Document ID: FERC-2022-1549-0001
Agency: ferc
Document Type: Notice
Title: Meetings: Staff-Led Workshop; Establishing Interregional Transfer Capability Transmission Planning and Cost Allocation Requirements
Posted Date: 2022-12-06T05:00Z

[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:

------------------------------------------------------------------------
                                                     Docket Nos.
------------------------------------------------------------------------
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.
------------------------------------------------------------------------

    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