Document ID: FERC-2022-1667-0001
Agency: ferc
Document Type: Notice
Title: Meetings: Transmission Planning and Cost Management, Joint Federal-State Task Force on Electric Transmission; Post-Technical Conference Comments
Posted Date: 2022-12-30T05:00Z

[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.
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    \1\ Supplemental Notice of Technical Conference, Docket No. 
AD22-8-000 (Oct. 4, 2022).
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    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 http://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.
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    \2\ See 18 CFR 385.2001(a)(1)(iii) (2021).
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    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
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    \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).
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    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\
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    \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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    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\
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    \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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    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.
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    \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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    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-

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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?

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.
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    \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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    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\
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    \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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    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

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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