Staff-Led Workshop on Establishing Interregional Transfer Capability Transmission Planning and Cost Allocation Requirements

Docket No. AD23-3-000

Day 1| Establishing Interregional Transfer Capability Transmission Planning & Cost Allocation Requirements

Date and time:
12:00 p.m. to 5:00 p.m. ET
Monday, December 5, and Tuesday, December 6, 2022

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 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:

Invenergy Transmission LLC	Docket No.	AD22-13-000
Invenergy Transmission LLC v. Midcontinent Independent System Operator, Inc.	Docket No.	EL22-83-000
SOO Green HVDC Link ProjectCo, LLC v. PJM Interconnection, LLC	Docket Nos.	EL21-85-000 EL21-103-000
PPL Electric Utilities Corporation, PJM Interconnection, L.L.C.		ER22-2690-000 ER22-2690-001
Appalachian Power Company, PJM Interconnection, L.L.C.		ER19-2105-005
Neptune Regional Transmission System, LLC and Long Island Power Authority v. PJM Interconnection, L.L.C.	Docket No.	EL21-39-000
WestConnect Public Utilities	Docket No.	ER22-1105-000
PPL Electric Utilities Corporation	Docket No.	ER22-1606-000
Southwest Power Pool, Inc.	Docket No.	ER22-1846-000

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 customer@ferc.gov if you have any questions.

Commission workshops are accessible under section 508 of the Rehabilitation Act of 1973. For accessibility accommodations, please send an e-mail to accessibility@ferc.gov, 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 jessica.cockrell@ferc.gov or (202) 502-8190. For information related to logistics, please contact Sarah McKinley at sarah.mckinley@ferc.gov or (202) 502-8368.

Post-Workshop Comments

All interested persons are invited to file post-workshop comments on issues raised during the workshop that they believe would benefit from further discussion. In addition to addressing the questions listed in the Supplemental Notice,[1] parties are also invited to provide comments on the questions listed below. Commenters need not respond to all topics or questions asked.

Commenters may reference material previously filed in this docket, including the workshop 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 75 days from the date of this notice and reply comments are due 120 days from the date of this notice.

Comments may be filed electronically via the Internet.[2] Instructions are available on the Commission’s website http://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:

Jessica Cockrell (Technical Information)
Office of Energy Policy and Innovation
(202) 502-8190
Jessica.Cockrell@ferc.gov

Moon Athwal (Legal Information)
Office of the General Counsel
(202) 502-6272
Moon.Athwal@ferc.gov

Post-Workshop Questions for Comment

For purposes of this discussion, we continue to use the following terms as defined in the Supplemental Notices:[1]

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 C.F.R. § 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.
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).

Valuing Interregional Transfer Capability

To what extent can Interregional Transfer Capability mitigate risks that may occur across a wide geographic area (e.g., the shedding of load, correlated generation outages, or transmission outages due to the same extreme weather event, fuel disruptions, cyber-attacks, or physical security events)?
1. Could evaluating how Interregional Transfer Capability can mitigate such risks serve as a useful framework for determining whether, and at what minimum amount, Interregional Transfer Capability is necessary to ensure reliability and just and reasonable rates? If so, how could this framework help to inform an analysis of the appropriate amount of Interregional Transfer Capability?
2. Would such a framework be useful in determining the benefits of a Transfer Transmission Facility as well?
During the workshop, participants identified several metrics that could be used to evaluate the need for and benefit of a minimum amount of Interregional Transfer Capability. Participants mentioned metrics including loss of load expectation, expected unserved energy, planning reserve margin, value of lost load, grid stress, First Contingency Incremental Transfer Capability,[2] and avoided transmission costs, among others.
1. What metrics should be used to evaluate the need for a minimum amount of Interregional Transfer Capability, and why?
2. What metrics should be used to evaluate the benefit of a minimum amount of Interregional Transfer Capability, and why?
3. Should a common set of these metrics be used consistently across transmission planning regions to evaluate the need for and benefits of a minimum amount of Interregional Transfer Capability? Why or why not? If so, which metrics should be included in that common set? Should the Commission be prescriptive in how public utility transmission providers in transmission planning regions define these metrics?
Several participants in the workshop indicated that existing regional transmission planning and interregional transmission coordination processes have not led to the development of a sufficient amount of Interregional Transfer Capability in many regions across the United States. For instance, some participants explained that existing processes consider only normal system conditions in their transmission modeling and benefit calculations and do not adequately consider infrequent, extreme events.
1. Please describe whether there are gaps in existing regional transmission planning and interregional transmission coordination processes that could result in potentially beneficial Transfer Transmission Facilities not being considered, which could lead to a lack of sufficient Interregional Transfer Capability in some transmission planning regions and the possibility of unjust and unreasonable rates.
1. If there is insufficient Interregional Transfer Capability between certain transmission planning regions, what additional actions should be taken by the Commission to increase Interregional Transfer Capability? What actions have already been taken by public utility transmission providers in transmission planning regions to increase Interregional Transfer Capability?

