project
continues to be cost-effective? Would it be appropriate to apply a cost
or benefits threshold below which or above which, respectively, such a
requirement would not apply? Are there any categories of transmission
projects for which this cost management method is not appropriate?
e. Who should be responsible for developing the cost estimates used
in the variance analysis? The RTO/ISO, the public utility transmission
provider, an Independent Transmission Monitor, or another entity?
Should this role vary between non-RTO/ISO and RTO/ISO regions, and/or
are there general guidelines with regard to independence that should be
met for any entity developing cost estimates or bandwidths?
f. Can or should such an approach be designed in order to maximize
benefits to consumers, as opposed to focusing only on reducing costs?
For example, a given project modification might increase up-front costs
of the project, but lower costs for customers in the long-run by
enhancing project efficiency and thereby increasing anticipated
economic benefits. Should any variance analysis mechanism required by
the Commission be designed in a manner that encourages such
investments, or at minimum does not inadvertently discourage them? If
so, how?
Independent Transmission Monitor (ITM)
5. During the technical conference, many panelists argued in favor
of an ITM to review and evaluate a wide range of elements of the
transmission planning process, including the transmission planning
criteria used to identify transmission facilities. However, others
expressed concern that an ITM would be unnecessary or duplicative in
light of other regulatory agencies or stakeholders. Given the
divergence of views on the potential roles and responsibilities of an
ITM, please respond to the following:
a. Please provide a concise but detailed job description for an ITM
in both RTOs/ISOs and non-RTOs/ISOs. For example, should the ITM serve
as a technical expert that publishes after-the-fact reports assessing
public utility transmission providers' transmission plans? Should an
ITM assist state regulators and other stakeholder with evaluating
potential transmission facilities and their costs? Should an ITM
participate in proceedings before the Commission? Should an ITM develop
and monitor benchmark estimates of costs using data collected over
time? Should an ITM assess continuing need for certain transmission
projects? Should an ITM attend local and regional transmission planning
meetings? Please list specific roles that would be appropriate for an
ITM, and please explain at which stage of the transmission planning
process those roles should be leveraged (i.e., inputs and assumptions,
planning study results, selection, cost allocation, project
development).
b. What are the potential benefits of an ITM? Please describe with
specificity, and address whether these benefits are particular to RTO/
ISO or non-RTO/ISO regions, or present in both.
c. Are there specific challenges, including how the roles and
responsibilities of the ITM relate to Commission jurisdiction,
regarding the creation of an ITM, or the responsibilities that an ITM
might have that the Commission should consider? If so, please describe.
d. What information would the ITM need access to in carrying out
these responsibilities? Should the ITM have access to transmission
planning and cost information, including CEII information? Please
describe with specificity the information that the ITM should be able
to review.
e. If an ITM were established, should the Commission periodically
review the need for, role, and/or scope of that entity?
f. Would the ITM's functions potentially overlap with the functions
of a public utility transmission provider, particularly in an RTO/ISO?
If so, where would the overlap occur? Where should the ITM be housed,
and what are the pros and cons of that arrangement (e.g., internal or
external independent entity similar to or incorporated within IMMs, an
office within the Commission itself, or some other arrangement)? How
should an ITM be funded?
g. How, if at all, should an ITM's role differ between RTO/ISO
regions and non-RTO/ISO regions? What legal authority (or authorities)
could the Commission rely on in establishing an ITM, and does that
authority differ with respect to RTO/ISO and non-RTO/ISO regions?
Should the Commission require an ITM in both RTOs/ISOs and non-
[[Page 80536]]
RTOs/ISOs? If so, please state the legal justification in both RTOs/
ISOs and non-RTOs/ISOs. What implications does the Commission's scope
of authority have with regard to the potential structure and duties of
the ITM?
h. How often and at what stages of the local and regional
transmission planning processes and interregional transmission
coordination process should an ITM review and evaluate transmission
facility cost information, if at all (e.g., during the transmission
planning cycle, during the development of the transmission facility, or
following the completion of construction of the transmission facility)?
