[Federal Register Volume 87, Number 233 (Tuesday, December 6, 2022)]
[Notices]
[Pages 74612-74616]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2022-26474]
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DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
[Docket No. AD23-3-000]
Establishing Interregional Transfer Capability Transmission
Planning and Cost Allocation Requirements; Supplemental Notice of
Staff-Led Workshop
As announced in the Notice of Staff-Led Workshop issued in this
proceeding on October 6, 2022, Federal Energy Regulatory Commission
(Commission) staff will convene a workshop to discuss whether and how
the Commission could establish a minimum requirement for Interregional
Transfer Capability for public utility transmission providers in
transmission planning and cost allocation processes on December 5 and
6, 2022, from approximately 12:00 p.m. to 5:00 p.m. Eastern Time.
The purpose of this workshop is to consider the question of whether
and how to establish a minimum requirement for Interregional Transfer
[[Page 74613]]
Capability. Topics for discussion may include: how to determine the
need for and benefit of setting a minimum requirement for Interregional
Transfer Capability; what to consider in establishing a potential
Interregional Transfer Capability requirement, including who would be
responsible for determining a minimum Interregional Transfer Capability
requirement and what would be the objective and drivers of such a
requirement; what process could be used in establishing a minimum
Interregional Transfer Capability requirement to determine key data
inputs, modeling techniques, and relevant metrics; and how costs for
transmission facilities intended to increase Interregional Transfer
Capability should be allocated and how to ensure a minimum amount of
Interregional Transfer Capability is achieved and maintained.
While the workshop is not for the purpose of discussing any
specific matters before the Commission, some workshop discussions may
involve issues raised in proceedings that are currently pending before
the Commission. These proceedings include, but are not limited to:
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Docket Nos.
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Invenergy Transmission LLC................. AD22-13-000.
Invenergy Transmission LLC v. Midcontinent EL22-83-000.
Independent System Operator, Inc.
SOO Green HVDC Link ProjectCo, LLC v. PJM EL21-85-000, EL21-103-000.
Interconnection, LLC.
PPL Electric Utilities Corporation, PJM ER22-2690-000, ER22-2690-
Interconnection, L.L.C. 001.
Appalachian Power Company, PJM ER19-2105-005.
Interconnection, L.L.C.
Neptune Regional Transmission System, LLC EL21-39-000.
and Long Island Power Authority v. PJM
Interconnection, L.L.C.
WestConnect Public Utilities............... ER22-1105-000.
PPL Electric Utilities Corporation......... ER22-1606-000.
Southwest Power Pool, Inc.................. ER22-1846-000.
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Attached to this Supplemental Notice is an agenda for the workshop,
which includes the workshop program and expected panelists.
Panelists are asked to submit advance materials to provide any
information related to their respective panel (e.g., summary
statements, reports, whitepapers, studies, or testimonies) that
panelists believe should be included in the record of this proceeding
by November 21, 2022. Panelists should file all advance materials in
the AD23-3-000 docket.
The workshop will take place virtually, with remote participation
from both presenters and attendees. The workshop will be open to the
public and there is no fee for attendance. Information will also be
posted on the Calendar of Events on the Commission's website,
www.ferc.gov, prior to the event.
The workshop will be transcribed and webcast. Transcripts will be
available for a fee from Ace Reporting (202-347-3700). A free webcast
of this event is available through the Commission's website. Anyone
with internet access who desires to view this event can do so by
navigating to www.ferc.gov's Calendar of Events and locating this event
in the Calendar. The Federal Energy Regulatory Commission provides
technical support for the free webcasts. Please call (202) 502-8680 or
email [email protected] if you have any questions.
Commission workshops are accessible under section 508 of the
Rehabilitation Act of 1973. For accessibility accommodations, please
send an email to [email protected], call toll-free (866) 208-3372
(voice) or (202) 208-8659 (TTY), or send a fax to (202) 208-2106 with
the required accommodations.