Developing an Interregional Transfer Capability Requirement

A requirement for a minimum amount of Interregional Transfer Capability would apply to public utility transmission providers. As you consider the following questions, please describe how developing a minimum Interregional Transfer Capability requirement may differ depending on whether it applies to a Regional Transmission Organization or Independent System Operator (RTO/ISO) or those public utility transmission providers in a non-RTO/ISO transmission planning region, as applicable.

What are the advantages and disadvantages of the following approaches to establishing a minimum amount of Interregional Transfer Capability, and determining who should identify that minimum amount? Could these different approaches be combined? If so, how? Do your responses change based on whether or not non-public utility transmission providers are considered in the development of an Interregional Transfer Capability requirement?
1. A set of principles developed by the Commission. These principles would inform the processes that public utility transmission providers would need to implement to determine what minimum amount of Interregional Transfer Capability is needed.
2. An economic analysis that compares the incremental benefits and costs of increasing Interregional Transfer Capability between transmission planning regions and determines the minimum amount of Interregional Transfer Capability based on the comparison of benefits and costs. This analysis could be conducted by public utility transmission providers in neighboring transmission planning regions, in two or more transmission planning regions within an interconnection, or in each interconnection.
3. A standardized minimum amount of Interregional Transfer Capability based on a single characteristic of the transmission planning region(s), like a percentage of peak load or the single largest contingency. Do your responses change based on whether or not non-public utility transmission providers are considered?
4. A standardized formula to determine a minimum Interregional Transfer Capability requirement based on identified characteristics of the transmission planning region(s), such as peak load, ramping needs, generation outages, and variability of generation and load. Do your responses change based on whether or not non-public utility transmission providers are considered?
5. A transmission planning study that assesses unconstrained power flows between transmission planning regions to optimize the economic and reliability benefits of Interregional Transfer Capability. This approach would determine the minimum amount of Interregional Transfer Capability based on the level of interregional power flows during normal and emergency conditions.
Some participants in the workshop recommended a transmission planning study to determine a minimum amount of Interregional Transfer Capability. What is the appropriate geographic scope of a transmission planning study for Interregional Transfer Capability?
1. What are the benefits and drawbacks of a transmission planning study between neighboring transmission planning regions to determine the minimum amount of Interregional Transfer Capability between those regions?
2. What are the benefits and drawbacks of an interconnection-wide study to determine the minimum amount of Interregional Transfer Capability for a transmission planning region with its neighboring transmission planning regions?
3. To what extent could existing interregional organizations (e.g., Eastern Interconnection Planning Collaborative and Western Electricity Coordinating Council) support an interconnection-wide transmission planning study for Interregional Transfer Capability?
4. What type of analysis should an Interregional Transfer Capability planning study include? For example, would a study consider the “single largest contingency” or “common mode failures”?
5. Should a transmission planning study for Interregional Transfer Capability require that neighboring transmission planning regions consider Transfer Transmission Facilities that would cross between the interconnections?
Ahead of developing a transmission planning study, as suggested in question 5, some workshop participants raised the idea of the Commission, or public utility transmission providers in each transmission planning region, establishing an easily quantifiable minimum Interregional Transfer Capability requirement (e.g., a region-specific default amount, based on criteria such as a percentage of peak load or the single largest contingency) that could later be revised up or down to reflect the region-specific transmission needs or the additional benefits of Interregional Transfer Capability after a more detailed interconnection-wide Interregional Transfer Capability study is completed.
1. How would the Commission, or public utility transmission providers within a transmission planning region, define region-specific default minimum Interregional Transfer Capability requirements, which could be revised after an interconnection-wide Interregional Transfer Capability study is completed?
2. What are important considerations for defining a metric, like those in question 2 above, used to evaluate the need for and benefits of region-specific default Interregional Transfer Capability requirements?
3. What are important considerations for an interconnection-wide Interregional Transfer Capability study for revising region-specific default Interregional Transfer Capability requirements?
  1. How would you measure and use the benefits of mitigating risk through Interregional Transfer Capability to revise up or down region-specific default Interregional Transfer Capability requirements?
  2. How would you use benefits in addition to reliability and resilience risk-mitigating benefits to revise up or down region-specific default Interregional Transfer Capability requirements?
  3. What region-specific transmission needs could be used to revise up or down region-specific default Interregional Transfer Capability requirements?
Should the need for Interregional Transfer Capability be considered within existing regional transmission planning and interregional transmission coordination processes or in a new, separate transmission planning process? Are there other ways to consider Interregional Transfer Capability given the existing processes already underway?
1. Could a metric be defined and used to capture the benefits of Interregional Transfer Capability in maintaining reliability during extreme events in existing regional transmission planning and interregional transmission coordination processes? Would the use of a such a metric in existing regional transmission planning and interregional transmission coordination processes sufficiently consider the benefits of Interregional Transfer Capability?
2. Should potential common mode failures and correlated outages be incorporated into studies for identifying Transfer Transmission Facilities in an Interregional Transfer Capability transmission planning process? If so, how?
To what extent, if any, should the following be considered when establishing a minimum Interregional Transfer Capability requirement; if so, how and why?
1. Historical or projected extreme events (e.g., extreme weather, loss of fuel supply, etc.).
2. Load and resource diversity across a wide geographic area.
3. Anticipated changes in the resource mix and demand.
4. Improved reliability.
5. Avoided production costs.
6. Geographic zones with the potential for large amounts of new generation.
7. The option value of Transfer Transmission Facilities, as determined by the increased access to supplemental capacity during emergency operating conditions.
8. Increased operator flexibility.
9. Impact of correlated generator outages and common mode failures.
10. Power system stability.
11. Other factors?