What types of costs should an ITM review and evaluate (e.g., capital
costs, labor costs, etc.), if any? What should an ITM do with the
information that is reviewed and evaluated?
i. Should the Commission establish a minimum threshold (e.g.,
costs, voltage, etc.) for transmission facilities that would be
reviewed by an ITM? If so, what should that threshold be and why? In
RTO/ISO regions, should an ITM review only transmission facilities that
address local transmission planning criteria and asset management
transmission projects?
j. Should an ITM be subject to standards of conduct or other
professional criteria? If so, what should those standards be?
Commission's Formula Rates and Prudence Practices
6. Under the MISO Protocol Orders,\8\ the Commission required
public utility transmission providers to include safeguards in their
transmission formula rate protocols to provide transparency in the
public utility transmission providers' implementation of their
transmission formula rates, to ensure that input data is correct, and
that their calculations are performed consistent with the formula.
---------------------------------------------------------------------------
\8\ Midwest Indep. Transmission Sys. Operator, Inc., 139 FERC ]
61,127 at P 9 (2013); see also Midwest Indep. Transmission Sys.
Operator, Inc., 143 FERC ] 61,149 (2013); Midcontinent Indep. Sys.
Operator, Inc., 146 FERC ] 61,212 (2014); and Midcontinent Indep.
Sys. Operator, Inc., 150 FERC ] 61,025 (2015) (collectively, MISO
Protocol Orders).
---------------------------------------------------------------------------
a. What, if any, specific standard formula rate protocols that the
Commission requires under the MISO Protocol Orders and other precedent
should be revised, and how? For example, should the Commission require
public utility transmission providers to provide additional time for
state regulators and other stakeholders to review and respond to annual
updates before they are submitted to the Commission?
7. Under the Commission's current prudence standard, the Commission
presumes that a public utility transmission provider's expenditures are
prudent in the absence of a challenge casting serious doubt on such
prudence, and establishing serious doubt regarding prudence requires
``reliable, probative, and substantial evidence.'' \9\
---------------------------------------------------------------------------
\9\ Delmarva Power & Light Co., 172 FERC ] 61,175, at P 15
(2020) (citing New Eng. Power Co., Opinion No. 231, 31 FERC ] 61,047
(1985)).
---------------------------------------------------------------------------
a. Should the Commission alter the rebuttable presumption of
prudence of expenditures in certain circumstances, such as with respect
to specific types of expenditures (e.g., asset management
expenditures), where alternatives to transmission have not been
considered, or where a state regulator has not reviewed a project for
need and cost? If so, how should the standard be altered and in which
circumstances?
8. Other than transparency criteria, are there ways that the
Commission could consider local planning criteria that utilities use in
determining how the prudence standard is applied to specific
expenditures? For example, with respect to local transmission and/or
asset management projects, should the Commission establish certain
guidance for planning such projects and only apply the rebuttable
presumption of prudence to projects that follow the Commission-
determined guidelines for planning such projects? What are the pros and
cons of that approach?
Federal and State Regulation of Transmission Facilities
9. Some panelists at the technical conference argued that there is
a regulatory gap with regard to ensuring that a cost-effective mix of
local, asset management, and regional reliability transmission projects
is developed. Generally speaking, for such projects they contend that
state siting processes, the formula rate process, and the Commission's
prudence standard and existing transparency requirements, may not
provide adequate assurance that utilities will choose a cost-effective
mix of projects. Do you agree that there is a regulatory gap for local
projects and/or asset management projects, and if so, why or why not?