For more information about this workshop, please contact Jessica
Cockrell at [email protected] or (202) 502-8190. For
information related to logistics, please contact Sarah McKinley at
[email protected] or (202) 502-8368.
Dated: November 30, 2022.
Kimberly D. Bose,
Secretary.
Staff-Led Workshop Establishing Interregional Transfer Capability
Transmission Planning and Cost Allocation Requirements, Docket No.
AD23-3-000, December 5-6, 2022
Agenda and Speakers
Background
To aid in our discussion at the workshop, we will use the following
terms:
For this discussion, the definition of Interregional
Transfer Capability is consistent with total transfer capability as
defined in the Commission's regulations: ``the amount of electric power
that can be moved or transferred reliably from one area to another area
of the interconnected transmission systems by way of all transmission
lines (or paths) between those areas under specified system conditions,
or such definition as contained in Commission-approved Reliability
Standards.'' 18 CFR 37.6(b)(1)(vi) (2021). In the context of
Interregional Transfer Capability, an ``area'' in the above definition
would be a transmission planning region composed of public utility
transmission providers.
For this discussion, Transfer Transmission Facility is
defined as a transmission facility that increases the amount of
electric power that can be moved or transferred reliably from one
transmission planning region to another by way of all transmission
lines (or paths) between those transmission planning regions. For
purposes of geographic location, a Transfer Transmission Facility may
be located entirely within a single transmission planning region (i.e.,
either a local transmission facility or a regional transmission
facility), or it may span two or more transmission planning regions
(i.e., an interregional transmission facility).
Day One: Monday, December 5, 2022
12:00 p.m.-12:10 p.m.: Welcome and Opening Remarks
12:10 p.m.-12:25 p.m.: Presentation from Dr. Dev Millstein, Research
Scientist, Lawrence Berkeley National Lab, Empirical Estimates of
Transmission Value using Locational Marginal Prices
12:25 p.m.-2:25 p.m.: Panel 1: Determining the Need for Additional
Interregional Transfer Capability
This panel will explore whether the existing transmission planning
and cost allocation and the interregional coordination and cost
allocation processes adequately consider the need to establish a
minimum requirement for Interregional Transfer Capability between
neighboring transmission planning regions. In addition, the panel
[[Page 74614]]
will discuss the specific drivers that may necessitate the
establishment of a minimum requirement.
This panel may include a discussion of the following topics:
1. What are the current levels of Interregional Transfer Capability
between transmission planning regions? Is more Interregional Transfer
Capability between transmission planning regions needed? Why or why
not?
2. Is the potential need for additional Interregional Transfer
Capability currently considered in any transmission planning processes
and if so, how? To the extent such needs are considered, have they
resulted in the development of any transmission facilities?
3. What are the drivers of the need for increasing Interregional
Transfer Capability? To what extent do these vary based on regional and
system characteristics (e.g., weather patterns, load diversity,
resource mix, etc.)? Are there barriers to identifying or assessing
these drivers?
4. Is a minimum amount of Interregional Transfer Capability between
transmission planning regions necessary to ensure just and reasonable
Commission-jurisdictional rates? If so, what evidence is there to
support, or negate, that position? How will planning for a minimum
amount of Interregional Transfer Capability produce just and reasonable
rates?
5. Does the potential need for a minimum amount of Interregional
Transfer Capability differ between RTO and non-RTO regions? Why or why
not? Is a minimum amount of Interregional Transfer Capability necessary
for non-RTO regions?
Panelists
Neil Millar, Vice President, Infrastructure and Operations
Planning, California Independent System Operator Corporation
Liza Reed, Ph.D., Research Manager, Electricity Transmission,
Niskanen Center
Michele Kito, Supervisor, Electric Market Design Section,
California Public Utilities Commission
Philip D. Moeller, Executive Vice President, Edison Electric
Institute
Tricia Pridemore, Chairman, Georgia Public Service Commission
Simon Mahan, Executive Director, Southern Renewable Energy
Association
2:25 p.m.-2:45 p.m.: Break
2:45 p.m.-3:00 p.m.: Presentation from Dr. Adria Brooks, U.S.