Weather Data

In the context of establishing an Interregional Transfer Capability requirement, what challenges exist to modeling the impact of extreme weather events on generation, load, and transmission system performance in forward-looking transmission planning studies? What data, tools, and information sharing can help to mitigate these challenges?
To what extent do transmission planners rely on normalized weather data in transmission planning models? Are there drawbacks to using normalized weather data in determining the need for and benefits of Interregional Transfer Capability?
In determining an Interregional Transfer Capability requirement, should public utility transmission providers use data on generation, load, and transmission system performance during past extreme weather events and other hours of reported transmission system stress (i.e., during normal conditions) in forward-looking transmission planning studies? Is such data sufficient to capture the possible impacts of future extreme weather events? Why or why not?

Cost Allocation

Should the Commission require an ex ante cost allocation method, an ex post cost allocation method, or some combination for Transfer Transmission Facilities? What are the advantages or disadvantages of each approach? If an ex ante cost allocation method, are there factors that would make changing the ex ante cost allocation method appropriate? If so, what are those factors?
How would one design an ex ante cost allocation method for Transfer Transmission Facilities that relies on identified benefits? Which benefits should be considered when determining how to allocate the costs of Transfer Transmission Facilities in a manner that is at least roughly commensurate with the benefits and why?
Should the Commission establish a defined set of benefits for Transfer Transmission Facilities or require the public utility transmission providers in a pair (or more) of neighboring transmission planning regions to determine the set of benefits considered for purposes of cost allocation? What are the advantages and disadvantages of each approach?
How should a single cost allocation method be determined for Transfer Transmission Facilities? Should the relevant public utility transmission providers be tasked with jointly proposing a cost allocation method for Transfer Transmission Facilities in the first instance? 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 cannot agree on one?
What role, if any, could merchant transmission facilities play in meeting a minimum Interregional Transfer Capability requirement?

Operations

Are existing market-to-market operational protocols and congestion management tools sufficient to manage flows across Transfer Transmission Facilities effectively during extreme events? Are there modifications to the Transmission Loading Relief process that would more effectively manage congestion across seams between regions than the current Transmission Loading Relief process?

[1] Supplemental Notices, supra note 1.

[2] NERC Transmission Transfer Capability, reference document (May 1995), available at https://www.nerc.com/pa/Stand/MOD%20V0%20Revision%20RF%20DL/atctdt-1105cca.pdf.

[1] Supplemental Notice of Staff-Led Workshop, Docket No. AD23-3-000 (Nov. 30, 2022); see also Errata Notice, Docket No. AD23-3-000 (Dec. 2, 2022) (Supplemental Notices).