Does the presence or extent of a regulatory gap depend on the
underlying state regulatory framework? If so, how? If you agree that
one or more regulatory gaps exist, how should the Commission address
these gaps? For example, should the Commission modify the prudence
standard and/or formula rate protocols for transmission or asset
management projects falling within such a regulatory gap? Should the
Commission establish new transmission planning requirements to help
ensure that such projects are cost-effective? In your response, please
discuss whether the Commission's approach should depend on the
underlying state regulatory framework. Also please discuss the extent
to which your recommended reforms, standing alone, will address the
perceived gaps, or whether they should or must be coupled with other
solutions.
10. Some panelists argued that certain types of projects do not
receive adequate state, regional, or federal scrutiny with regard to
project prudence/need. For example, the Commission has held that asset
management and end-of-life decisions are not subject to Order No. 890
planning requirements, and panelists highlighted that in some states
such projects do not require a certificate of public convenience and
necessity. Do you agree that some projects are not subject to adequate
review, and if so, why or why not? What particular types of projects do
not receive adequate scrutiny (if any), and should there be some form
of heightened scrutiny for them? If so, what kind of heightened
scrutiny would be appropriate, and how would that scrutiny be applied?
11. The Commission has authority over the justness and
reasonableness of the rates for wholesale transmission service,
including recovery of the costs of transmission facilities used in
providing transmission service and the prudence of those expenditures,
and has approved public utility transmission provider proposals to
recover their costs of providing transmission service through formula
rates. Under a formula rate, the Commission reviews and accepts as the
rate a formula for calculating the utility's cost of service, including
clear definitions of inputs to that formula and a process for updating
rates every year as the utility's costs change. State regulators
typically have authority to evaluate whether certain transmission
facilities to be built within their state may be constructed (i.e.,
whether to grant the proposed facility a Certificate of Public
Convenience and Necessity (CPCN)), which may involve evaluation of the
need for, and projected costs of, a proposed transmission facility.
a. Are there differences among the states' CPCN authorities and
processes, and what is the extent of those differences?
b. Should the Commission consider relying on a state regulator's
determination in a CPCN proceeding
[[Page 80537]]
that a proposed transmission facility is in the public convenience and
necessity when considering whether the costs of that transmission
facility may be recovered through a formula rate? Should the Commission
prohibit the recovery of transmission project costs through a formula
rate if those projects have not been subject to a robust state CPCN
process? Why or why not? Should the Commission accept as self-proving
an attestation from state regulators that such a robust CPCN process is
used in their state? If yes, are there specific factors or features of
a state regulator's CPCN process that indicate whether a potential
transmission facility has been robustly evaluated for need and cost? If
not, are there other indicators (e.g., other regulatory determinations,
third-party analyses, legislative reports, etc.) that demonstrate that
the need for and costs of a potential transmission facility have been
robustly reviewed? What are the advantages and disadvantages of this
approach?
c. If formula rate treatment is not permitted, how should costs
related to the new transmission project or transmission facility be
separated out for recovery in a stated rate proceeding (e.g., should
all costs related to the transmission facility be excluded from formula
rate recovery, or only capital costs)? How could the timing of the
state regulatory proceeding impact a public utility transmission
provider's ability to file for cost recovery of proposed transmission
facilities subject to CPCN review? How, if at all, would the inability
to recover the costs of certain transmission facilities through a
public utility transmission provider's formula rate impact its annual
formula rate proceedings?
d. If the Commission determines that a potential transmission
facility has not been robustly evaluated at the state level for need
and cost, are there other regulatory requirements that the Commission
could impose short of requiring a transmission facility's costs to be
recovered through stated rates rather than formula rates? If so, what
options are available and what are the pros and cons of those options?
Other Questions
12. Some panelists argued that the timing of cost management or
oversight mechanisms is relevant to ensuring cost effectiveness,
contending that cost scrutiny must be applied to decisions during the
local or regional transmission planning phase in order to influence
those decisions. Do you agree, and if so why or why not? What are the
possibilities for facilitating timely cost management before money is
spent on transmission projects (aside from planning costs)?
[FR Doc. 2022-28454 Filed 12-29-22; 8:45 am]
BILLING CODE 6717-01-P