Department of Energy Grid Deployment Office, Transmission Division
3:00 p.m.-4:55 p.m.: Panel 2: Considerations for Establishing Potential
Interregional Transfer Capability Requirements
This panel will discuss who would be responsible for determining a
minimum Interregional Transfer Capability requirement and the relevant
considerations for establishing such a requirement, assuming that there
is such a need. Specifically, this panel will focus on identifying the
objective, and drivers, of a minimum Interregional Transfer Capability
requirement. This panel may include a discussion of the following
topics:
1. What principles should be used to establish a minimum amount of
Interregional Transfer Capability (e.g., should a minimum Interregional
Transfer Capability requirement be determined based on the cost impact
to transmission customers during extreme events, such as extreme
weather, wide-spread loss of fuel supply, etc.)?
2. To what extent, if any, should the following be considered when
establishing a minimum Interregional Transfer Capability requirement?
a. Historical or projected extreme events (e.g., extreme weather,
loss of fuel supply, etc.)
b. Load and resource diversity across a wide geographic area
c. Anticipated changes in the resource mix and demand
d. Improved reliability
e. Avoided production costs
f. Geographic zones with the potential for large amounts of new
generation
g. The option value of Transfer Transmission Facilities, as
determined by the increased access to supplemental capacity during
emergency operating conditions.
h. Increased operator flexibility
i. Others?
3. Should planning criteria other than reliability and resilience
be considered in establishing a minimum Interregional Transfer
Capability requirement?
4. For this question, please consider: (a) public utility
transmission providers in each pair of neighboring transmission
planning regions, (b) the public utility transmission providers in all
of a transmission planning region's neighboring transmission planning
regions, and (c) all public utility transmission providers within an
Interconnection.
a. What role should the Commission, relevant groupings of public
utility transmission providers described in (a), (b), and (c) above, or
other relevant entities play in determining what, if any, minimum
amount of Interregional Transfer Capability is needed? What are the
advantages and disadvantages of each approach?
b. Should the Commission establish a specific formula or planning
process, or instead more general criteria, guidelines, or principles
for public utility transmission providers to follow in establishing a
minimum Interregional Transfer Capability? Should the Commission allow
public utility transmission providers flexibility in whether to work on
a bilateral basis with neighboring regions, or require planning to be
carried out across a broader geography? What are the advantages and
disadvantages of each approach?
c. Should the principles considered be consistent for (a), (b) or
(c) above? What are the advantages and disadvantages of each approach?
5. How should merchant transmission facility developers and public
utility transmission providers conducting transmission planning avoid
planning duplicative or conflicting transmission facilities to increase
Interregional Transfer Capability?
6. To what extent, if at all, would a minimum Interregional
Transfer Capability requirement complement or conflict with a potential
new or modified NERC Reliability Standard that requires consideration
of extreme heat and cold events as proposed in Docket No. RM22-10?
7. Should the establishment of a minimum amount of Interregional
Transfer Capability for non-RTO regions differ from that for RTO
regions? If so, how?
Panelists
Debra Lew, Ph.D., Associate Director, Energy System
Integration Group
Aaron Bloom, Executive Director, NextEra Energy Transmission,
LLC
Laura Rauch, Senior Director, Transmission Planning,
Midcontinent Independent System Operator, Inc.
David Kelley, Director of Seams and Tariff Services, Southwest
Power Pool, Inc.
Saad Malik, Director Reliability Planning, Western Electricity
Coordinating Council
Deral Danis, Senior Director, Transmission, Pattern Energy
Group LP
Sharon Segner, Senior Vice President of Transmission Policy,
LS Power Development, LLC
4:55 p.m.-5:00 p.m.: Closing Remarks
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Day Two: Tuesday, December 6, 2022
12:00 p.m.-12:10 p.m.: Welcome and Opening Remarks
[[Page 74615]]
12:10 p.m.-2:15 p.m.: Panel 3: Process for Establishing Potential
Interregional Transfer Capability Requirements
This panel will discuss the process for determining a minimum
amount of Interregional Transfer Capability including, but not limited
to, the determination of key data inputs, modeling techniques, and
relevant metrics.