[2] See 18 C.F.R. § 385.2001(a)(1)(iii) (2021).

Day One Agenda and Speakers: Monday, December 5, 2022

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 C.F.R. § 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).

Time	Details
12:00 pm – 12:10 pm	Welcome and Opening Remarks
12:10 pm – 12:25 pm	Presentation from Dr. Dev Millstein, Research Scientist, Lawrence Berkeley National Lab, Empirical Estimates of Transmission Value using Locational Marginal Prices
12:25 pm – 2:25 pm	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 will discuss the specific drivers that may necessitate the establishment of a minimum requirement. This panel may include a discussion of the following topics: 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? 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? 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? 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? 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 \| Presentation Liza Reed, PhD, Research Manager, Electricity Transmission, Niskanen Center \| Presentation Christina Hayes, Executive Director, Americans for a Clean Energy Grid 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 \| Presentation
2:25 pm – 2:45 pm	Break
2:45 pm – 3:00 pm	Presentation from Dr. Adria Brooks, U.S. Department of Energy Grid Deployment Office, Transmission Division \| Supplement
3:00 pm – 4:55 pm	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: 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.)? To what extent, if any, should the following be considered when establishing a minimum Interregional Transfer Capability requirement? Historical or projected extreme events (e.g., extreme weather, loss of fuel supply, etc.) Load and resource diversity across a wide geographic area Anticipated changes in the resource mix and demand Improved reliability Avoided production costs Geographic zones with the potential for large amounts of new generation The option value of Transfer Transmission Facilities, as determined by the increased access to supplemental capacity during emergency operating conditions. Increased operator flexibility Others? Should planning criteria other than reliability and resilience be considered in establishing a minimum Interregional Transfer Capability requirement? 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. 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? 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? Should the principles considered be consistent for (a), (b) or (c) above? What are the advantages and disadvantages of each approach? 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? 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? 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, PhD, Associate Director, Energy System Integration Group Aaron Bloom, Executive Director, NextEra Energy Transmission, LLC \| Presentation Laura Rauch, Senior Director, Transmission Planning, Midcontinent Independent System Operator, Inc. \| Presentation 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 pm – 5:00 pm	Closing Remarks

Day Two Agenda and Speakers: Tuesday, December 6, 2022

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 C.F.R. § 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).

Time	Details
12:00 pm – 12:10 pm	Welcome and Opening Remarks
12:10 pm – 2:15 pm	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: 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? 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? 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? 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? 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. 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. 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? What operational barriers preclude potential Interregional Transfer Capability from being realized during normal and emergency system conditions? Panelists Sheila Manz, PhD, Technical Director, Decarbonization Planning, GE Energy Consulting \| Presentation Digaunto Chatterjee, Vice President, System Planning, Eversource Energy \| Presentation David Souder, Executive Director, System Planning, PJM Interconnection, L.L.C. and Vice Chair, Eastern Interconnection Planning Collaborative Technical Committee \| Presentation Michael Goggin, Vice President, Grid Strategies, LLC, speaking on behalf of the American Clean Power Association \| Opening Statement \| Presentation Nicolas Koehler, Director, Transmission Planning, American Electric Power Company Christopher Clack, PhD, Chief Executive Officer, Vibrant Clean Energy, LLC \| Presentation
2:15 pm – 2:30 pm	Break
2:30 pm – 4:45 pm	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: 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? 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)? How would public utility transmission providers in a transmission planning region demonstrate that they have met the minimum Interregional Transfer Capability requirement? 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? 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)? 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? 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? Should the Commission prescribe a standard, or principles to govern the selection of Transfer Transmission Facilities for purposes of cost allocation? 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? What rules, if any, should the Commission promulgate with regard to establishing a cost allocation method for Transfer Transmission Facilities? 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? 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? 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? 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? 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. \| Presentation Shashank Sane, Executive Vice President, Transmission, Invenergy \| Presentation Rob Gramlich, Founder and President, Grid Strategies, LLC \| Statement \| Presentation-1 \| Presentation-2 \| Presentation-3 Andrew French, Commissioner, Kansas Corporation Commission J. Arnold Quinn, Chief Economist, Vistra Corp.
4:45pm – 5:00pm	Closing Remarks

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Date and Time

Monday, Dec 5, 2022 , 12:00 pm - Tuesday, Dec 6, 2022 , 5:00 pm EST
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Virtual

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Staff-Led Workshop on Establishing Interregional Transfer Capability Transmission Planning and Cost Allocation Requirements

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