This panel may include a discussion of the following topics:
1. What process should be used to determine a minimum amount of
Interregional Transfer Capability? For example, should the minimum be
(a) derived heuristically from past extreme events; (b) derived using a
probabilistic approach; or (c) based on scenario planning similar to
the requirements proposed for Long-Term Regional Transmission Planning
(Docket No. RM21-17-000) or other deterministic analysis? What are the
advantages and disadvantages of each approach?
a. With respect to a probabilistic approach, what are the primary
challenges in developing probabilistic models to determine a minimum
amount of Interregional Transfer Capability? Do current probabilistic
methods model common mode outages appropriately? If not, to what extent
does that reduce the usefulness of a probabilistic approach?
b. With respect to scenario planning to determine a minimum amount
of Interregional Transfer Capability, what guidelines, if any, are
necessary to ensure that such scenario planning adequately assesses the
need for, and value of, increased Interregional Transfer Capability?
Are certain types of scenarios particularly important to assess the
need for, and value of, Interregional Transfer Capability? Should
scenario planning account for wide-area events and correlated outages,
and if so, how?
2. After a need for a minimum amount of Interregional Transfer
Capability is determined, what models and data are necessary to
evaluate it? Do public utility transmission providers typically have
access to or collect these models and data? If not, how should public
utility transmission providers acquire these models and data? To
simulate the wide-area impact of extreme events, to what extent should
these models and data represent the overall interconnection?
3. What criteria should be used to assess whether public utility
transmission providers have sufficient existing transmission facilities
to meet or surpass an Interregional Transfer Capability requirement?
Please specify whether your answer to this question depends on your
answer to question 1 in this panel.
a. Is there a benefit to using a specific metric of Interregional
Transfer Capability? Potential metrics may include a set amount of
electric power, an amount of electric power relative to some electric
power characteristic of the transmission planning region (like peak
load, or the largest single contingency), among others.
b. To what extent should public utility transmission providers in a
transmission planning region consider criteria that would help ensure
the ``right amount'' of Interregional Transfer Capability is identified
and sufficient Transfer Transmission Facilities are selected to meet an
Interregional Transfer Capability requirement? For example, should the
criteria used to assess whether public utility transmission providers
meet an Interregional Transfer Capability requirement be informed by
the net-benefits, or other types of measures, of Transfer Transmission
Facilities?
4. What operational barriers preclude potential Interregional
Transfer Capability from being realized during normal and emergency
system conditions?
Panelists
Sheila Manz, Ph.D., Technical Director, Decarbonization
Planning, GE Energy Consulting
Digaunto Chatterjee, Vice President, System Planning,
Eversource Energy
David Souder, Executive Director, System Planning, PJM
Interconnection, L.L.C. and Vice Chair, Eastern Interconnection
Planning Collaborative Technical Committee
Michael Goggin, Vice President, Grid Strategies, LLC, speaking
on behalf of the American Clean Power Association
Nicolas Koehler, Director, Transmission Planning, American
Electric Power Company
Christopher Clack, Ph.D., Chief Executive Officer, Vibrant
Clean Energy, LLC
2:15 p.m.-2:30 p.m.: Break
2:30 p.m.-4:45 p.m.: Panel 4: Meeting the Goal of Increased
Interregional Transfer Capability
This panel will discuss how costs for Transfer Transmission
Facilities should be allocated and how to ensure a minimum amount of
Interregional Transfer Capability is achieved and maintained.
This panel may include a discussion of the following topics:
1. How should cost allocation for Transfer Transmission Facilities
be determined? For example, should public utility transmission
providers in a transmission planning region be required to allocate the
costs of Transfer Transmission Facilities: (1) within their own
transmission planning region; (2) jointly with two or more neighboring
transmission planning regions; (3) at an Interconnection-wide level; or
(4) via some other process? What are the advantages or disadvantages of
each approach? Should there be a process in place for the Commission to
establish a cost allocation method for Transfer Transmission Facilities
if the public utility transmission providers in (1), (2), or (3) above
cannot agree?
a. How should the process for evaluating, selecting, and allocating
the costs of Transfer Transmission Facilities align with current
regional transmission planning and interregional transmission
coordination processes (e.g., should the process be a part of existing
transmission planning and cost allocation and/or coordination and cost
allocation processes or should it be a separate process)?
2. How would public utility transmission providers in a
transmission planning region demonstrate that they have met the minimum
Interregional Transfer Capability requirement?
3. What process would public utility transmission providers in (a)
a transmission planning region, (b) a pair of transmission planning
regions, or (c) a broader collection of neighboring planning regions
use to identify and select Transfer Transmission Facilities?
4. Should the Commission reexamine the minimum Interregional
Transfer Capability requirement or the required process to identify and
select Transfer Transmission Facilities at some point in the future
(e.g., in 10 years)?
5. What, if any, categories of benefits should public utility
transmission providers be required to consider when evaluating Transfer
Transmission Facilities for selection for purposes of cost allocation?
a. Should the benefits considered be consistent between (a) public
utility transmission providers in each pair of neighboring transmission
planning regions, (b) the public utility transmission providers in all
of a transmission planning region's neighboring transmission planning
regions, or (c) all public utility transmission providers within an
Interconnection? What are the advantages and disadvantages of each
approach?
[[Page 74616]]
6. Should the Commission prescribe a standard, or principles to
govern the selection of Transfer Transmission Facilities for purposes
of cost allocation?
7. Should the Commission require public utility transmission
providers to use a portfolio approach for selecting Transfer
Transmission Facilities to meet a minimum amount of Interregional
Transfer Capability?
8. What rules, if any, should the Commission promulgate with regard
to establishing a cost allocation method for Transfer Transmission
Facilities?
a. What are the advantages and disadvantages of the Commission
requiring a specific ex ante regional and/or interregional cost
allocation method for Transfer Transmission Facilities?
b. What are the advantages and disadvantages of the Commission
requiring a specific ex post regional and/or interregional cost
allocation method or a hybrid (i.e., part ex ante and part ex post) for
Transfer Transmission Facilities?
c. Should the Commission decline to prescribe an ex ante or ex post
cost allocation method for applicable public utility transmission
providers, what process should govern the establishment of cost
allocation rules for any particular Transfer Transmission Facility?
9. What role should state and local governmental entities play in
the public utility transmission provider process for selection and cost
allocation for Transfer Transmission Facilities? Should the states'
role in selection and cost allocation be determined by the drivers of
the need for a minimum requirement for Transfer Transmission
Facilities? For example, if the Transfer Transmission Facilities are
planned to serve public policy goals, such as renewable generation
deployment, should the states have a role in cost allocation, such as
that proposed in the Notice of Proposed Rulemaking in RM21-17?
10. Are there barriers to the ability of interregional merchant
transmission facilities in providing a minimum amount of Interregional
Transfer Capability? For example, do contractual or tariff limitations
prevent merchant interregional high-voltage direct current transmission
facilities from supporting reliability during extreme events?
Panelists
Kris Zadlo, Chief Development Officer, Grid United
Travis Kavulla, Vice President Regulatory Affairs, NRG Energy,
Inc.
Shashank Sane, Executive Vice President, Transmission,
Invenergy
Rob Gramlich, Founder and President, Grid Strategies, LLC
Andrew French, Commissioner, Kansas Corporation Commission
J. Arnold Quinn, Chief Economist, Vistra Corp.
4:45 p.m.-5:00 p.m.: Closing Remarks
[FR Doc. 2022-26474 Filed 12-5-22; 8:45 am]
BILLING CODE 6717-01-P